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As filed pursuant to Rule 424(b)3
Registration No. 333-10318

PROSPECTUS

GRAPHIC   Offer to Exchange
    

5.15% Notes due 2012
which have been registered under the Securities Act of 1933
for all outstanding 5.15% Notes due 2012
($200,000,000 aggregate principal amount outstanding)


of


EQUITABLE RESOURCES, INC.

        In making your investment decision, you should rely only on the information contained or incorporated by reference in this prospectus. This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. This prospectus incorporates important business and financial information about us that is not included in this prospectus. You may obtain a copy of this information, without charge, as described in the "Where You Can Find More Information" section. In order to obtain timely delivery, please provide us with at least five business days' notice. To ensure the timely delivery of any requested information with regard to this exchange offer, we must receive your request for information no later than April 11, 2003. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations, and prospects may have changed since that date. Neither the delivery of this prospectus nor any sale made hereunder shall under any circumstances imply that the information herein is correct as of any date subsequent to the date on the cover of this prospectus.

        In this prospectus, "we," "us," "our," "Equitable," and the "Company" refer collectively to Equitable Resources, Inc. and its consolidated subsidiaries unless otherwise specified.


TABLE OF CONTENTS

 
   Page
Forward-Looking Statements   ii
Where You Can Find More Information   iii
Incorporation of Certain Documents by Reference   iv
Prospectus Summary   1
Risk Factors   7
Ratio of Earnings to Fixed Charges   13
The Exchange Offer   14
Use of Proceeds   22
Capitalization   23
Summary Selected Historical Consolidated Financial Data   24
Management's Discussion and Analysis of Financial Condition and Results of Operations   26
Business   52
Management   59
Description of Other Indebtedness   62
Description of Exchange Notes   63
Certain U.S. Federal Income Tax Considerations   77
Plan of Distribution   78
Legal Matters   79
Experts   79

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FORWARD-LOOKING STATEMENTS

        This prospectus and the documents incorporated by reference contain certain statements that are, or may be considered to be, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include, among other things, statements regarding our expectations of future plans, our objectives, our anticipated cost savings, our growth and anticipated financial and operational performance, the effect of the application of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," the effect of recording Appalachian Basin Partners' sales as equity production sales instead of as monetized sales, the effect of changes in natural gas prices on our earnings per share, our expected repayment schedule of our debt and other obligations, the anticipated fees for operating, gathering and marketing gas, our anticipated capital expenditures and commitments, anticipated changes in our NORESCO backlog, anticipated sales of NORESCO contracts, and our expected drilling program. 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, our forward-looking statements do not reflect the impact of any possible acquisitions, divestitures or restructurings. 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. These events, risks, and uncertainties include, among other things, those matters discussed under the caption "Risk Factors," as well as the following:

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        The factors discussed under the heading "Risk Factors" and elsewhere in this prospectus are not necessarily all of the important factors that could cause our results to differ materially from expected results. Other factors could cause actual results to vary materially from expected results. Forward-looking statements speak only as of the dates they were made and we undertake no obligation to update them, whether as a result of new information, future events or otherwise. You are advised to consult any additional disclosures we may make in our reports filed with the Securities and Exchange Commission ("SEC").


WHERE YOU CAN FIND MORE INFORMATION

        We file annual, quarterly, and current reports, proxy statements, and other information with the SEC. You can inspect and copy these reports, proxy statements, and other information at the public reference facilities of the SEC, in Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room. The SEC also maintains a web site that contains reports, proxy statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. You can inspect reports and other information we file at the office of The New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

        We will provide you, without charge, a copy of the notes, the indenture governing the notes, the related registration rights agreement, and other material agreements that we summarize in this prospectus. You may request copies of these documents by contacting us at:

Equitable Resources, Inc.
One Oxford Centre, Suite 3300
301 Grant Street
Pittsburgh, Pennsylvania 15219
Attention: Johanna G. O'Loughlin, Esq.
Senior Vice President, General Counsel, and Corporate Secretary
Telephone: 412-553-5700

iii


INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

        We are incorporating by reference in this prospectus the documents we file with the SEC. This means that we are disclosing important information to you by referring to those documents. The information incorporated by reference is an important part of this prospectus, and information that we file later with the SEC will automatically update and supersede the information contained in this prospectus. We incorporate by reference the following documents:

        Any statement contained in a document incorporated by reference, or deemed to be incorporated by reference, in this prospectus shall be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in any other subsequently filed document which also is incorporated by reference in this prospectus modifies or supersedes such statement. Any such statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this prospectus.

        As used in this prospectus, the term "prospectus" means this prospectus, including the documents incorporated by reference, as the same may be amended, supplemented or otherwise modified from time to time. Statements contained in this prospectus as to the contents of any contract or other document referred to in this prospectus do not purport to be complete, and where reference is made to the particular provisions of such contract or other document, such provisions are qualified in all respects by reference to all of the provisions of such contract or other document. We will provide without charge to each person to whom a copy of this prospectus has been delivered, on the written or oral request of such person, a copy of any or all of the documents which have been or may be incorporated in this prospectus by reference (other than exhibits to such documents unless such exhibits are specifically incorporated by reference in any such documents) and a copy of any or all other contracts or documents which are referred to in this prospectus. You may request a copy of these filings at the address and telephone number set forth above.

iv


PROSPECTUS SUMMARY

        This summary may not contain all of the information that may be important to you. You should read the entire prospectus, including, the matters set forth under "Risk Factors" and the financial data and related notes included in this prospectus and incorporated by reference in this prospectus, before making an investment decision.


About Equitable Resources, Inc.

        We are an integrated energy company. We focus on Appalachian area natural gas production and gathering, natural gas distribution and transmission, and the development of energy infrastructure and efficiency solutions for our customers primarily in the northeastern section of the United States. We also have a minority interest in Westport Resources, Inc. ("Westport"), a public company with oil and gas exploration and production properties in the Gulf of Mexico and Rocky Mountain areas. Together with our subsidiaries, we 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 Supply, and NORESCO.

Equitable Utilities

        Equitable Utilities' regulated operations are comprised of the distribution of natural gas to retail customers at state-regulated rates and interstate pipeline operations. Unregulated operations include marketing of natural gas, risk management activities, and the sale of energy-related products and services. In 2001 and in the nine months ended September 30, 2002, we derived approximately 41% of our net operating revenues from Equitable Utilities and the unregulated marketing of natural gas.

Equitable Supply

        Previously, Equitable Supply was referred to as Equitable Production. We believe that this business segment will be better understood by expanding the segment's information concerning our two lines of business, production and gathering.

        Equitable Supply 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 Supply is one of the largest owners of proved natural gas reserves in the Appalachian Basin. In 2001 and in the nine months ended September 30, 2002, we derived approximately 53% and 51%, respectively, of our net operating revenues from Equitable Supply.

NORESCO

        NORESCO provides energy-related systems and services that are designed to reduce its customers' operating costs and to improve their productivity. The segment's activities are comprised of energy infrastructure projects, including: on-site power generation, central boiler/chiller plant development, design, construction and operation; performance contracting; and energy efficiency programs. NORESCO's customers include governmental, institutional, military, and industrial end-users. Additionally, NORESCO owns/operates a portfolio of existing cogeneration facilities in the United States, Jamaica, Panama, and Costa Rica.

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Business Strategy

        Our strategy is to create shareholder value by focusing on:


Principal Offices

        Our principal offices are located at One Oxford Centre, Suite 3300, 301 Grant Street, Pittsburgh, Pennsylvania 15219 and our telephone number is (412) 553-5700.


The Exchange Offer

Background   On November 15, 2002, we completed a private placement of the original notes. In connection with that private placement, we entered into a registration rights agreement in which we agreed to deliver this prospectus to you and to make an exchange offer. This exchange offer is intended to satisfy the exchange and registration rights granted to the initial purchasers of the original notes in the registration rights agreement. Except in the limited circumstances described below, after the exchange offer is complete, you will no longer be entitled to any exchange or registration rights with respect to your original notes.

Securities Offered
 
Up to $200,000,000 of 5.15% Notes due 2012. The terms of the exchange notes and the original notes are identical in all material respects, except for certain transfer restrictions and registration rights relating to the original notes.

The Exchange Offer
 
We are offering to exchange the original notes for a like principal amount of exchange notes. Original notes may only be exchanged in integral principal multiples of $1,000.

Expiration Date; Withdrawal of Tender
 
Our exchange offer will expire 5:00 p.m., New York City time, on April 16, 2003, or a later time if we choose to extend the exchange offer. You may withdraw your tender of original notes at any time prior to the expiration date. All outstanding original notes that are validly tendered and not validly withdrawn will be exchanged. Any original notes not accepted by us for exchange for any reason will be returned to you at our expense as promptly as possible after the expiration or termination of the exchange offer.

Resales of Exchange Notes
 
Based on interpretive letters of the SEC staff to third parties, we believe that you can offer for resale, resell, and otherwise transfer the exchange notes without complying with the registration and prospectus delivery requirements of the Securities Act if:

 
 
 
 
 

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•
 
you acquire the exchange notes in the ordinary course of business;

 
 
•
 
you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate, in the distribution of the exchange notes; and

 
 
•
 
you are not an "affiliate" of ours, as defined in Rule 405 of the Securities Act.

 
 
If any of these conditions is not satisfied and you transfer any exchange notes without qualifying for a registration exemption, you may incur liability under the Securities Act. We do not assume or indemnify you against this liability.

 
 
Each broker-dealer acquiring exchange notes for its own account in exchange for original notes which it acquired through market-making activities or other trading activities must acknowledge that it will deliver a proper prospectus when any such exchange notes are transferred. After notice to us in writing, a broker-dealer may use this prospectus, as amended or supplemented from time to time, for an offer to resell, a resale or other retransfer of such exchange notes. We have agreed that until October 13, 2003 we will keep the prospectus current and make it available for this purpose to broker-dealers who request it in writing for such use.

Conditions to the Exchange Offer
 
Our obligation to accept for exchange, or to issue the exchange notes in exchange for, any original notes is subject to certain customary conditions relating to compliance with any applicable law, or any applicable interpretation by the staff of the SEC, or any order of any governmental agency or court of law. See "The Exchange Offer —Conditions to the Exchange Offer."

Procedures for Tendering Notes Held in the Form of Book-Entry Interests
 
The original notes were issued as global securities and were deposited upon issuance with the Trustee, as custodian for The Depository Trust Company ("DTC"). The Trustee issued certificateless depositary interests in those outstanding original notes, which represent a 100% interest in those original notes, to DTC. Beneficial interests in the outstanding original notes, which are held by direct or indirect participants in DTC through the certificateless depository interest, are shown on, and transfers of the original notes can only be made through, records maintained in book-entry form by DTC.

 
 
 
 
 

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You may tender your outstanding original notes:

 
 
•
 
through a computer-generated message transmitted by DTC's Automated Tender Offer Program system and received by the exchange agent and forming a part of a confirmation of book-entry transfer in which you acknowledge and agree to be bound by the terms of the letter of transmittal; or

 
 
•
 
by sending a properly completed and signed letter of transmittal, which accompanies this prospectus, and other documents required by the letter of transmittal, or a facsimile of the letter of transmittal and other required documents, to the exchange agent at the address on the cover page of the letter of transmittal;

 
 
and either:

 
 
•
 
a timely confirmation of book-entry transfer of your outstanding original notes into the exchange agent's account at DTC, under the procedure for book-entry transfers described in this prospectus under the heading "The Exchange Offer-Book Entry Transfers" must be received by the exchange agent on or before the expiration date; or

 
 
•
 
the documents necessary for compliance with the guaranteed delivery described in "The Exchange Offer-Guaranteed Delivery Procedures" must be received by the exchange agent on or before the expiration date.

Procedures for Tendering Notes held in the Form of Registered Notes
 

If you hold registered original notes, you must tender your registered original notes by sending a properly completed and signed letter of transmittal, together with other documents required by it, and your certificates, to the exchange agent, in accordance with the procedures described in this prospectus under the heading "The Exchange Offer-Procedures for Tendering Original Notes."

United Series Federal Income Tax Considerations
 

The exchange offer should not result in any income, gain or loss to the holders of original notes or to us for United States federal income tax purposes. See "Certain U.S. Federal Income Tax Considerations."

Use of Proceeds
 
We will not receive any proceeds from the issuance of the exchange notes in the exchange offer.

 
 
The proceeds from the offering of the original notes were added to our general funds and were used to reduce our outstanding commercial paper and other indebtedness.

Exchange Agent
 
The Bank of New York is serving as the exchange agent for the exchange offer.

 
 
 
 
 

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Shelf Registration Statement
 
In limited circumstances, holders of original notes may require us to register their original notes under a shelf registration statement. See "The Exchange Offer — Shelf Registration."


The Exchange Notes

        The following summary contains basic information about the exchange notes and is not intended to be a complete description. It may not contain all the information that may be important to you. For a more complete description of the exchange notes, please refer to the section of this prospectus entitled "Description of Notes."

Issuer   Equitable Resources, Inc.

Securities Offered
 
$200,000,000 aggregate principal amount of 5.15% Notes due 2012

Maturity
 
November 15, 2012

Interest Rate
 
5.15% per year

Interest Payment Dates
 
Each May 15 and November 15, commencing May 15, 2003

Minimum Denomination
 
$1,000 and any integral multiple of $1,000

Optional Redemption
 
We may redeem some or all of the exchange notes at any time, or from time to time, at our option, at a redemption price based on a "make-whole" provision. See "Description of Notes—Optional Redemption."

Ranking
 
The exchange notes will be our senior unsecured debt and will rank equally with all of our existing and future unsecured and unsubordinated debt. The exchange notes will be effectively subordinated to all of our existing and future secured debt to the extent of the assets securing that debt and to all the debt and other liabilities of our subsidiaries.

Certain Covenants
 
The indenture governing the exchange notes will, among other things, contain covenants limiting our ability and the ability of our subsidiaries to:

 
 
•
 
incur debt secured by liens;

 
 
•
 
engage in sale-leaseback transactions; and

 
 
•
 
merge or consolidate or sell all or substantially all of our assets.

 
 
These covenants are subject to important exceptions and qualifications described under "Description of Notes—Certain Covenants."

 
 
 
 
 

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Listing
 
We do not intend to list the exchange notes on any securities exchange.

Further Issues
 
We may from time to time, without notice to or the consent of the holders of the exchange notes, create and issue further exchange notes ranking equally and ratably with the exchange notes in all respects, so that such further exchange notes shall be consolidated and form a single series with the notes offered by this prospectus and shall have the same terms as to status, redemption or otherwise as the exchange notes offered by this prospectus.

Risk Factors
 
You should refer to the section entitled "Risk Factors" beginning on page 7 for a discussion of material risks you should carefully consider before deciding to exchange your notes.

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RISK FACTORS

        In addition to the other information in this prospectus, you should carefully consider the following factors in connection with the exchange offer.


Risks Relating to Our Business

Our need to comply with comprehensive, complex, and sometimes unpredictable government regulations may have an adverse effect on our business.

        Our business is affected by many government regulations relating to the exploration for, and the development, production, and transportation of, gas and oil, as well as environmental and safety matters. The regulatory environment applicable to our business has undergone substantial changes in recent years, and these changes have significantly affected the nature of the industry of which we are a part and the manner in which its participants conduct their businesses.

        The production of natural gas is subject to regulation by federal and state agencies in the United States. In general, these regulatory agencies are authorized to make and enforce regulations to prevent waste of natural gas, protect the correlative rights and opportunities to produce natural gas by owners of a common reservoir, and protect the environment. Some leases held or operated by our subsidiaries and affiliates involved in exploration and production are federal leases subject to additional regulatory requirements. Our local natural gas distribution operations are subject to the jurisdiction of the Pennsylvania Public Utility Commission ("PUC"), the Kentucky Public Service Commission, and the Public Service Commission of West Virginia with the majority of customers residing in Pennsylvania. These regulatory commissions, among other things, approve rate schedules that reflect the return on debt that we may earn on our facilities utilized to provide natural gas services.

        Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our facilities, which may affect our business in ways that we cannot predict.

A decrease in natural gas prices may have an adverse effect on our business.

        Our ability to compete in any markets and industries in which we operate depends upon general market conditions, which may change. Decreased natural gas prices could adversely affect the revenues, cash flows, and profitability of our subsidiaries and our company as a whole. Our operations are materially dependent on prices received for natural gas production. Both short-term and long-term price trends affect the economics of developing, producing, gathering, and processing natural gas. Natural gas prices can be volatile. We sell most of our natural gas at current market prices rather than through fixed-price contracts, although we frequently hedge the price of a significant portion of future production in the financial markets. The prices we receive depend upon factors beyond our control, which include:

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        We believe that any prolonged reduction in natural gas prices would depress our ability to continue the level of activity we would otherwise pursue, which could have an adverse effect on our revenues, cash flows, and results of operations.

Sustained periods of weather inconsistent with normal can create volatility in our earnings.

        Our earnings are greatly affected by variations in temperature during the winter season. Weather-related factors such as temperature at certain times of the year affect our earnings in our natural gas distribution businesses.

Our business operates in a highly competitive industry.

        Competition could lead to lower levels of profits and lower cash flows over time. The natural gas exploration and production industry in which we operate is highly competitive. We compete with major natural gas companies, independent natural gas businesses, and individual producers and operators, some of which have greater financial and other resources than we have. Industry members compete both in North America and regionally for the acquisition of properties. We must also compete for pipeline capacity to transport gas to our markets. The industry, as a whole, competes with other industries that supply energy to industrial, commercial, and other consumers. Our natural gas pipelines and storage facilities compete against other existing natural gas pipelines originating from the same sources or serving the same markets as our facilities. In addition, we may face competition from natural gas pipelines and storage projects that may be built in the future. We conduct operations without the benefit of exclusive franchises from government entities. NORESCO's business requires the continued sale of new projects in order to generate earnings from construction activities. We provide open access transportation and storage services pursuant to the terms of tariffs filed with the Federal Energy Regulatory Commission ("FERC"). Demand for storage service and transportation on our pipelines is primarily a function of customer usage rates, economic conditions, competing transportation and storage sources, and price for service. Although there are no major distributors marketing natural gas sales service in our service area, marketing firms do arrange direct purchase contracts between large users in our service area and producers outside our service area, taking advantage of the open-access status of the pipeline systems that we use to transport natural gas to our customers. In addition, we face competition from natural gas distribution operations that overlap or are adjacent to our distribution operations. Demand for natural gas is primarily a function of customer usage rates, economic conditions, competing distribution operations, and price for service.

Estimates of gas reserves may be unreliable.

        The proved gas reserve information included in this prospectus represents only estimates. These estimates are prepared by company engineers and are reviewed by independent petroleum engineering firms. The estimates were calculated using gas prices in effect on the date indicated in the reports. Any significant price changes will have a material effect on the present value of our reserves.

        Petroleum engineering is a subjective process of estimating underground accumulations of gas that cannot be measured in an exact manner. Estimates of economically recoverable gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:

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        Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:

        Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues, and expenditures with respect to reserves will vary from estimates and the variances may be material.

        The discounted future net revenues included in this prospectus should not be considered as the market value of the reserves attributable to our properties. As required by the SEC, the estimated discounted future net revenues from proved reserves are generally based on prices and costs as of the date of the estimate while actual future prices and costs may be materially higher or lower. Actual future net revenues will also be affected by factors such as:

        In addition, the 10% discount factor, which the SEC requires to be used to calculate discounted future net reserves for reporting purposes, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the gas industry in general.

The amount or timing of actual future gas production may vary and the cost of drilling is often uncertain.

        There are many risks in developing natural gas, including numerous uncertainties inherent in estimating quantities of proved gas reserves and in projecting future rates of production and timing of development expenditures. Our future success depends on our ability to develop additional gas reserves that are economically recoverable. The total amount or timing of actual future production may vary significantly from reserves and production estimates. Our drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns and these risks can be affected by lease and rig availability, geology, and other factors. Drilling for natural gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, and shortages or delays in the delivery of equipment and services can delay our drilling operation or result in their cancellation. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or we may not recover all or any portion of our investment. Without continued successful exploitation or acquisition activities, our reserves and revenues will decline as a result of our current reserves being depleted by production. We cannot assure you that we will be able to find or acquire additional reserves at acceptable costs.

The nature of our operations presents inherent risks of loss, that may have an adverse effect on our business.

        The nature of our operations presents inherent risks of loss that, if not insured or indemnified against, could adversely affect our results of operations. Our operations are subject to inherent hazards

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and risks such as: fires; natural disasters; explosions; formations with abnormal pressures; blowouts; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury or property damage. Additionally, our facilities, machinery, and equipment are subject to sabotage. Any of these events could cause a loss of hydrocarbons, environment pollution, personal injury or death claims, damage to our properties or damage to the properties of others. As protection against operational hazards, we maintain insurance coverage against some, but not all, potential losses. Our coverages include: operator's extra expense; physical damage to certain assets; employer's liability; business interruption; comprehensive general liability; automobile; and workers' compensation. Generally, the agreements that we execute with contractors provide for the division of responsibilities between the contractor and ourselves, and we seek to obtain an indemnification from the contractor for certain of these risks. To the extent we are unable to transfer such risks to the contractor, we seek protection through insurance that our management considers to be adequate. Such insurance or indemnification agreements may not adequately protect us against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, or the failure of a contractor to meet its indemnification obligations, could result in substantial losses to us. In addition, insurance may not be available to cover any or all of these risks, or, even if available, it may not be adequate or insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive. Furthermore, such hazards and risks may subject us to litigation from time to time. Such litigation could result in substantial monetary judgments against us or be resolved on unfavorable terms, the result of which could have a material adverse effect to our results of operations, financial condition and cash flows.

We may be subject to margin calls by entering into commodity price derivative contracts to hedge commodity prices.

        We use derivatives to hedge commodity prices. In order to protect to some extent against price volatility and to lock in favorable pricing on natural gas production, we periodically enter into commodity price derivatives contracts (hedging arrangements) for a portion of our expected production. In a typical hedge transaction, we have the right to receive from hedge counterparties the excess of the fixed price specified in the hedge agreement over a floating price based on a market index, multiplied by the quantity hedged. These contracts reduce exposure to subsequent price drops but may subject us to margin calls that may require us to give material amounts of collateral to counterparties in the form of cash or to settle with the commodity or cash when commodity prices rise significantly. Use of energy price hedges also exposes parties to the risk of non-performance by a contract counterparty. We carefully evaluate the financial strength of all contract counterparties, but these parties might not be able to perform their obligations under the hedge arrangements. It is our policy that the use of commodity derivatives contracts be strictly confined to the price hedging of existing and forecast production, and we maintain a system of internal controls to assure there is no unauthorized trading or speculation on commodity prices. Unauthorized speculative trades could however occur that may expose us to substantial losses to cover a position in the contract, which may in turn have a material adverse effect on our revenues, cash flows, and results of operations.

We plan to continue to implement acquisition and disposition strategies that involve a number of inherent risks, any of which may cause us not to realize anticipated benefits.

        We intend to continue to strategically position our business in order to improve our ability to compete. We plan to do this by acquiring businesses complementary to our strengths and continually evaluating business unit dispositions. As a result, the relative makeup of our business is subject to change. Acquisitions, joint venture, and other business combinations involve various inherent risks, such as assessing the value, strengths, weaknesses, contingent and other liabilities and potential profitability of acquisition or other transaction candidates; the potential loss of key personnel of an acquired business; our ability to achieve identified financial and operating synergies anticipated to result from an

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acquisition or other transaction; and unanticipated changes in business and economic conditions affecting an acquisition or other transaction.

        We may be unable to realize, or do so within any particular time frame, the cost reductions, cash flow increases or other synergies expected to result from acquisitions, joint ventures, and other transactions or investments we may undertake, or be unable to generate additional revenue to offset any unanticipated inability to realize such expected synergies. Realization of the anticipated benefits of acquisitions or other transactions could take longer than expected, and implementation difficulties, market factors, and the deterioration in domestic or global economic conditions could alter the anticipated benefits.

We are subject to environmental regulations, and violations of or liability under these regulations may have a material adverse effect on us.

        Environmental regulation significantly affects our business. Our business operations are subject to federal, state, and local laws and regulations relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal or discharge of contaminants into the environment, and the general protection of public health, natural resources, wildlife, and the environment. Costs of compliance and liabilities could negatively affect our level of cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We do not believe that environmental protection provisions currently in place will have a significant effect on our competitive position; however, because the costs of environmental regulation are already significant, additional regulation could negatively affect our business. Although we cannot predict the impact of the interpretation or enforcement of Environmental Protection Agency standards or future environmental measures or other state and local regulations, our costs could increase if environmental laws and regulations become more strict.

Increases in interest rates may adversely affect our business by causing higher interest costs.

        A portion of our indebtedness is commercial paper and commercial paper market is uncertain. Upon the maturity of our outstanding commercial paper, there can be no assurance that we will be able to lower rates. With respect to that portion of our interest costs that we cannot pass on to our utility customers, a higher interest rate would reduce our net income.

Our tax rate may be increased and/or tax laws affecting us can change that may have an adverse impact on our operations.

        The rates of federal, state, local, and international taxes applicable to the industries in which we operate, including ad valorem and severance taxes paid by Equitable Supply, which often fluctuate, could be increased by the respective taxing authorities. In addition, the tax laws, rules and regulations that affect our business could change. Any such increase or change could adversely impact our business, financial condition or results of operations.

The September 11, 2001 terrorist attacks and the possibility of wider armed conflict have adversely affected the U.S. and other economies and may adversely affect our operating results.

        Terrorist attacks, such as the attacks that occurred in New York, Pennsylvania, and Washington, D.C. on September 11, 2001, and future war or risk of war may adversely impact our results of operations, our ability to raise capital, and our future growth. Uncertainty surrounding future military strikes or sustained military campaigns may impact our operations in unpredictable ways, including disruptions of fuel or gas supplies and markets, and the possibility that infrastructure facilities, including pipelines, processing plants, and storage facilities, could be direct targets of, or indirect casualties of, an act of terror. A reduction in or total restriction to access at Federal government

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installations could hinder NORESCO's ability to construct, operate, and develop projects, negatively affecting both current and future earnings. The uncertainties of gas supply may affect our ability to replace dedicated reserves. Terrorist activity may also hinder our ability to transport natural gas if transportation facilities or pipelines become damaged as a result of an attack. In addition, war or risk of war may also have an adverse effect on the economy. A lower level of economic activity could result in a decline in energy consumption which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital. Terrorist activity or war could likely lead to increased volatility in prices for natural gas and could affect the markets for drilling services. In addition, the insurance premiums charged for some or all of the coverages currently maintained could increase dramatically, or the coverages could be unavailable in the future.

Labor disputes may have a material adverse effect on our operations and profitability.

        We collectively bargain with labor unions that represent a number of our employees. When the current collective bargaining agreements expire, failure to reach an agreement could result in strikes or other labor protests which could disrupt our operations. If we were to experience a strike or work stoppage, it would be difficult for us to find a sufficient number of employees with the necessary skills to replace these employees. We cannot assure you that we will reach any such agreement or that we will not encounter strikes or other types of conflicts with the labor unions of our personnel. Such labor disputes could have an adverse effect on our business, financial condition or results of operations, could cause us to lose revenues and customers and might have permanent effects on our business.

An unstable political and/or economic environment in foreign countries may adversely impact our operations in these countries.

        Certain of NORESCO's operations are located in foreign countries that historically have an unstable political and/or economic environment. Any political or economic turmoil in these countries could adversely impact our operations in these countries and our ability to generate the predicted amount of revenues from those operations.


Risks Related to the Exchange Notes

If no trading market develops for the exchange notes, you may not be able to resell your exchange notes at their fair market value or at all.

        Prior to this offering, there was no public market for the exchange notes. If no active trading market develops, you may not be able to resell your exchange notes at their fair market value or at all. Future trading prices of the exchange notes will depend on many factors including, among other things, our ability to effect the exchange offer, prevailing interest rates, our operating results and the market for similar securities. No assurance can be given as to the liquidity of or trading market for the exchange notes. We do not intend to apply for listing the exchange notes on any securities exchange.

Redemption may adversely affect your return on the exchange notes.

        Your exchange notes are redeemable at our option, and therefor we may choose to redeem your exchange notes at times when prevailing interest rates are relatively low. As a result, you may not be able to reinvest the proceeds you receive from the redemption in a comparable security at an effective interest rate as high as the interest rate on your exchange notes being redeemed.

12



RATIO OF EARNINGS TO FIXED CHARGES

 
   Nine Months Ended
September 30,
    
    
    
    
    
 
   Years Ended December 31,
 
   Pro Forma
2002(1)
    
    
 
   2002
   2001
   2001
   2000
   1999
   1998(2)
   1997
Ratio of Earnings to Fixed Charges   5.53   6.42   5.94   5.75   2.67   3.36   N/A   3.72
(1)
Giving effect to the repayment of outstanding commercial paper and other indebtedness with the proceeds of the issuance of the 5.15% notes.

(2)
Earnings were inadequate to cover fixed charges by $55 million for the year ended December 31, 1998.

•
The ratio of earnings to fixed charges is calculated as follows:

(earnings)
(fixed charges)

13


THE EXCHANGE OFFER

Terms of the Exchange Offer; Period for Tendering Outstanding Exchange Notes

        On November 15, 2002, we sold the original notes to J.P. Morgan Securities, Inc., Banc of America Securities LLC, Banc One Capital Markets, Inc., PNC Capital Markets, Inc., Salomon Smith Barney Inc., and BMO Nesbitt Burns Corp. These initial purchasers subsequently resold the original notes to qualified institutional buyers in accordance with Rule 144A under the Securities Act and outside the United States in accordance with Regulation S under the Securities Act. When we sold the original notes, we entered into a registration rights agreement with the initial purchasers. The registration rights agreement requires that we register the exchange notes with the SEC and offer to exchange the registered exchange notes for the outstanding original notes sold on November 15, 2002.

        We will accept any original notes that you validly tender and do not withdraw before 5:00 p.m., New York City time, on April 16, 2003 ("expiration date"). We will issue $1,000 of principal amount of exchange notes in exchange for each $1,000 principal amount of your outstanding original notes. You may tender some or all of your original notes in the exchange offer, but only in integral multiples of $1,000.

        The form and terms of the exchange notes are the same as the form and terms of the outstanding original notes except that:

        Outstanding original notes that we accept for exchange will not accrue interest after we complete the exchange offer. The exchange offer will expire at 5:00 p.m., New York City time, on the expiration date, unless we extend it. If we extend the exchange offer, we will issue a notice by press release or other public announcement before 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

        If we extend the exchange offer, original notes that you have previously tendered will still be subject to the exchange offer, and we may accept them.

        To the extent we are legally permitted to do so, we reserve the right, in our sole discretion:

        Any such delay in acceptance, termination or amendment will be followed as promptly as practicable by oral or written notice to the registered holders of original notes.

        Without limiting the manner by which we may choose to give notice of any extension, delay in acceptance, amendment or termination of the exchange offer, we will have no obligation to publish, advertise or otherwise communicate any public announcement, other than by making a timely release to a financial news service.

14


        We will promptly return your original notes without expense to you after the exchange offer expires or terminates if we do not accept them for exchange for any reason.

Procedures for Tendering Original Notes

        Only you may tender your original notes in the exchange offer. To tender your original notes in the exchange offer, you must:

        OR

if you tender your notes under The Depository Trust Company's book-entry transfer procedures, arrange for The Depository Trust Company ("DTC") to transmit an agent's message to the exchange agent on or before the expiration date.

        In addition, either:

        An agent's message is a computer-generated message transmitted to the exchange agent by DTC through its Automated Tender Offer Program. To tender your original notes effectively, a tendering party must make sure that the exchange agent receives a letter of transmittal and other required documents or an agent's message before the expiration date. When you tender your outstanding original notes and we accept them, the tender will be a binding agreement between you and us in accordance with the terms and conditions in this prospectus and in the letter of transmittal.

        The method of delivery to the exchange agent of original notes, letters of transmittal, and all other required documents is at your election and risk. We recommend that you use an overnight or hand delivery service instead of mail. If you do deliver by mail, we recommend that you use registered mail, properly insured, with return receipt requested. In all cases, you should allow enough time to make sure your documents reach the exchange agent before the expiration date. Do not send a letter of transmittal or notes directly to us. You may request your brokers, dealers, commercial banks, trust companies, or nominees to make the exchange on your behalf.

        Unless you are a registered holder who requests that the exchange notes be mailed to you and issued in your name, or unless you are an Eligible Institution, you must have your signature on a letter of transmittal or a notice of withdrawal guaranteed by an Eligible Institution. An "Eligible Institution" is a firm which is a financial institution that is a member of a registered national securities exchange or a participant in the Securities Transfer Agents Medallion Program, the New York Stock Exchange Medallion Signature Program or the Stock Exchanges Medallion Program.

        If the person who signs the letter of transmittal and tenders the original notes is not the registered holder of the original notes, the registered holders must endorse the original notes or sign a written instrument of transfer or exchange that is included with the original notes, with the registered holder's

15


signature guaranteed by an Eligible Institution. We will decide whether the endorsement or transfer instrument is satisfactory.

        We will decide all questions about the validity, form, eligibility, acceptance, and withdrawal of tendered original notes, and our determination will be final and binding on you. We reserve the absolute right to:

        Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. You must cure any defects or irregularities in connection with tenders of original notes as we will determine. Neither we, the exchange agent nor any other person will incur any liability for failure to notify you of any defect or irregularity with respect to your tender of original notes.

        If trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity sign the letter of transmittal or any notes or power of attorney on your behalf, those persons must indicate their capacity when signing, and submit to us with the letter of transmittal satisfactory evidence demonstrating their authority to act on your behalf.

        To participate in the exchange offer, we require that you represent to us that:

        The delivery of an agent's message to the exchange agent on your behalf will be deemed a representation by you to the effects stated above.

        By its acceptance of the exchange offer, any broker-dealer that receives exchange notes pursuant to the exchange offer agrees to notify us in writing before using the prospectus in connection with the resale or transfer of exchange notes. The broker-dealer further acknowledges and agrees that, upon receipt of notice from us of the happening of any event which makes any statement in the prospectus untrue in any material respect or which requires the making of any changes in the prospectus to make the statements in the prospectus not misleading or which may impose upon us disclosure obligations that may have a material adverse effect on us, which notice we agree to deliver promptly to the broker-

16


dealer, the broker-dealer will suspend use of the prospectus until we have notified the broker-dealer that delivery of the prospectus may resume and have furnished to the broker-dealer copies of any amendment or supplement to the prospectus. We have agreed in the registration rights agreement that for a period of 180 days after the effective date of the registration statement of which this prospectus is a part we will make this prospectus, as amended or supplemented, available to any broker-dealer who requests it in writing for use in connection with any such resale.

        If you are our "affiliate," as defined under Rule 405 of the Securities Act, you are a broker-dealer who acquired your original notes in the initial offering and not as a result of market-making or trading activities, or if you are engaged in or intend to engage in or have an arrangement or understanding with any person to participate in a distribution of exchange notes acquired in the exchange offer, you or that person:

        Broker-dealers who cannot make the representations in the fifth bullet point of the paragraph above cannot use this exchange offer prospectus in connection with resales of exchange notes.

Acceptance of Original Notes for Exchange; Delivery of Exchange Notes Issued in the Exchange Offer

        We will accept validly tendered original notes when the conditions to the exchange offer have been satisfied or we have waived them. We will have accepted your validly tendered original notes when we have given oral or written notice to the exchange agent. The exchange agent will act as agent for the tendering holders for the purpose of receiving the exchange notes from us. If we do not accept any tendered original notes for exchange because of an invalid tender or other valid reason, the exchange agent will return the certificates, without expense, to the tendering holder. If a holder has tendered original notes by book-entry transfer, we will credit the notes to an account maintained with DTC. We will return certificates or credit the account at DTC as promptly as practicable after the exchange offer terminates or expires.

Book-Entry Transfers

        The exchange agent will make a request to establish an account at DTC for purposes of the exchange offer within two business days after the date of this prospectus. Any financial institution that is a participant in DTC's systems must make book-entry delivery of outstanding original notes by causing DTC to transfer those outstanding original notes into the exchange agent's account at DTC in accordance with DTC's Automated Tender Offer Procedures. The participant should transmit its acceptance to DTC on or before the expiration date or comply with the guaranteed delivery procedures described below. DTC will verify acceptance, execute a book-entry transfer of the tendered outstanding original notes into the exchange agent's account at DTC and then send to the exchange agent confirmation of the book-entry transfer. The confirmation of the book-entry transfer will include an agent's message confirming that DTC has received an express acknowledgment from the participant that the participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against the participant. Delivery of exchange notes issued in the exchange offer may be effected through book-entry transfer at DTC. However, the letter of transmittal or facsimile of it or an agent's message, with any required signature guarantees and any other required documents, must:

17

Guaranteed Delivery Procedures

        If you are a registered holder of outstanding original notes who desires to tender original notes but your original notes are not immediately available, or time will not permit your original notes or other required documents to reach the exchange agent before the expiration date, or the procedure for book-entry transfer cannot be completed on a timely basis, you may effect a tender if:



Withdrawal Rights

        You may withdraw your tender of original notes at any time before 5:00 p.m., New York City time, on the expiration date.

        For a withdrawal to be effective, you must make sure that, before 5:00 p.m., New York City time, on the expiration date, the exchange agent receives a written notice of withdrawal at one of the addresses below or, if you are a participant of DTC, an electronic message using DTC's Automated Tender Offer Program.

        A notice of withdrawal must:

        If you have tendered original notes under the book-entry transfer procedure, your notice of withdrawal must also specify the name and number of an account at DTC to which your withdrawn original notes can be credited.

        We will decide all questions as to the validity, form, and eligibility of the notices and our determination will be final and binding on all parties. Any tendered original notes that you withdraw will not be considered to have been validly tendered. We will return any outstanding original notes that

18

have been tendered but not exchanged, or credit them to DTC account, as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn original notes before the expiration date by following one of the procedures described above.

Conditions to the Exchange Offer

        We are not required to accept for exchange, or to issue exchange notes in exchange for, any outstanding original notes. We may terminate or amend the exchange offer, if at any time before the acceptance of original notes:

        These conditions are for our sole benefit and we may assert or waive them at any time and for any reason. However, the exchange offer will remain open for at least five business days following any waiver of the preceding conditions. Our failure to exercise any of the foregoing rights will not be a waiver of our rights.

Exchange Agent

        You should direct all signed letters of transmittal to the exchange agent, The Bank of New York. You should direct questions, requests for assistance, and requests for additional copies of this prospectus, the letter of transmittal, and the Notice of Guaranteed Delivery to the exchange agent addressed as follows:

By Registered or Certified Mail:   By Hand Delivery:

The Bank of New York
Corporate Trust Operations
Reorganization Unit
101 Barclay Street—7E
New York, NY 10286
Attention: Mr. Santino Ginnocchietti
 
The Bank of New York
Corporate Trust Operations
Reorganization Unit
101 Barclay Street—Lobby Window
New York, NY 10286
Attention: Mr. Santino Ginnocchietti

By Overnight Courier:
 
By Facsimile:

The Bank of New York
Corporate Trust Operations
Reorganization Unit
101 Barclay Street—7E
New York, NY 10286
Attention: Mr. Santino Ginnocchietti
 
(212) 298-1915
Attention: Mr. Santino Ginnocchietti
Confirmed by telephone:
(212) 815-6331

        Delivery or fax of the letter of transmittal to an address or number other than those above is not a valid delivery of the letter of transmittal.

19


Fees and Expenses

        We will not make any payment to brokers, dealers, or others soliciting acceptances of the exchange offer except for reimbursement of mailing expenses. The expenses to be incurred in connection with the exchange offer will be paid by us. These expenses will include reasonable and customary fees and out-of-pocket expenses of the exchange agent and reasonable out-of-pocket expenses incurred by brokerage houses and other fiduciaries in forwarding materials to beneficial holders in connection with the exchange offer.

Accounting Treatment

        The exchange notes will be recorded at the same carrying value as the existing original notes, as reflected in our accounting records on the date of exchange. Accordingly, we will recognize no gain or loss for accounting purposes. The expenses of the exchange offer will be expensed over the term of the exchange notes.

Transfer Taxes

        If you tender outstanding original notes for exchange you will not be obligated to pay any transfer taxes. However, if you instruct us to register exchange notes in the name of, or request that your original notes not tendered or not accepted in the exchange offer be returned to, a person other than you, you will be responsible for paying any transfer tax owed.

You May Suffer Adverse Consequences if You Fail to Exchange Outstanding Exchange Notes

        Original notes that are not tendered or that are tendered but not accepted by us will, following completion of the exchange offer, continue to be subject to existing restrictions upon transfer under the Securities Act. Upon completion of the exchange offer, specified rights under the registration rights agreement, including registration rights and any right to additional interest, will be either limited or eliminated. Accordingly, if you do not tender your notes in the exchange offer, your ability to sell your original notes could be adversely affected. Once we have completed the exchange offer, holders who have not tendered notes will not continue to be entitled to any increase in interest rate that the indenture provides for should we not complete the exchange offer.

        Holders of the exchange notes issued in the exchange offer and original notes that are not tendered in the exchange offer will vote together as a single class under the indenture.

Consequences of Exchanging Outstanding Original Notes

        If you make the representations that we discuss above, we believe that you may offer, sell or otherwise transfer the exchange notes to another party without registration of your notes or delivery of a prospectus.

        We base our belief on interpretations by the staff of the SEC in no-action letters issued to third parties. If you cannot make these representations, you cannot rely on this interpretation by the SEC's staff and you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a resale of the original notes. A broker-dealer that receives exchange notes for its own account in exchange for its outstanding original notes must acknowledge that it acquired the original notes as a result of market making activities or other trading activities and that it will deliver a prospectus in connection with any resale of the exchange notes. Broker-dealers who can make these representations may use this exchange offer prospectus, as supplemented or amended, in connection with resales of exchange notes issued in the exchange offer. We have agreed in the registration rights agreement that for a period of 180 days after the effective date of the registration statement of which

20


this prospectus is a part we will make this prospectus, as amended or supplemented, available to any broker-dealer who requests it in the letter of transmittal for use in connection with any such resale.

        However, because the SEC has not issued a no-action letter in connection with this exchange offer, we cannot be sure that the staff of the SEC would make a similar determination regarding the exchange offer as it has made in similar circumstances.

Shelf Registration

        The registration rights agreement requires that we file a shelf registration statement if:

        Original notes will be subject to restrictions on transfer until:

21


USE OF PROCEEDS

        We are making the exchange offer to satisfy our obligation under the registration rights agreement we entered into with the initial purchasers when we issued the original notes. We will not receive any cash proceeds from the issuance of the exchange notes. In consideration for issuing the exchange notes, we will receive an equal principal amount of original notes. The original notes surrendered in exchange for the exchange notes will be retired and cancelled.

        The proceeds from the issuance and sale of the original notes were $196,834,000 after deducting initial purchasers' commissions and other estimated offering expenses. The proceeds were added to our general funds and were used to reduce our outstanding commercial paper and other indebtedness.

22


CAPITALIZATION

        The following table sets forth our consolidated capitalization as of September 30, 2002 on a historical basis and as adjusted to give effect to this offering. This table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements and notes related thereto appearing elsewhere in this prospectus.

 
   As of September 30, 2002
  
 
   Actual
   As Adjusted(1)
  
 
   (in thousands except shares and per share data)
(Unaudited)

  
Current liabilities:              
  Current portion of nonrecourse project financing   $ 16,219   $ 16,219  
  Current portion of debentures and medium term notes     24,250     24,250  
  Short-term loans     232,400     34,266  
  Accounts payable     104,595     104,595  
  Prepaid gas forward sale     55,705     55,705  
  Derivative commodity instruments, at fair value     41,934     41,934  
  Other current liabilities     107,670     107,670  
   
 
 
      Total current liabilities     582,773     384,639  
   
 
 
Long-term debt:              
  Debentures and medium-term notes     247,000     247,000  
  Notes offered hereby     —     200,000  
Deferred and other credits:              
  Deferred income taxes     357,345     357,345  
  Deferred investment tax credits     13,501     13,501  
  Prepaid gas forward sale     55,632     55,632  
  Deferred revenue     13,755     13,755  
  Project financing obligations     83,173     83,173  
  Other credits     77,970     77,970  
   
 
 
      Total deferred and other credits     601,376     601,376  
Preferred trust securities:   $ 125,000   $ 125,000  
Common stockholders' equity:              
  Common stock, no par value, 160,000 shares authorized; 74,504 shares issued and outstanding     281,931     281,931  
  Treasury stock, shares at cost: 12,327     (268,135 )   (268,135 )
  Retained earnings     755,495     755,495  
  Accumulated other comprehensive income     19,480     19,480  
   
 
 
  Total common stockholders' equity     788,771     788,771  
   
 
 
      Total   $ 2,344,920   $ 2,346,786  
   
 
 
(1)
Gives effect to the issuance of the notes (net of the estimated fees and expenses related thereto) and the application of the proceeds as described in "Use of Proceeds."

23


SUMMARY SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

        The following year ended annual selected financial data are derived from the consolidated financial statements of Equitable Resources, Inc. which have been audited by Ernst & Young LLP, independent auditors. The data should be read in conjunction with the consolidated financial statements, related notes, and other financial information incorporated by reference in this prospectus. The selected financial information presented for the nine months ended September 30, 2002 and 2001 is unaudited. In the opinion of management, the unaudited selected financial information has been prepared on the same basis as the audited selected consolidated financial information and includes all adjustments, consisting of normal recurring adjustments, necessary to present fairly our results of operations and financial position as of the dates and for the periods presented. The unaudited selected financial information for the nine months ended September 30, 2002 is not necessarily indicative of results that may be expected for any other interim period or for the full year ending December 31, 2002. You should read the following information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this prospectus and our consolidated financial statements and related notes incorporated in this prospectus by reference.

 
   Nine Months Ended
September 30,
   Years Ended December 31,
  
 
   2002
   2001
   2001
   2000
   1999
   1998
   1997
  
 
   (Unaudited)

   (in thousands except per share data)

  
Results of Operations Data:                                            
Net operating revenues   $ 403,261   $ 426,992   $ 567,608   $ 576,951   $ 455,350   $ 401,696   $ 445,906  
  Operations and maintenance     54,829     60,696     80,607     103,020     74,424     74,859     104,200  
  Production and exploration     19,587     26,899     34,500     45,870     35,142     56,779     39,111  
  Selling, general, and administrative expense     73,248     85,817     124,743     116,050     102,307     114,846     100,328  
  Interest expense     28,182     31,000     41,098     75,661     37,132     40,302     34,903  
  Other cost (income)     —     —     —     390     —     —     (50,120 )
  Equity earnings (losses) from nonconsolidated investments and minority interest     (6,936 )   26,369     26,101     25,161     2,683     2,667     —  
   
 
 
 
 
 
 
 
  Income from continuing operations before income taxes and cumulative effect of accounting change     164,008     196,312     239,531     163,344     108,486     (49,433 )   117,397  
Provisions (benefit) for income taxes     55,761     68,809     87,723     57,171     39,356     (22,381 )   43,210  
   
 
 
 
 
 
 
 
Income from continuing operations     108,247     127,503     151,808     106,173     69,130     (27,052 )   74,187  
   
 
 
 
 
 
 
 
Net income (loss)   $ 111,728   $ 127,503   $ 151,808   $ 106,173   $ 69,130   $ (44,119 ) $ 78,057  
   
 
 
 
 
 
 
 
Cash Flow Data:                                            
Net cash provided by operating activities   $ 189,665   $ 115,660   $ 129,869   $ 361,153   $ 154,318   $ 90,227   $ 121,861  
Net cash (used in) provided by investing activities     (91,229 )   (75,762 )   (125,761 )   (363,008 )   (137,543 )   142,003     (79,056 )
Net cash (used in) provided by financing activities     (121,408 )   (91,720 )   (26,509 )   35,847     (101,188 )   (199,228 )   11,900  

24

Financial Position Data:                                            
Cash   $ 6,650   $ 201   $ 92,578   $ 52,023   $ 18,031   $ 102,444   $ 69,442  
Accounts receivable, net     88,845     154,191     132,750     300,399     148,103     199,362     354,121  
Inventories     94,109     106,557     96,445     85,246     40,859     33,743     37,156  
Total current assets     386,654     526,887     613,344     583,736     326,838     451,442     684,734  
Property and equipment, net     1,513,086     1,441,113     1,414,277     1,419,429     1,221,431     1,194,443     1,187,002  
Regulatory assets     81,033     63,624     80,225     62,755     63,382     65,983     69,919  
Goodwill     51,702     58,350     57,364     60,635     64,382     68,128     66,823  
Contract receivables     13,265     6,533     49,577     22,843     72,668     63,423     81,391  
Total assets     2,344,920     2,392,582     2,518,747     2,424,914     1,789,574     1,860,856     2,328,051  
Current portion of long-term debt     40,469     26,949     16,696     10,561     —     74,136     5,000  
Total current liabilities     582,773     609,109     612,190     845,581     443,246     441,960     745,701  
Long-term debt, less current portion     247,000     271,250     271,250     271,250     298,350     281,350     417,564  
Deferred taxes     357,345     336,287     364,633     247,833     183,896     172,676     208,236  
Other liabilities and deferred credits     244,031     212,491     299,520     225,016     96,272     131,451     133,030  
Preferred trust securities     125,000     125,000     125,000     125,000     125,000     125,000     —  
Total stockholder's equity     788,771     838,445     846,154     693,695     642,810     708,419     823,520  

Other Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EBITDA(1)   $ 246,822   $ 279,949   $ 353,859   $ 336,782   $ 246,340   $ 58,972   $ 232,202  
EBITDA(1) to interest expense     8.8     9.0     8.6     4.5     6.6     1.5     6.7  
Cash dividends declared per share of common stock(2)     0.50     0.47     0.628     0.59     0.59     0.59     0.59  
Total dividends paid     31,257     30,178     40,356     38,490     40,384     43,800     42,679  
Capital expenditures     155,235     83,474     132,679     123,727     101,991     158,714     227,360  
Business acquisitions     —     —     —     677,235     40,128     —     —  
Depreciation, depletion, and amortization     51,151     52,637     73,230     97,777     100,722     85,170     76,032  
(1)
Earnings before interest, income taxes, depreciation, and amortization ("EBITDA") is presented as a measure of our ability to service our debt and to make capital expenditures. EBITDA is not a measure of operating results and is not presented in our consolidated financial statements and is not considered a qualified financial measurement under U.S. generally accepted accounting principles.

(2)
Adjusted to reflect the two-for-one stock split effective June 11, 2002.

25


MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS


Critical Accounting Policies Involving Significant Estimates

        The following discussion and analysis of the financial statements and results of our operations are based upon our 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 our more significant judgments and estimates used in the preparation of our consolidated financial statements. There can be no assurance that our actual results will not differ from those estimates.

Revenue Recognition

        Revenues from 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.

        We recognize 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

        We use 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, we utilize 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.

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        The carrying value of our proved oil and gas properties is 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, we estimate the expected future cash flows (on an undiscounted basis) from our proved oil and gas properties and compare 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, we used forward market prices. For the nine months ended September 30, 2002 and 2001 and the years ended December 31, 2001 and 2000, we 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. We had no loss contracts as of September 30, 2002.

Hedging and Derivatives

        Our primary market risk exposure is the volatility of future prices for natural gas. We use a variety of techniques to minimize this exposure, which includes sales of gas properties, other monetizations, and prepaid natural gas sales. We also use derivative financial instruments to reduce the effect of this volatility. Our strategy is to become more highly hedged at prices considered to be at the upper end of historical levels. We use simple, non-leveraged derivative instruments that are placed with major financial institutions whose creditworthiness is continually monitored. Our Corporate Risk Committee and Board of Directors approved a set of policies that guides the use of these derivative financial instruments.

Newly Issued Accounting Standards

        In July 2001, the Financial Accounting Standards Board ("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. We recorded goodwill of $57.4 million at December 31, 2001.

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        In accordance with the requirements of Statement No. 142, we tested our goodwill for impairment as of January 1, 2002. Our goodwill balance as of January 1, 2002 totaled $57.4 million and is entirely related to the NORESCO segment. The fair value of our goodwill was estimated using discounted cash flow methodologies and market comparable information. As a result of the impairment test, we recognized an impairment of $5.5 million, net of tax, or $0.09 per diluted share, to reduce the carrying value of the goodwill to NORESCO's estimated fair value as the level of future cash flows from the NORESCO segment are expected to be less than originally anticipated. In accordance with Statement No. 142, this impairment adjustment has been reported as the cumulative effect of an accounting change in our Statements of Consolidated Income retroactive to the first quarter 2002. The impairment adjustment reduced our reported first quarter 2002 net income of $52.4 million, or $0.80 per diluted share, to $46.9 million, or $0.72 per diluted share.

        In July 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. Our management continues to assess the impact, if any, of this pronouncement on our earnings and financial position.

        In October 2001, the FASB issued Statement No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which is effective for fiscal year 2002. Statement No. 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.

        During the second quarter 2002, we evaluated the ongoing value of the Jamaican power plant project. We own 91.24% of the equity in the project and therefore we consolidate the project in our financial statements. The Jamaican power plant project has not operated to expected levels and remediation efforts have been ineffective. We recorded a long-lived asset impairment of $5.3 million.

        In January 2003, the FASB issued interpretation No. 46 "Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements" ("Interpretation No. 46"). Interpretation No. 46 is an interpretation relating to the principles of consolidation of variable interest entities. Variable interest entities involve ownership interests of an entity where an ownership participant has substantive decision-making authority without regard to such participant's actual ownership percentage. A variable interest entity would be required to be consolidated by the participant that has majority ownership, or otherwise has the ability to make decisions, and is entitled to the majority of either the entity's risks or residual economics through variable interests. Interpretation No. 46 requires immediate application to variable interest entities created after January 31, 2003. For variable interest entities created before that date, the provisions would be applied to those still existing as of the beginning of the first fiscal year or interim period beginning after June 15, 2003. Equitable is currently evaluating the impact of Interpretation No. 46 on its financial statements.

        In June 2002, the FASB's Emerging Issues Task Force ("EITF") issued EITF 02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, 'Accounting for Contracts Involved in Energy Trading and Risk Management Activities,"' and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." EITF 02-3 is effective for financial statements issued for periods ending after July 15, 2002 and requires that gains and losses on energy trading contracts be recorded net on a company's income statement.

        Prior to this guidance, we were required to report the gains and losses on our energy trading contracts (as defined in EITF 98-10) gross on our Statements of Consolidated Income. As a result of this guidance, in the third quarter 2002, we classified all gains and losses on our energy trading contracts net on our Statements of Consolidated Income for all periods presented. The reduction from a gross to a net classification has resulted in a reduction in both operating revenues and cost of sales for our Utility segment for the nine months ended September 30, 2002 and 2001 of $271.4 million and

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$692.2 million, respectively. The reclassification for the years ending December 31, 2001, 2000, and 1999 were $591.9 million, $615.7 million, and $197.4 million.

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

        In December 2002, the FASB issued Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure, amending FASB Statement No. 123, Accounting for Stock-Based Compensation" ("Statement No. 148"). This statement amends Statement 123 to provide alternative methods for transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation. It also amends the disclosure provisions of Statement No. 123 to require prominent disclosure about the effects on reported net income of an entity's accounting policy decisions with respect to stock-based employee compensation. Finally, Statement No. 148 amends APB Opinion No. 28 "Interim Financial Reporting" to require disclosure about those effects in interim financial information. For entities that voluntarily change to the fair value based method of accounting for stock-based employee compensation, the transition provisions are effective for fiscal years ending after December 15, 2002. For all other companies, the disclosure provisions and the amendment of APB No. 28 are effective for interim periods beginning after December 15, 2002. Management is currently assessing the impact that adoption of Statement No. 143 will have on the earnings and financial position of the Company.

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


Consolidated Results of Operations

        Our consolidated net income from continuing operations for the period ended September 30, 2002 was $111.7 million, or $1.73 per diluted share, compared with $127.5 million, or $1.93 per diluted share, for the period ended September 30, 2001. Our 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.

Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001

        The decrease in earnings for the nine month period ended September 30, 2002 over the nine month period ended September 30, 2001 was mainly attributable to lower commodity prices realized in the Supply segment and to decreased throughput in the Utility segment resulting from warmer than usual weather. The decrease was further impacted by the equity loss in Westport of $4.6 million compared to equity earning of $19.9 million in the nine months of 2001. The decrease was also caused by a long-lived asset impairment at the NORESCO segment combined with the loss of income related

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to production volumes of oil-dominated fields that were sold in 2001 and decreased commodity prices within the Supply segment. The decrease was partially offset by a gain from discontinued operations, increased throughput due to colder weather at the Utility segment, and decreased operating costs at all three business units in the second quarter of 2002. The decrease was further offset by the absence of a $4.3 million charge related to a workforce reduction in June 2001 at the Utility segment.

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

        The improved 2001 earnings were due to higher realized selling prices; incremental natural gas production attributable to a full year of production from the acquired Statoil Energy, Inc. ("Statoil") 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.

Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

        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 $1.5 million for the nine months ended September 30, 2002, and $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

 
   Nine Months Ended
September 30,
   Years Ended December 31,
  
 
   2002
   2001
   2001
   2000
   1999
  
 
   (in thousands except percentage amounts)

  
OPERATIONAL DATA                                
Operating expenses/net revenues     52.62 %   65.79 %   65.77 %   60.85 %   64.62 %
Capital expenditures   $ 48,170   $ 26,002   $ 38,528   $ 28,436   $ 43,979  
FINANCIAL DATA                                
Utility revenues   $ 226,964   $ 318,423   $ 408,812   $ 377,700   $ 324,869  
Marketing revenues     128,570     210,537     440,246     393,866     289,616  
   
 
 
 
 
 
  Total revenues     355,534     528,960     849,058     771,566     614,485  
Purchased natural gas cost     189,807     362,457     618,316     534,087     386,585  
   
 
 
 
 
 
  Net revenues     165,727     166,503     230,742     237,479     227,900  
Operating and maintenance expense     37,299     42,780     56,013     59,072     57,844  
Selling, general and administrative
expense		     36,552     46,900     69,344     57,244     53,819  
Depreciation, depletion, and amortization     19,981     19,864     26,404     28,185     35,596  
   
 
 
 
 
 
  Total Expenses     93,832     109,544     151,761     144,501     147,259  
   
 
 
 
 
 
Operating income   $ 71,895   $ 56,959   $ 78,981   $ 92,978   $ 80,641  
   
 
 
 
 
 

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        Equitable Utilities had operating income of $71.9 million for the nine-month period ended September 30, 2002, compared with $57.0 million for the period ended September 30, 2001. The increase was related to our ongoing cost reduction initiatives and improved marketing margins despite the decline in gross revenues. The improved margins, in the context of sharply lower gross revenues, was a result of our decision to focus on storage and asset management activities and de-emphasize the low margin trading-oriented activities.

        Equitable Utilities had operating income of $79.0 million for 2001, compared with $93.0 million for 2000. The lower results for 2001 were primarily due to reduced revenues resulting from warm weather and charges related to pipeline operations workforce reductions.

        Operating income for Equitable Utilities increased 15.3% from 1999 to 2000. The increase in 2000 was a result of higher net revenues due principally to the acquisition of Carnegie Natural Gas Company and subsidiaries ("Carnegie") in December 1999 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 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. Equitrans is our subsidiary whose operations comprised 32% of Equitable Utilities net operating revenues during 1999. 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.

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   Nine Months Ended
September 30,
   Years Ended December 31,
 
   2002
   2001
   2001
   2000
   1999
 
   (in thousands except percentage amounts)
OPERATIONAL DATA                              
Degree days(1) (30 year average 5,968)     3,076     3,457     5,059     5,596     5,485
O& M per customer(2)   $ 189.89   $ 202.17   $ 296.52   $ 271.94   $ 254.85
Volumes (MMcf):                              
Residential     16,864     17,997     24,753     27,776     25,431
Commercial and industrial     21,340     17,991     24,500     32,521     22,209
   
 
 
 
 
Total natural gas sales and transportation     38,204     35,988     49,253     60,297     47,640
FINANCIAL DATA                              
Net revenues   $ 107,182   $ 112,121   $ 154,624   $ 159,818   $ 144,969
Operating expenses     53,560     57,323     84,276     78,454     73,179
Depreciation, depletion, and amortization     14,812     13,569     18,175     17,411     17,086
   
 
 
 
 
Operating Income   $ 38,810   $ 41,229   $ 52,173   $ 63,953   $ 54,704
(1)
30 year: yearly average = 5,968; year-to-date average = 3,848

(2)
O&M is defined for this calculation as the sum operating and maintenance and selling, general and administrative expenses, excluding other taxes.

        Net revenues for the nine-month period ended September 30, 2002 were $107.2 million, compared with $112.1 million for the nine-month period ended September 30, 2001. Weather in the distribution service territory for the nine months ended September 30, 2002, was 20% warmer than normal and 11% warmer than 2001, primarily associated with warm temperatures in the first quarter of 2002. Residential volumes decreased 6% from the prior year period, while commercial and industrial volumes increased 19%. Despite the increase in commercial and industrial volumes, net operating revenues did not proportionately increase due to the relatively low margins on industrial customer volumes.

        Total operating expenses decreased $3.8 million, or 7% from the nine-month period ended September 30, 2001. The decrease in operating expenses was related to a reduction in the provision for bad debts attributable to lower gas prices in the current year, and from continued process improvement initiatives.

        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 was attributable to a $7.0 million charge for incrementaI credit-related reserves in the fourth quarter of

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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 was 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 was due principally to the acquisition of Carnegie Gas, increased provision for performance-related bonuses and higher administrative costs.

 
   Nine Months Ended
September 30,
   Years Ended December 31,
 
   2002
   2001
   2001
   2000
   1999
 
   (in thousands except percentage amounts)
OPERATIONAL DATA                              
Transportation throughput (MMBtu)     56,725     53,095     70,693     81,692     76,727
FINANCIAL DATA                              
Net revenues   $ 41,607   $ 44,726   $ 62,079   $ 61,119   $ 73,273
Operating expenses     17,701     26,579     33,249     29,040     32,607
Deprivation, depletion, and amortization     4,860     6,042     7,872     10,577     18,312
   
 
 
 
 
Operating income   $ 19,046   $ 12,105   $ 20,958   $ 21,502   $ 22,354

        Excluding the impact of the transfer of gathering assets of $2.8 million, net revenues from pipeline operations decreased slightly to $41.6 million in the nine-month period ended September 30, 2002 from $41.9 million in the nine-month period ended September 30, 2001. Excluding the $4.3 million one-time charge for the workforce reductions, the $1.7 million charge for compressor automation and lease buyout in 2001 and the $2.2 million reduction of operating costs in 2002 due to the gathering asset transfer, operating expenses declined by $0.7 million, or 3%, to $19.9 million. The decrease in operating costs resulted from the on-going savings realized from workforce reductions, compressor station automation, and a lease buyout, despite higher pension and planned maintenance costs. Depreciation and amortization expenses for the nine-month period ended September 30, 2002 decreased to $4.9 million from $6.0 million for the same prior year period.

        Net revenues from pipeline operations increased to $62.1 million from $61.1 million in 2000. Pipeline revenues in 2000 included $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 was 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% was 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 were due to the September 2001 and September 2000 charges for workforce reductions and

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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 included $3.8 million for the recovery of stranded costs in rates from the previously mentioned Equitrans rate case settlement. Revenues in 1999 included $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 included $2.9 million of amortization expense related to the recovery of stranded costs in rates. Operating expenses for 1999 included $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.

 
   Nine Months Ended
September 30,
   Years Ended December 31,
 
   2002
   2001
   2001
   2000
   1999
 
   (in thousands except percentage amounts)
OPERATIONAL DATA                              
Marketed gas sales (MMBtu)     125,473     170,052     215,541     240,992     188,133
Net revenue/MMBtu   $ 0.1268   $ 0.0568   $ 0.0651   $ 0.0687   $ 0.0513
FINANCIAL DATA                              
Net revenues   $ 16,938   $ 9,656   $ 14,039   $ 16,542   $ 9,658
Operating expenses     2,590     5,778     7,832     8,822     5,877
Depreciation, depletion, and amortization     309     253     357     197     198
   
 
 
 
 
Operating income   $ 14,039   $ 3,625   $ 5,850   $ 7,523   $ 3,583

        Net operating revenues for the nine months ended September 30, 2002 increased $7.3 million, or 75% from the same prior year period. Excluding the one-time loss of $2.6 million for the nine-month period ended September 30, 2001 on transactions marked to market that were previously treated as hedges, the net operating revenues increased $4.7 million. This increase in net operating revenues and in unit marketing margins versus the same period last year was a result of our decision to focus on storage and asset management activities and de-emphasize the low margin trading-oriented activities.

        Operating expenses for the nine-month period decreased by $3.2 million, or 55% from the nine months ended September 30, 2001. The decrease was due to cost reduction initiatives associated with

34


our decision to de-emphasize the low margin trading-oriented activities and from a decreased provision for bad debts attributable to lower gas prices compared to prior year.

        Net revenues from 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 was in line with our strategic decision to reduce our 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 was 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 from energy marketing operations increased 71.3%, from 1999 to 2000. The increase in net revenues was 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 us to benefit from the increasing natural gas prices.

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

Equitable Supply

        Previously, Equitable Supply was referred to as Equitable Production. We believe that this business segment will be better understood by expanding the segment's information concerning are two lines of business, production and gathering.

        During 2000, Equitable Supply completed several transactions which affect the comparability of the financial data between the periods described.

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

        In December of 2001, we sold our oil-dominated fields in order to focus on natural gas activities. The sale resulted in a decrease in 63 billion cubic feet equivalent ("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.

        During 2000, we utilized two prepaid natural gas sales transactions in order to limit our exposure to commodity volatility, to reduce counter-party risk, and to raise capital. These contracts are based upon energy content or British thermal units ("Btu"). We convert these to their volumetric equivalents or thousand cubic feet equivalent ("Mcfe") using a factor of 1.05 Btu per Mcfe.

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        In December 2000, we sold approximately 26.1 Bcf of future production for proceeds of $104 million. This natural gas advance sales contract was treated as a prepaid forward sale and was recorded as a liability. Under the terms of this sales contract, we must deliver approximately 14,300 thousand cubic feet ("Mcf") per day for five years starting January 1, 2001. We recognize the revenue from this sale as natural gas is gathered and delivered.

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

        Below is a table that details the specifics of our 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

        In November 1995, we monetized certain Appalachian gas properties to a partnership, Appalachian Basin Partners ("ABP"), the production from which qualifies for the non-conventional fuels tax credit. We treated the proceeds from the deal as monetized production and consequently recognized all of the activity from the partnership in our Statements of Consolidated Income and reduced the deferred revenue balance established from the receipt of the proceeds by the cash payments made to the other partners as production occurred. We retained a partnership interest in the properties that increased substantially at the end of 2001 to 69% when a performance target was met. Consequently, beginning in 2002, we no longer include ABP volumes as monetized sales, but instead as equity production sales. As a result, monetized volumes sold decreased by 6.5 Bcf during the nine months ended September 30, 2002, while equity production volumes increased by the same amount. Additionally, beginning January 1, 2002, we consolidated the partnership with the portion not owned by us and some reserves pertaining to unresolved issues related to the partnership agreement recorded as a minority interest. The minority interest expense recognized for the nine months ended September 30, 2002 was $5.2 million and is included within minority interest other in the Statements of Consolidated Income. The sales volumes attributed to the minority interest owners for the nine months ended September 30, 2002, was 2.1 Bcf. As a result of our increased interest in ABP in 2002, we began receiving a greater percentage of the nonconventional fuels tax credit. The nonconventional fuels tax credit for this production is slated to expire on December 31, 2002. Legislative proposals exist to extend the nonconventional fuels tax credit beyond December 31, 2002. The enactment of such legislation is uncertain at this time.

        Occasionally, we enter into a sale of gas properties in order to reduce our exposure to commodity volatility, to reduce counter-party risk, eliminate production risk, and to raise capital, while providing us with market-based fees associated with the gathering, marketing, and operation of these producing properties.

        In June 2000, we 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. We 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 our equity interest to increase. We separately negotiated

36


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, we may from time to time have receivables outstanding from ESP of up to $10 million.

        In December 2000, we 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. We retained an interest in the trust which was recorded as Equity in Nonconsolidated Investments under the equity method of accounting. The transaction contains a provision, under certain circumstances, for our equity interest to increase. We 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, we receive 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 our various sales of gas properties as of December 31, 2001 and 2000.

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

        Our capital budget for 2002 is $121 million. This includes $98 million for development of Appalachian holdings, $16 million for improvements to gathering system pipelines, and $7 million for technology initiatives. This 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 continue to be the principal factors for the economic justification of drilling and gathering system investments. Through September 30, 2002, our capital expenditures have been $105.5 million.

37

 
   Nine Months Ended
September 30,
   Years Ended December 31,
 
   2002
   2001
   2001
   2000
   1999
 
   (in thousands except operational data)
OPERATIONAL DATA                              
Production:                              
  Net equity sales, natural gas and equivalents (MMCfe)     34,861     28,052     38,825     66,356     30,844
  Average (well-headed) sales price ($/Mcfe)   $ 3.36   $ 3.98   $ 3.67   $ 3.06   $ 2.30
  Monetized sales (MMcfe)(1)     10,530     17,056     22,845     11,105     11,819
  Average (well-head) sales price ($/ Mcfe)   $ 3.26   $ 3.98   $ 3.81   $ 2.04   $ 1.85
  Company usage (MMcfe)     4,731     4,336     5,742     6,568     3,232
  Lease operating expense, excluding severance tax ($/Mcfe)   $ 0.27   $ 0.33   $ 0.32   $ 0.33   $ 0.33
  Severance tax ($/MMcfe)   $ 0.11   $ 0.18   $ 0.16   $ 0.16   $ 0.09
  Depletion ($/Mcfe)   $ 0.39   $ 0.38   $ 0.38   $ 0.49   $ 0.42
Production Services:                              
  Gathered volumes (MMcfe)     90,258     79,326     106,832     92,440     49,396
  Average gathering fee ($/Mcfe)(2)   $ 0.51   $ 0.58   $ 0.58   $ 0.58   $ 0.59
  Gathering and compression expense ($/Mcfe)   $ 0.19   $ 0.23   $ 0.23   $ 0.27   $ 0.33
  Gathering and compression depreciation ($/Mcfe)   $ 0.09   $ 0.10   $ 0.10   $ 0.11   $ 0.15
Total operated volumes(3)     68,163     69,105     93,167     89,932     45,896
Volumes handled (MMcfe)(4)     99,349     89,978     119,874     101,889     58,196
Selling, general, and administrative ($/Mcfe handled)   $ 0.18   $ 0.20   $ 0.20   $ 0.23   $ 0.33
Capital expenditures   $ 105,530   $ 56,831   $ 93,862   $ 84,661   $ 29,155
(1)
Volumes sold associated with our two prepaid natural gas sales contracts and the ABP partnership discussed above.
(2)
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 we utilize standard measures in order to split the price into its two components.
(3)
Includes equity volumes, monetized volumes, and volumes in which interests were sold, but which we still operate for a fee.
(4)
Includes operated volumes plus volumes gathered for third parties.

38

 
   Nine Months Ended
September 30,
   Years Ended December 31,
 
   2002
   2001
   2001
   2000
   1999
 
   (in thousands)
FINANCIAL DATA                              
Revenues from Production   $ 152,415   $ 179,639   $ 229,344   $ 225,774   $ 92,680
Services:                              
  Revenue from gathering fees     45,837     45,844     61,475     53,268     29,178
  Other revenues     8,210     8,883     11,459     10,120     4,152
   
 
 
 
 
  Total revenues     206,462     234,366     302,278     289,162     126,010
Operating expenses:                              
  Gathering and compression Expenses     17,530     17,916     24,594     25,237     16,424
  Lease operating expense     13,534     16,227     21,855     27,893     15,009
  Severance tax     5,425     9,042     10,640     13,103     3,977
  Depreciation, depletion and amortization     29,771     28,254     40,624     57,175     29,141
  Selling, general, and administrative     17,526     18,000     24,556     23,470     19,034
  Exploration and dry hole expense     628     1,630     2,005     2,896     1,891
  Strike-related expenses     —     —     —     18,694     —
   
 
 
 
 
    Total operating expenses     84,414     91,069     124,274     168,468     85,476
Equity from nonconsolidated investments     (4,998 )   660     726     167     —
Other loss     —     —     —     (6,951 )   —
   
 
 
 
 
Earnings before interest and taxes   $ 117,050   $ 143,957   $ 178,730   $ 113,910   $ 40,534

        Equitable Supply's earnings before interest and taxes for the nine months ended September 30, 2002, was $117.0 million, 19% lower than the $144.0 million earned for the nine months ended September 30, 2001. Our results were negatively affected by lower commodity prices, which resulted in a decrease of $24.4 million and increased minority interest expense of $5.2 million due to the ABP transition and the loss of volumes associated with the December 2001 oil field sale. These factors were partially offset by increased sales volume due to increased developmental drilling and lower operating costs.

        During the nine months ended September 30, 2002, revenues declined $27.9 million, or 12%, from $234.4 million to $206.5 million, primarily due to lower market prices for gas. Our weighted average well-head sales price realized on produced volume fell to $3.36 per Mcfe, compared to $3.98 per Mcfe in the same period in 2001, which represented a 16% decline. The overall production volume increase was a result of new drilling and production enhancements (3.5 Bcfe), partially offset by sales volumes lost in the December 2001 oil field sale (3.2 Bcfe).

        Operating expenses were $84.4 million compared to $91.1 million for the nine months ended September 30, 2001. This 7% reduction was primarily due to reductions in lease operating expenses, severance taxes, and selling, general, and administrative expenses. Lease operating expense and selling, general, and administrative expense reductions are a result of continued operating efficiency improvements, while severance taxes are primarily lower due to declines in the weighted average well-head sales price. Operating costs per Mcfe, consisting of lease operating expense, gathering, and compression expense and selling, general, and administrative expense, decreased from $0.76 to $0.64, a 16% reduction. The total value of the operating cost savings was $3.5 million.

39


        Revenues from production increased slightly from 2000 to 2001. The increase in revenues from production of $4 million from 2000 to 2001 was 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 Supply'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 was still gathered and compressed by us. 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 a 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 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 was 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 Supply's average selling prices for natural gas increased 33.0% over the prior year. 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 Supply 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 us 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.

        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 and thereafter.

40

        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 Supply also participated in exploratory activity during 1999, including a successful well at South Timbalier 196, in which Equitable Supply 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.

 
   Years Ended
December 31,
 
   2000
   1999
 
   (in thousands except
operational data)
OPERATIONAL DATA            
Production:            
  Net sales, natural gas and equivalents (MMcfe)     6,087     26,853
  Average sales price ($/Mcfe)   $ 2.77   $ 2.34
  Lease operating expense ($/Mcfe)   $ 0.24   $ 0.25
  Selling, general, and administrative expense ($/Mcfe)   $ 0.27   $ 0.26
  Depletion   $ 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
   
 
Earnings before interest and taxes   $ 6,426   $ 14,082
   
 

        Results of operations for the Gulf in 2000 included 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.

41

NORESCO

 
   Nine Months Ended
September 30,
   Years Ended December 31,
  
 
   2002
   2001
   2001
   2000
   1999
  
 
   (in thousands except percentages)

  
OPERATIONAL DATA                                
Revenue backlog, end of period   $ 148,769   $ 142,383   $ 128,264   $ 90,978   $ 70,999  
Gross profit margin     22.8 %   23.7 %   22.0 %   24.8 %   21.5 %
Selling, general & administrative as a % of revenue     13.1 %   16.9 %   14.7 %   17.0 %   11.7 %
Development expense as a % of revenue     2.4 %   2.3 %   2.6 %   3.3 %   2.6 %
Capital expenditures   $ 635   $ 405   $ 289   $ 1,596   $ 6,041  
FINANCIAL DATA                                
Energy service contracting services   $ 136,142   $ 110,087   $ 157,379   $ 134,620   $ 169,633  
Energy service contract cost     105,070     83,965     122,790     101,266     133,088  
   
 
 
 
 
 
  Gross margin     31,072     26,122     34,589     33,354     36,545  
Operating expenses                                
  Selling, general and administrative     17,789     18,632     23,112     22,873     19,889  
Impairment of long-lived assets     5,320     —     —     —     —  
  Depreciation, depletion and amortization     1,248     4,339     5,952     5,304     6,078  
   
 
 
 
 
 
    Total operating expenses     24,357     22,971     29,064     28,177     25,967  
Operating income     6,715     3,151     5,525     5,177     10,578  
Equity earnings of nonconsolidated investments     2,660     5,778     7,555     5,109     2,863  
Earnings before interest and taxes   $ 9,375   $ 8,929   $ 13,080   $ 10,286   $ 13,441  

        Revenue backlog increased to $148.8 million for the nine-month period ended September 30, 2002 from $142.4 million at the nine-month period ended September 30, 2001. The increase in backlog occurred with respect to both energy infrastructure and performance contracting projects. A significant portion of the increase is due to a contract signed during the quarter for a large domestic energy infrastructure project located in California. Substantially all the backlog is expected to be completed within the next 18 months. Total construction completed during the nine-month period ended September 30, 2002 was $88.8 million versus $68.7 million for the nine-month period ended September 30, 2001, an increase of $20.1 million. This increase was primarily due to increased construction activity.

        Revenues increased from the nine-month period ended September 30, 2001 to the nine-month period ended September 30, 2002 by $26 million, or 23.7%, due primarily to increased construction activity from an increase in construction backlog at the beginning of 2002. Gross margins increased to $31.1 million in the nine-month period ended September 30, 2002 from $26.1 million in the nine-month period ended September 30, 2001, reflecting a demand side management program termination of $2.4 million and increases in both operations and construction activity of $2.6 million.

        Selling, general, and administrative expenses decreased $0.8 million from the nine-month period ended September 30, 2001 to the nine-month period ended September 30, 2002. Depreciation, depletion, and amortization expense decreased from the nine-month period ended September 30, 2001 to the nine-month period ended September 30, 2002 by $3.1 million, or 71%. This decrease was primarily due to the elimination of goodwill amortization resulting from FASB issued Statement No. 144.

42


        Equity earnings of nonconsolidated investments decreased from $5.8 million for the nine-month period ended September 30, 2001 to $2.7 million in the nine-month period ended September 30, 2002. The decrease in earnings was primarily due to reduced equity in earnings from power plants in Panama and Rhode Island.

        Revenue backlog increased to $128.3 million at year-end 2001 from $91.0 million at year-end 2000. The increase in backlog was 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 and due to competitive pressure. The gross margin in 1999 was 21.5%.

        Selling, general, and administrative expenses were flat from 2000 to 2001. Included in selling, general, and administrative expenses in 2001 were $1.4 million related to office consolidations in the third quarter. Included in selling, general, and administrative 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 expense increased from 2000 to 2001 by $0.6 million, or 12.2%. This increase is primarily due to increased depreciation, depletion, and amortization for power plant projects.

        Equity earnings of nonconsolidated investments of $7.6 million in 2001 and $5.1 million in 2000 reflected 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 from 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.

        Selling, general, and administrative 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 included $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 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 45% owned by the Company. A 96 mega-watt facility in Panama and a 7 mega-watt facility in Providence, Rhode Island were brought on line in late 1999.

43


Other Income Statement Items

Other Income

 
   Nine Months Ended
September 30,
   Years Ended December 31,
 
   2002
   2001
   2001
   2000
   1999
 
   (in thousands)
Other Income (loss):                              
Equity earnings (loss) of nonconsolidated investments   $ (6,936 ) $ 26,369   $ 26,101   $ 25,161   $ 2,863
Gain on sale of Westport stock     —     —     —     6,561     —
Other loss     —     —     —     (6,951 )   —
   
 
 
 
 
Total other income (loss)   $ (6,936 ) $ 26,369   $ 26,101   $ 24,771   $ 2,863

        Equity earnings of nonconsolidated investments decreased from income of $26.3 million to a loss of $6.9 million. The reduction is primarily due to reduced equity in earnings from Westport and power plants in Panama and Rhode Island.

        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 our ownership in Westport. In October 2000, Westport completed an initial public offering of its shares. We sold 1.325 million shares in this initial public offering for an after-tax gain of $4.3 million. This reduced our ownership to approximately 36% interest in Westport. On August 21, 2001, Westport completed a merger with Belco Oil & Gas. We continue to own 13.911 million shares, which currently represents approximately 21% of Westport's total shares outstanding. Our equity in Westport was $148.1 million as of December 31, 2001 with a fair market value of $241.3 million.

        On June 30, 2000, we 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, we 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.

 
   Nine Months Ended
September 30,
   Years Ended December 31,
 
   2002
   2001
   2001
   2000
   1999
 
   (in thousands)
Interest Charges   $ 28,182   $ 31,000   $ 41,098   $ 75,661   $ 37,132

        Average annual interest rates on short-term debt were 4.1%, 6.4%, and 5.2% for 2001, 2000, and 1999, respectively. For the first nine months of 2002, average annualized interest rates on short term debt were 1.8%.

        Interest costs decreased by $2.8 million in the nine-month period ended September 30, 2002 as a result of lower commercial paper borrowing rates.

44

        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 and the sale of gas properties. Interest expense also increased as a result of higher interest rates in 2000 compared to 1999.

Capital Resources and Liquidity

Operating Activities

        Cash flows provided by operating activities totaled $189.7 million, a $74.0 million increase from the $115.7 million recorded in the prior year period. The increase is primarily the result of the effect of lower commodity prices in 2002 as compared to 2001 on working capital items, including the fair value of derivative instruments, in addition to a decrease in two non-cash related items included in net income. The two items are a $29.8 million decrease in monetized production revenue that is primarily the result of the fact that ABP sales were recorded as monetized sales in 2001 but have been recorded as equity production sales in 2002, and a $24.0 million decrease in undistributed earnings from unconsolidated investments that is primarily the result of decreased earnings recognized by Westport.

        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, we 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 are 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.

45


Investing Activities

        Cash flows used in investing activities in the first nine months of 2002 were $91.2 million compared to $75.8 million for the same period in the prior year. The change from the prior year was attributable to an increase in capital expenditures of $71.8 million which is offset by a decrease in restricted cash. Capital expenditures in both years represent growth projects in the Equitable Supply segment, and replacements, improvements, and additions to plant assets in the Equitable Utilities segment. Equitable Supply and Equitable Utilities accounted for $106 million and $48 million, respectively, of the expenditures through September 30, 2002. Additionally, proceeds relating to the sale of oil-dominated fields within the Supply segment had been held in a restricted cash account at December 31, 2001 for use in a like kind exchange for certain identified assets. Subsequently, the restrictions lapsed and the cash has been made available for operations.

        On July 18, 2002, our Board of Directors increased the capital budget by $4.0 million. Specifically, the capital budget of the Supply segment was increased by $14.0 million for acceleration of a well automation project and infrastructure improvements. The Board also reduced the capital budget of NORESCO by $10.0 million. NORESCO contemplated investing this capital in domestic energy infrastructure projects, which have not materialized due to weak economic conditions.

        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 of 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.

        We 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 Supply segment, and replacements, improvements, and additions to plant assets in the Equitable Utilities and NORESCO units. Equitable Supply 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.

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

Financing Activities

        Cash flows used in financing activities during the first nine months of 2002 were $121.4 million compared to $91.7 million in the prior year period. The increase is primarily the result of a reduction in proceeds received from financial institutions associated with the transfer of contract receivables during 2002. Excluding proceeds received from the transfer of contract receivables, cash flows used in financing activities during 2002 were relatively consistent with 2001 and primarily related to our continued focus on reducing our short-term debt and purchasing shares of our outstanding common stock through the use of cash provided by operating activities.

46

        During the first quarter of 2001, a Jamaican energy infrastructure project, a consolidated subsidiary, experienced defaults relating to various loan covenants. Consequently, we reclassified the non-recourse project financing from long-term debt to current liabilities. The plant has not operated to expected levels and remediation efforts have been ineffective. As a result, in the second quarter of 2002, we reviewed the project for impairment and recognized an impairment loss of $5.3 million. We are exploring various strategic alternatives including the sale of our interest in the project.

        We have adequate borrowing capacity to meet our financing requirements. Bank loans and commercial paper, supported by available credit, are used to meet short-term financing requirements. We maintain, with a group of banks, a revolving credit agreement providing $250 million of available credit, and a 364-day credit agreement providing $250 million of available credit that expire in 2005 and 2003, respectively. As of September 30, 2002, we have the authority to arrange for a commercial paper program up to $650 million.

        We issued long-term debt in the fourth quarter of 2002 to pay down commercial paper, which has a maturity of less than 90 days. Consequently, in September 2002, we entered into interest rate swap agreements to hedge the risk of movement in interest rates from the date of the swap agreements to the date of issuance of the forecasted long-tem debt. Upon issuance of the long-tem debt, we terminated these swaps. These swap agreements were designated at inception as being cash flow hedges and were deemed to be effective.

        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, we reduced our short-term debt and bought back shares of our 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.

        We continued our 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 our 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, we repaid $75.0 million of 71/2% debentures, using cash proceeds received in 1998 from the sale of our natural gas midstream operations.

Commitments and Contingencies

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

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Benefit Plans

        Poor market conditions that have existed since 2000 have contributed to a significant reduction in the fair market value of our pension plan assets and is expected to result in additional contributions to our pension plan over the next two fiscal years. Additionally, this has contributed to a steady increase in the amount of pension expense recognized by us as a result of a lower asset base, an increase in the amount of unrecognized actuarial losses, and decreases to the expected rate of return on pension plan assets. Total pension expense recognized by the Company in 2001 excluding special termination benefits and curtailment losses totaled $3.8 million. Total pension expense expected to be recognized by the Company in 2002, exclusive of any special termination benefits and curtailment losses, totals $4.2 million and is expected to increase by over $1.5 million in 2003.

Certain Trading Activities Accounted for at Fair Value

        Below is a table that presents maturities and the fair valuation source for our derivative commodity instruments that are held for trading purposes as of September 30, 2002.

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
  
Prices actively quoted (NYMEX)   $ 2,037   $ (2,231 ) $ (105 ) $ —   $ (299 )
Prices provided by other external sources     (6,748 )   2,560     1,539     16     (2,633 )
Prices based on models and other valuation methods     (536 )   (1,932 )   (1,616 )   —     (4,084 )
   
 
 
 
 
 
Net derivative assets   $ (5,247 ) $ (1,603 ) $ (182 ) $ 16   $ (7,016 )
   
 
 
 
 
 
(1)
Contracts include futures and fixed price swaps and demand charges and other fees

Risk Management

        Our overall objective in our hedging program is to protect earnings from undue exposure to the risk of falling commodity prices. Since we are 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 our exposure to changes in natural gas commodity prices, under current market conditions management's objective is to reduce our exposure to commodity price changes to $0.005 per diluted share per $0.10 change in the average NYMEX natural gas price for 2003, between $0.025 and $0.03 per diluted share for 2004 and 2005, and less than $0.06 per diluted share for 2006 through 2008. In addition to monetizations, we use derivative instruments to hedge our exposure. We have 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

        We, within the NORESCO segment, have equity ownership interests in independent power plant projects located domestically and in selected 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. We 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. Our share of the earnings for 2001 and 2000 related to the total investment was

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$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.

        One of our two Panamanian projects is a party to a five-year power purchase agreement ("PPA") with Petroelectrica de Panama, which expires in February 2003. Coterminous with the expiration of the PPA, the debt on the project will be fully paid. We believe the project has value beyond the term of its PPA and are actively pursuing a new PPA for the project. New fixed capacity contracts are awarded each year for terms ranging from one to five years. We expect to make a decision by year-end on whether to enter into long-term off-take arrangements or sell power into the market.

        We own a 50% interest in a second Panamanian electric, generation project. This project has experienced poor financial performance during the first half of 2002 due to adverse weather (abnormally high rainfall), other adverse market-related conditions, and reduced plant availability related to planned and unplanned outages curing the first quarter. These factors temporarily depressed revenues, causing a drop below the minimum debt service coverage ratio covenant of the non-recourse loan document applicable to the project. We have been actively working with the creditor sponsor on this matter and have experienced improved operational and financial performance. We expect continued recovery by the end of 2002. Despite the debt service coverage ratio issues, cash flow and payment of debt service are expected to be adequate through 2003.

        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. We 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.

        In 2001, one of our domestic power plant projects in which we own a 50% interest, Capital Center Energy, began incurring billing disputes. The project has reserved for the amounts in dispute pending resolution of the issues. These disputed bills adversely affect the cash flows and the financial stability of the project and could trigger project loan document covenant violations, particularly if resolution of the issues are further delayed.

        In April 2000, we merged our Gulf of Mexico operations with Westport Oil and Gas Company to form Westport for $50 million in cash and approximately 49% interest in the combined company. In October 2000, Westport completed an initial public offering of its shares. We sold 1.325 million shares in this initial public offering for an after-tax gain of $4.3 million, leaving us 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.

        During 2000, Equitable Supply sold gas properties with approximately 199 Bcfe in reserves located in the Appalachian Basin region of the United States in two transactions which resulted in 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, our Board of Directors 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.

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Acquisitions and Dispositions

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

        In April 2000, we merged Equitable Production—Gulf with Westport Oil and Gas Company based in Denver, Colorado, to form Westport in exchange for $50.0 million and a 49% ownership interest in the combined entity. In October 2000, Westport completed an initial public offering in which we 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. We continue to own 13.911 million shares, which currently represents approximately 21% of Westport's total shares outstanding. Our equity in Westport was $148.1 million as of December 31, 2001. The fair market value of our investment in Westport was $241.3 million as of December 31, 2001 on a pretax basis.

        In June 2000, we 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, we 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. We account for our remaining $26.2 million investment under the equity method of accounting. We estimate that we 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, we 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 the trust. In anticipation of this transaction, we had previously entered into financial hedges. Removal of these hedges upon closing of this transaction resulted in a $57.7 million charge that was offset against the gain recognized on the sale of these properties. The proceeds received were used to pay down short-term debt associated with the Statoil acquisition. We account for its $36.2 million investment under the equity method of accounting. We estimate that we will receive $14.5 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, we entered into two prepaid natural gas sales contracts for 52.7 million cubic feet ("MMcf") of reserves. We are 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, we sold our 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 since the proceeds were escrowed while like-kind exchange transaction alternatives were evaluated.

Rate Regulation

        Accounting for the operations of our Utilities segment is in accordance with the provisions of FASB issued Statement No. 71, "Accounting for the Effects of Certain Types of Regulation."

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Schedule of Certain Contractual Obligations

        Below is a table that details the future projected payments for our significant contractual obligations as of September 30, 2002.

 
   Payments Due By Period (in thousands)
 
   Total
   2002-2003
   2004-2005
   2006-2007
   2008+
Interest expense   $ 684,247   $ 38,622   $ 57,276   $ 55,141   $ 533,208
Long-term debt     287,469     24,250     30,500     13,000     219,719
Unconditional purchase obligations     201,042     31,507     48,248     45,631     75,656
   
 
 
 
 
Total contractual cash obligations   $ 1,172,758   $ 94,379   $ 136,024   $ 113,772   $ 828,583
   
 
 
 
 

        We and our 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 through 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 our financial position or results of operations. We have identified situations that require remedial action for which approximately $8.0 million is included in other long-term liabilities at December 31, 2001.

        At the end of the useful life of a well we are 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 our profitability. 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 our 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.

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BUSINESS

        We are an integrated energy company. We focus on Appalachian area natural gas production and gathering, natural gas distribution and transmission, and the development of energy infrastructure and efficiency solutions for our customers, primarily in the northeastern section of the United States. We also have an interest in another public company with oil and gas exploration and production properties in the Gulf of Mexico and Rocky Mountain areas. Together with our subsidiaries, we 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 Supply, and NORESCO. We had 1,500 employees at the end of 2001.

        We were formed by the consolidation and merger in 1925 of two constituent companies, the older of which was organized in 1888. In 1984, we changed our name 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. During 2001, we announced our decision to focus on storage and asset management and de-emphasize low margin high volume trading revenues, which has resulted in sharply lower marketing revenues and sales volumes. Equitable Utilities generated 41% of our net operating revenues in 2001 and 41% of our net operating revenues for the first nine months of 2002.

        Equitable Utilities' distribution operations are carried out by our Equitable Gas Company division. The service territory for Equitable Gas includes southwestern Pennsylvania, municipalities in northern West Virginia and field line soles in eastern Kentucky. As of December 31, 2001, the distribution operations provided, 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.

        Equitable Utilities' interstate pipeline operations include the natural gas transmission and storage activities of Equitrans, L.P. ("Equitrans") and Carnegie Interstate Pipeline Company, both of which are regulated by the 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. We have 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.

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        The pipeline operations consist of approximately 2,700 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 MMcf per day of peak delivery capability. Equitrans has 59 Bcf of storage capacity of which 27 Bcf is working gas.

        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 our energy customers. To manage the price exposure risk of its marketing operations, we engage 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, we also engage 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.

        Our distribution rates, terms of service, contracts with affiliates and issuance of securities are regulated primarily by the Pennsylvania 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 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.

        In December 1999, we acquired the distribution, transmission, and production operations of 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.

        Various regulatory and market trends have combined to promote competition in markets served by us. 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 we have 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 our operations. Equitable Gas has responded to this competitive environment by offering a variety of firm

53

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 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. We 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 PUC to provide performance-based rates ("PBR"). On September 26, 2001, the PUC issued a final order 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.

        Our 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 Supply

        Previously, Equitable Supply was referred to as Equitable Production. We believe that this business segment will be better understood by expanding the segment's information concerning our two lines of business, production and gathering.

        Equitable Supply 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 Supply generated approximately 53% of our net operating revenues in 2001 and 51% of net operating revenues in the first nine months of 2002.

        Equitable Supply 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 Supply currently owns 7,184 net producing wells in Appalachia. As of December 31, 2001, we estimate the total proved reserves to be 2,082 Bcfe, including undeveloped reserves of 583 Bcfe.

        The areas in which our Appalachian properties are located are characterized by wells with comparatively low rates of annual decline in production, low production costs, and high 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, we 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 our 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 from these zones may be mixed or commingled. Commingled production lowers producing costs on a per unit basis compared to isolated zone completions.

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        In the Appalachian Region during 2001, Equitable Supply 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. During the first two quarters of 2002, Equitable Supply drilled 196 gross wells at a success rate of 100% in the Appalachian Region.

        Equitable Supply currently has an inventory of 3.6 million gross acres of which approximately 71% has not been developed. As of December 31, 2001, we 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 Supply 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 Supply business segment. On February 13, 2002, the FERC approved the order that resulted in the transfer of gathering systems. The transfer was 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 Supply.

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

        In February 2000, we 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 Bcf of proven natural gas reserves and 6,500 gross natural gas wells in West Virginia, Kentucky, Virginia, Pennsylvania, and Ohio.

        In April 2000, we merged Statoil's Gulf of Mexico operations with Westport Oil and Gas Company to form Westport for $50 million in cash and 15.236 million shares or approximately 49% interest in the combined company. In October 2000, Westport completed an initial public offering of its shares. Equitable sold 1.325 million shares in this for an after-tax gain of $4.3 million. This reduced our ownership to approximately 36% interest in Westport. On August 21, 2001, Westport completed a merger with Bellco Oil & Gas Company. We continue to own 13.911 million shares, which currently represents approximately 21% of Westport's total shares outstanding. The book value of our equity in Westport was $148.1 million as of December 31, 2001.

        In June 2000, we 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, we 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. We account for our remaining $26.2 million investment under the equity method of accounting. During 2001 and 2000, we 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, we estimate that we 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, we 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, we had previously entered into financial hedges. Removal of these

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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. We account for our $36.2 million investment under the equity method of accounting. During 2001, we 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, we estimate that we 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, we entered into two prepaid natural gas sales contracts for a total of approximately 52.7 MMcf of reserves. We are 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, we sold our 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 since the proceeds were escrowed while like-kind exchange transaction alternatives were evaluated. Although we will no longer operate these properties, we will continue to gather and market the natural gas produced, which resulted in approximately $0.8 million in service revenue through the first two quarters of 2002.

        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 3,000 independent operators and 90,000 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.

        We have historically entered into hedging contracts with respect to forecasted natural gas production at specified prices for a specified period of time. Our hedging strategy and information regarding derivative instruments used are outlined in the Risk Factors section.

NORESCO

        NORESCO provides an integrated group of energy-related products and services in the United States, Panama, Jamaica, and Costa Rica 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 our net operating revenues in 2001 and 8% of our net operating revenues in the first nine months of 2002.

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        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.

        In April 2000, we merged our Gulf of Mexico operations with Westport Oil and Gas Company to form Westport for $50 million in cash and approximately 49% interest in the combined company. In October 2000, Westport completed an initial public offering of its shares. We sold 1.325 million shares in this initial public offering for an after-tax gain of $4.3 million, leaving us 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 and Gas. We continue to own 13.911 million shares, which currently represents approximately 21% of Westport's total shares outstanding. The fair market value of our investment in Westport was $241.3 million as of December 31, 2001.

        Within the NORESCO segment, we have equity ownership interests in independent power plant projects located domestically and in selected international countries. Long-term power purchase agreements are signed with the customer whereby it agrees to purchase the energy generated by the plant. The length of these contracts ranges from 5 to 30 years. We 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. Our 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.

        In 2001, one of our domestic power plant projects in which we own a 50% interest, Capital Center Energy, began incurring billing disputes. The project has reserved for the amounts in dispute pending resolution of the issues. These disputes adversely affect the cash flows and the financial stability of the project and could trigger project loan document covenant violations, particularly if resolution of the issues are further delayed.

        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. We 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 electric generation project. The project had previously agreed to retrofit a plant to conform to environmental noise standards by a target date of

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August 31, 2001. Unforeseen events delayed the final completion date of the required retrofits. The project has obtained an extension from the Panamanian regulators while it evaluates a land acquisition/rezoning proposal, which, if accepted and executed, would obviate the retrofit requirement. The creditor sponsor continues to evaluate the land acquisition/rezoning proposal while concurrently exploring the feasibility of a final technical resolution to the noise issues. We are coordinating with the creditor sponsor to obtain any additional regulatory extension, which may be required.

        During 2000, Equitable Supply sold gas properties with approximately 199 Bcfe in reserves located in the Appalachian Basin region of the United States in two transactions which resulted in 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, our Board of Directors 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.

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MANAGEMENT

        The table below sets forth the names, ages, and positions held by our executive officers and Board of Directors:

Name
   Age
   Title
Murry S. Gerber   49   Director; Chairman of the Board of Directors; President; Chief Executive Officer
David L. Porges   45   Director; Executive Vice President; Chief Financial Officer
Johanna G. O'Loughlin   56   Senior Vice President; General Counsel; Corporate Secretary
James M. Funk   53   Senior Vice President; President, Equitable Production Company
Gregory R. Spencer   54   Senior Vice President; Chief Administrative Officer
Joseph E. O'Brien   50   Vice President; President, NORESCO
Philip P. Conti   43   Vice President, Finance; Treasurer
Arthur G. Cantrell   45   Vice President; President, Equitrans
Randall L.Crawford   40   Vice President; President, Equitable Gas Company
John A. Bergonzi   50   Vice President; Corporate Controller; Chief Accounting Officer
Charlene Petrelli   41   Vice President, Human Resources
Phyllis A. Domm, Ed.D   55   Director
Barbara S. Jeremiah   51   Director
E. Lawrence Keyes, Jr.   73   Director
Thomas A. McConomy   69   Director
George L. Miles, Jr   61   Director
Malcolm M. Prine   74   Director
James E. Rohr   54   Director
David S. Shapira   61   Director

        Set forth below is certain biographical information with respect to our executive officers and directors.

        Mr. Gerber has been Chairman of the Board of Directors, President, and Chief Executive Officer since May 2000 and served as President and Chief Executive Officer from June 1998 through April 2000. He has been a Director since May 1998 and is a member of the Executive Committee. Mr. Gerber served as Chief Executive Officer of Coral Energy, L.P. (an energy marketing and services company) from November 1995 through May 1998. He is also a Director of Westport Resources Corporation and BlackRock, Inc.

        Mr. Porges has been Executive Vice President and Chief Financial Officer since February 2000 and served as Senior Vice President and Chief Financial Officer from July 1998 through January 2000. He has been a Director since May 2002. Mr. Porges served as Managing Director of Bankers Trust Company (financial services company) from December 1992 through June 1998. He is also a Director of Westport Resources Corporation.

        Ms. O'Loughlin has been Senior Vice President, General Counsel, and Corporate Secretary since January 2002. She previously served as Vice President, General Counsel, and Secretary from May 1999 through December 2001 and Vice President and General Counsel from December 1996 through April 1999.

        Mr. Funk has been Senior Vice President since July 2000 and President of Equitable Production Company since June 2000. He served as President of J.M. Funk & Associates, Inc. from January 1999

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through May 2000, President of Shell Continental Companies from January 1998 through December 1998 and President and Chief Executive Officer of Shell Midstream Enterprises, Inc. from April 1996 through December 1997.

        Mr. Spencer has been Senior Vice President and Chief Administrative officer since May 1996. Mr. Spencer will be retiring in the second quarter of 2003.

        Mr. O'Brien has been Vice President since January 2001. He previously served as President of Northeast Energy Services, Inc. from January 2000 through December 2000 and Senior Vice President of Construction & Engineering from June 1993 through December 1999.

        Mr. Conti has been Vice President, Finance, and Treasurer since August 2000. He previously served as Director of Planning and Development from June 1998 through July 2000 and Assistant Treasurer-Finance from January 1996 through May 1998.

        Mr. Cantrell has been Vice President and President, Equitrans since January 2003. He previously served as Executive Vice President-Utilities segment. Mr. Cantrell joined Equitable Resources in 1996 and has over 15 years of experience in the natural gas industry.

        Mr. Crawford has been a Vice President and President, Equitable Gas Company since January 2003. He previously served as Executive Vice President-Utilities segment. Mr. Crawford joined Equitable Resources in 1996 and has more than 11 years of natural gas industry experience.

        Mr. Bergonzi has been Vice President since January 2003 and Corporate Controller since 1996. He joined Equitable Resources in 1977 and has served in a variety of financial management positions.

        Ms. Petrelli has been Vice President, Human Resources since January 2003. She previously served as Director, Corporate Human Resources. Ms. Petrelli joined Equitable Resources in 2000 and, prior to joining Equitable Resources, she held various Human Resources positions at Fisher Scientific, Merck, and Johnson & Johnson.

        Dr. Domm has been a Director since May 1996 and is a member of the Audit and Compensation Committees. She has been Vice President, Human Resources of Intermountain Health Care (health care services) since June 2000. Dr. Domm previously served as Vice President, Human Resources of MedStar Health (health care services) from March 1998 through May 2000, President of Management and Marketing Solutions, Inc. (marketing, public relations and human resources consulting) from July 1997 through March 1998, and Senior Vice President-Health Care Services at Intracoastal Health Systems, Inc. from April 1995 though June 1997.

        Ms. Jeremiah has been a Director since February 2003. She has been Executive Vice President—Corporate Development of Alcoa (aluminum producer) since July 2002 and currently is a member of the Alcoa Executive Council. Ms. Jeremiah previously served as Vice President of Corporate Development from 1998 through 2002, Assistant General Counsel from 1992 to 1998, and from 1977 to 1991 served in various roles as an attorney in the Alcoa legal department. Ms. Jeremiah currently serves as a Director of the Women's Center and Shelter of Greater Pittsburgh and the Pittsburgh Ballet Theatre.

        Mr. Keyes has been a Director since May 1988 and is a member of the Compensation Committee. He has been a Partner at the Fortune Group, LLC (management consulting and investment banking firm) since January 1987.

        Mr. McConomy has been a Director since May 1991 and is a Chairman of the Corporate Governance Committee and a member of the Compensation Committee. He has been a Director of Calgon Carbon Corporation (manufacturer and marketer of activated carbon and related products and services) since April 1985. Mr. McConomy previously served as the Chairman of the Board at Calgon

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Carbon Corporation from April 1985 through April 1999 and Interim President and Chief Executive Officer of Calgon Carbon Corporation from February 1998 through April 1999.

        Mr. Miles has been a Director since July 2000 and is a member of the Audit and Corporate Governance Committees. He has been President and Chief Executive Officer of WQED Pittsburgh (public broadcasting) since 1994. Mr. Miles also serves as a Director of WESCO International, Inc.

        Mr. Prine has been a Director since May 1982 and is Chairman of the Audit Committee and a member of the Corporate Governance and Executive Committees. He has been Chairman of the Board of Directors for Core Materials Corp. (manufacturer of plastics molding) since January 1997 and President of Malcar, Inc. since 1990.

        Mr. Rohr has been a Director since May 1996 and is Chairman of the Executive Committee and a member of the Compensation Committee. He has been Chairman of the Board of Directors, President and Chief Executive Officer of PNC Financial Services Group, Inc. (financial services company) since May 2001. Mr. Rohr previously served as President, Chief Executive Officer, and Director of PNC Financial Services Group, Inc. from May 2000 through May 2001, President and Chief Operating Officer of PNC Financial Services Group, Inc. from April 1998 through April 2000, and President of PNC Bank Group Corp. (the predecessor of PNC Financial Services Group, Inc.) from January 1992 through March 1998. He is also a Director of Allegheny Technologies, Inc., BIackRock, Inc., and Water Pik Technologies, Inc.

        Mr. Shapira has been a Director since May 1987 and is a member of the Audit and Executive Committees. He has been Chairman and Chief Executive Officer of Giant Eagle, Inc. (retail grocery store chain) since February 1994. Mr. Shapira is also a Director of Mellon Financial Corporation.

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DESCRIPTION OF OTHER INDEBTEDNESS

Credit Facilities

        We maintain a three year unsecured revolving credit facility and a 364-day unsecured revolving credit facility to support our commercial paper program and to fund our working capital and capital expenditure needs. Each facility is in the amount of $250 million and both facilities require that our consolidated debt to capital ratio not exceed 65%. We have never borrowed under these facilities. The three year facility expires in November 2005 and the 364-day facility expires in November 2003.

Debentures and Medium Term Notes

        The following debt instruments are issued and outstanding as of the date of this prospectus:

        The 73/4% debentures were issued under the same indenture under which the notes offered in this prospectus are to be issued and are subject to the same covenants, defaults, and other terms applicable to the notes offered by this prospectus.

        The Series A, Series B, and Series C medium term notes were issued pursuant to an indenture between us and Bankers Trust Company, as trustee, dated as of April 1, 1983. The Bankers Trust indenture does not have any restrictions on additional funded indebtedness or other covenants that would be impacted by the issuance of the notes offered by this prospectus.

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DESCRIPTION OF EXCHANGE NOTES

        The following description is only a summary of certain provisions of the Indenture and the exchange notes, copies of which are available upon request to us at the address set forth under "Where You Can Find More Information." In this summary, the term Equitable refers only to Equitable Resources, Inc. and not to any of its subsidiaries or affiliates. You can find the definitions of capitalized terms used in this description under the subheading "Certain Definitions." Certain defined terms used in this description but not defined below under "Certain Definitions" have the meanings assigned to them in the Indenture. We urge you to read the Indenture and the exchange notes, together with the registration rights agreement, because they, and not this description, define your rights as holders of the exchange notes.

General

        The exchange notes are to be a series of debt securities issued under an Indenture, dated as of July 1, 1996 (the "Indenture") between Equitable and The Bank of New York (as successor to Bank of Montreal Trust Company), as Trustee (the "Trustee").

        The exchange notes will mature on November 15, 2012. Interest on the exchange notes will accrue at the rate of 5.15% per year and will be payable semi-annually in arrears on each May 15, and November 15, commencing on May 15, 2003. Equitable will make each interest payment to the holders of record of the exchange notes on the immediately preceding May 1 and November 1. The interest rate on the exchange notes is subject to increase in certain circumstances relating to the registration of the exchange notes. The registered holder of a exchange note will be treated as the owner of it for all purposes. Only registered holders will have rights under the Indenture. In anticipation of the offering of the exchange notes Equitable entered into interest rate hedging arrangements on September 23, 2002 which had the economic effect of fixing our interest rate with respect to $200,000,000 of notes at approximately 5.9%.

        The exchange notes will be senior, unsecured obligations of Equitable and will rank on a parity with all of Equitable's other outstanding unsecured and unsubordinated indebtedness. The exchange notes will be represented by Global Securities, which will be deposited with, or on behalf of, The Depository Trust Company, New York, New York, and registered in the name of DTC's nominee. Each note represented by a Global Security is referred to herein as a "Book-Entry Note."

        The Indenture does not limit the amount of exchange notes or other debt securities of Equitable that may be issued under the Indenture. Equitable has issued, and is permitted to continue to issue, additional series of debt securities under the Indenture. Equitable may also at any time and from time to time, without notice to or consent of the holders, issue additional debt securities of the same tenor, coupon and other terms as the exchange notes so that such debt securities and the exchange notes offered pursuant to this prospectus shall form a single series. References herein to the exchange notes shall include (unless the context otherwise requires) any further exchange notes issued as described in this paragraph.

        Unless otherwise provided and except with respect to Book-Entry Notes, principal of and premium, if any, and interest, if any, on the exchange notes will be payable, and the transfer of exchange notes will be registrable, at the Corporate Trust Office of the Trustee, except that, at the option of Equitable, interest may be paid by mailing a check to, or by wire transfer to, the holders of the exchange notes entitled thereto. For a description of payments of principal of, and premium, if any, and interest on, and transfer of, Book-Entry Notes, and exchanges of Global Securities representing Book-Entry Notes, see "Book-Entry, Delivery, and Form."

        The exchange notes will be issued only in fully registered form without coupons and only in denominations of $1,000 and any integral multiple of $1,000. No service charge will be made for any registration of transfer or exchange of the exchange notes, but Equitable may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith.

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Optional Redemption

        We may redeem the exchange notes, in whole or in part, at any time or from time to time at a redemption price equal to the greater of:

        For purposes of determining the optional redemption price, the following definitions are applicable:

        "Treasury Rate" means, with respect to any redemption date for the exchange notes,

The Treasury Rate will be calculated on the third business day preceding the redemption date.

        "Comparable Treasury Issue" means the U.S. Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term ("remaining life") of the exchange notes that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining terms of the exchange notes.

        "Comparable Treasury Price" means, with respect to any redemption date:

        "Independent Investment Banker" means either Banc of America Securities LLC or J.P. Morgan Securities Inc., as specified by us, or if these firms are unwilling or unable to select the applicable Comparable Treasury Issue, an independent investment banking institution of national standing appointed by us.

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        "Reference Treasury Dealer" means (1) Banc of America Securities LLC and J.P. Morgan Securities Inc. (and their respective successors), provided however, that if either of the foregoing shall cease to be a primary U.S. government securities dealer (a "Primary Treasury Dealer"), we will substitute therefore another Primary Treasury Dealer and (2) any other Primary Treasury Dealer selected by us after consultation with the Independent Investment Banker.

        "Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any redemption date for the exchange notes, an average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue for the exchange notes (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

        Notice of any redemption will be mailed at least 30 days but not more than 60 days before the redemption date to each registered holder of exchange notes to be redeemed. Unless we default in payment of the redemption price, on and after the redemption date, interest will cease to accrue on the exchange notes or portions of the exchange notes called for redemption. If fewer than all of the exchange notes are to be redeemed, the Trustee will select, not more than 60 days prior to the redemption date, the particular exchange notes or portions thereof for redemption from the outstanding exchange notes not previously called by such method as the Trustee deems fair and appropriate.

        Except as set forth above, the exchange notes will not be redeemable by the Company prior to maturity and will not be entitled to the benefit of any sinking fund.

Certain Covenants

        The Indenture contains certain covenants, including, among others, those described below. Except as set forth below, Equitable will not be restricted by the Indenture from incurring any type of indebtedness or other obligation, from paying dividends or making distributions on its capital stock or purchasing or redeeming its capital stock. In addition, the Indenture does not contain any provisions that would require Equitable to repurchase or redeem or otherwise modify the terms of any of the exchange notes upon a change in control or other events involving Equitable which may adversely affect the creditworthiness of the exchange notes.

        The Indenture provides that Equitable will not, and will not permit any Restricted Subsidiary to, issue, assume or guarantee any Debt which is secured by a mortgage, pledge, security interest or lien (any mortgage, pledge, security interest or lien being hereinafter referred to as a "lien" or "liens") upon any Principal Property of Equitable or of any Restricted Subsidiary or upon any shares of stock or Debt issued by any Restricted Subsidiary, whether now owned or hereafter acquired, without effectively providing that the exchange notes (together with, if Equitable so determines, any other indebtedness of or guaranty by Equitable or such Restricted Subsidiary then existing or thereafter created which is not subordinated to the exchange notes) will be secured equally and ratably with (or at Equitable's option, prior to) such secured Debt so long as such Debt is so secured; provided, however, that the foregoing will not restrict or apply to Debt secured by:

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provided, that such extension, renewal or replacement lien is limited to all or any part of the same property that secured the lien extended, renewed for replaced (plus any improvements and construction on such property) and will secure at the time of such extension, renewal or replacement no larger

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amount of Debt and, in the case of the fourth bullet above, that the Debt being secured thereby is being secured for the same type of Person as the Debt being replaced; and liens not permitted by the preceding bullets if at the time incurring such lien, the aggregate amount of the related Debt plus all other Debt of Equitable and its Restricted Subsidiaries secured by liens which would otherwise be subject to the foregoing restrictions after giving effect to the retirement of any Debt which is currently being retired (not including Debt permitted to be secured under the preceding bullets), plus the aggregate Attributable Debt (determined as of the time of incurring such lien) of Sale and Leaseback Transactions (other than Sale and Leaseback Transactions permitted by the first two bullets below) and in existence at the time of incurring such lien (less the aggregate amount of proceeds of such Sale and Leaseback Transactions which has been applied) in accordance with the third bullet below), does not exceed 10% of Consolidated Net Tangible Assets.

        The Indenture further provides that Equitable will not, and will not permit any Restricted Subsidiary to, enter into any arrangement with any bank, insurance company or other lender or investor (other than Equitable or another Restricted Subsidiary) providing for the leasing as lessee by Equitable or a Restricted Subsidiary of any Principal Property (except a lease for a term not to exceed three years by the end of which term it is intended that the use of such Principal Property by the lessee will be discontinued and a lease which secures or relates to industrial revenue or pollution control bonds or similar, financing), which was or is owned by Equitable or a Restricted Subsidiary and which has been or is to be sold or transferred by Equitable or a Restricted Subsidiary to such Person more than 180 days after the completion of construction and commencement of full operation of such property by Equitable or such Restricted Subsidiary, to such lender or investor or to any Person to whom funds have been or are to be advanced by such lender or investor on the security of such Principal Property (herein referred to as a "Sale and Leaseback Transaction"), unless:

provided, that the amount to be so applied will be reduced by (x) the principal amount of exchange notes delivered to the Trustee for retirement and cancellation within 180 days after such sale or transfer, and (y) the principal amount of any such Debt of Equitable or a Restricted Subsidiary other

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than the exchange notes voluntarily retired by Equitable or a Restricted Subsidiary within 180 days after such sale or transfer.

        Notwithstanding the foregoing, no retirement referred to in the third bullet above may be effected by payment at Maturity.

        Equitable may not consolidate with or merge into any other Person or convey, transfer or lease its properties and assets substantially as an entirety to any Person and Equitable may not permit any Person to consolidate with or merge into Equitable, unless:

Certain Definitions

        Certain terms used in this description are defined in the Indenture as follows:

        "Attributable Debt" in respect of a Sale and Leaseback Transaction means, as of any particular time, the present value (discounted at the rate of interest implicit in the terms of the lease involved in such Sale and Leaseback Transaction, as determined in good faith by Equitable) of the obligation of the lessee thereunder for net rental payments (excluding, however, any amounts required to be paid by such lessee, whether or not designated as rent or additional rent, on account of maintenance and repairs, services, insurance, taxes, assessments, water rates or similar charges and any amounts required to be paid by such lessee thereunder contingent upon monetary inflation or the amount of sales, maintenance and repairs, insurance, taxes, assessments, water rates or similar charges) during the remaining term of such lease (including any period for which such lease has been extended or may, at the option of the lessor, be extended).

        "Consolidated Net Tangible Assets" means the aggregate amount of assets of Equitable and its consolidated Subsidiaries (less applicable reserves) after deducting therefrom (a) all goodwill, trade names, trademarks, patents, unamortized debt discount and expense and other like intangibles and (b) all current liabilities except for current maturities of long-term debt, current maturities of capitalized lease obligations, indebtedness for borrowed money having a maturity of less than

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12 months from the date of the most recent audited consolidated balance sheet of Equitable, but which by its terms is renewable or extendable beyond 12 months from such date at the option of the borrower, and deferred income taxes which are classified as current liabilities, all as reflected in the audited consolidated balance sheet contained in Equitable's most recent annual report to its shareholders under Rule 14a-3 of the Exchange Act, prior to the time as of which "Consolidated Net Tangible Assets" is being determined.

        "Debt" means indebtedness for borrowed money.

        "Person" means, except as provided in the Indenture, any individual, corporation, partnership, joint venture, trust, unincorporated organization or government or any agency or political subdivision thereof.

        "Principal Property" means any manufacturing plant or production, transportation or marketing facility or other similar facility located within the United States (other than its territories and possessions) and owned by, or leased to, Equitable or any Restricted Subsidiary, the book value of the real property, plant, and equipment of which (as shown, without deduction of any depreciation reserves, on the books of the owner or owners) is not less than 1.5% of Consolidated Net Tangible Assets as of the date on which such facility is acquired or a leasehold interest therein is acquired.

        "Restricted Subsidiary" means any Subsidiary substantially all the property of which is located, or substantially all the business of which is carried on, within the United States (other than its territories and possessions) which shall at the time, directly or indirectly, through one or more Subsidiaries or in combination with one or more other Subsidiaries or Equitable, own or be a lessee of a Principal Property.

        "Subsidiary" means, with respect to Equitable, a corporation of which more than 50% of the total voting power of the capital stock entitled (without regard to the occurrence of any contingency) to vote in the election of its directors is owned, directly or indirectly, by Equitable or by one or more other Subsidiaries or by Equitable and one or more other Subsidiaries.

Events of Default

        An Event of Default with respect to the exchange notes is defined in the Indenture as:

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        The Indenture provides that, if any Event of Default with respect to the exchange notes occurs and is continuing, either the Trustee or the holders of not less than 25% in principal amount of the exchange notes may declare the principal amount of (and all accrued and unpaid interest on) all exchange notes to be due and payable immediately, but under certain conditions such declaration may be rescinded and annulled and past defaults (except, unless theretofore cured, a default in payment of principal of or premium, if any, or interest, if any, on the exchange notes and certain other specified defaults) may be waived by the holders of not less than a majority in principal amount of the exchange notes on behalf of the holders of all the exchange notes.

        The Indenture provides that if a default occurs under the Indenture with respect to the exchange notes, the Trustee will give the holders of the exchange notes notice of such default as and to the extent provided by the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act"); provided, however, that such notice will not be given until at least 30 days after the occurrence of that default if that default is in the performance of a covenant in the Indenture other than for the payment of the principal of or premium, if any, or interest on the exchange notes or the deposit of any sinking fund payment with respect to the exchange notes. For the purpose of the provision described in this paragraph, the term default with respect to any exchange notes means any event which is, or after notice or lapse of time or both would become, an "Event of Default" specified in the Indenture with respect to the exchange notes.

        The Indenture contains a provision entitling the Trustee to be indemnified by holders of the exchange notes before proceeding to exercise any right or power vested in it under the Indenture at the request or direction of the holders of the exchange notes. The Trustee is required, during a default, to act with the standard of care provided in the Trust Indenture Act. The Indenture provides that the holders of a majority in principal amount of the exchange notes may direct the time, method, and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee with respect to the exchange notes; provided, that the Trustee may decline to act if:

Modification and Waiver

        Modifications and amendments may be made by Equitable and the Trustee to the Indenture, without the consent of any holder of the exchange notes, to add covenants and Events of Default and to make provisions with respect to other matters and issues arising under the Indenture, provided that any such provision does not adversely affect the rights of the holders of the exchange notes in any material respect.

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        The Indenture contains provisions permitting Equitable and the Trustee, with the consent of the holders of not less than 662/3% in principal amount of the exchange notes to execute supplemental indentures adding any provisions to or changing or eliminating any of the provisions of the Indenture or modifying the rights of the holders of the exchange notes, except that no such supplemental indenture may, without the consent of the holder of each note affected thereby,

        The Indenture also permits Equitable to omit compliance with certain covenants in the Indenture with respect to the exchange notes upon waiver by the holders of not less than 662/3% in principal amount of the exchange notes.

Discharge or Defeasance

        The Indenture will cease to be of further effect (except as to any surviving rights for the registration of the transfer or exchange of exchange notes expressly provided for in the Indenture) if:

        The Indenture provides that the terms of the exchange notes may provide Equitable with the option to discharge its indebtedness represented by such exchange notes or to cease to be obligated to comply with certain covenants under the Indenture. Equitable, in order to exercise such option, will be required to deposit with the Trustee money and/or U.S. Government Obligations which, through the payment of interest and principal in respect thereof in accordance with their terms, will provide money in an amount sufficient, in the opinion of a nationally recognized firm of independent public accountants expressed in a written certification delivered to the Trustee, to pay the principal of and premium, if any, and interest on, and any mandatory sinking fund payments in respect of, the exchange

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notes at the stated maturity of such payments in accordance with the terms of the Indenture and such exchange notes. Such trust may only be established if:

        In the event Equitable exercises this option and the exchange notes are declared due and payable because of the occurrence of any Event of Default, the amount of money and U.S. Government Obligations, as the case may be, on deposit with the Trustee will be sufficient to pay the amounts due on the exchange notes at the time of their maturity "abut may not be sufficient to pay the amounts due on the exchange notes at the time of the acceleration resulting from such Event of Default. However, Equitable will remain liable for such payments.

Trustee

        The Trustee may resign or be removed with respect to the exchange notes and a successor trustee may be appointed to act with respect to such exchange notes. In the event that two or more persons are acting as trustee with respect to different series of Notes, each such trustee will be a trustee of a trust under the Indenture separate and apart from the trust administered by any other such trustee, and any action described herein to be taken by the "Trustee" under the Indenture may then be taken by each such trustee with respect to, and only with respect to, the one or more series of Notes for which it is trustee.

Book-Entry, Delivery, and Form

        The exchange notes will be issued in registered, global form in minimum denominations of $1,000 and integral multiples of $1,000 in excess of $1,000. The exchange notes will be represented by one or more exchange notes in registered, global form without interest coupons (collectively, the "Global Notes"). The Global Notes will be deposited upon issuance with the Trustee as custodian for DTC, in New York, New York, and registered in the name of DTC or its nominee, in each case to an account of a direct or indirect participant in DTC as described below.

        Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for exchange notes in certificated form except in the limited circumstances

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described below. See "Exchange of Global Notes for Certificated Notes." Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of exchange notes in certificated form.

        In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

        The following description of the operations and procedures of DTC, Euroclear, and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. Equitable takes no responsibility for these operations and procedures and urges investors to contact the system or their participants directly to discuss these matters.

        DTC has advised Equitable that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the "Participants") and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations, and certain other organizations. Access to DTC's system is also available to other entities such as banks, brokers, dealers, and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the "Indirect Participants"). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

        DTC has also advised Equitable that, pursuant to procedures established by it:

        Investors in the Global Notes who are Participants in DTC's system may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants in such system. Euroclear and Clearstream will hold interests in the Global Notes on behalf of their participants through customers' securities accounts in their respective names on the books of their respective depositories, which are Euroclear Bank S.A./N.V., as operator of Euroclear, and Citibank, N.A., as operator of Clearstream. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems. The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

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        Except as described below, owners of interest in the Global Notes will not have exchange notes registered in their names, will not receive physical delivery of exchange notes in certificated form and will not be considered the registered owners or "holders" thereof under the indenture for any purpose.

        Payments in respect of the principal of, and interest and premium on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the Indenture. Under the terms of the Indenture, Equitable and the Trustee will treat the Persons in whose names the exchange notes, including the Global Notes, are registered as the owners of the exchange notes for the purpose of receiving payments and for all other purposes. Consequently, neither Equitable, the Trustee nor any agent of Equitable or the Trustee has or will have any responsibility or liability for:

        DTC has advised Equitable that its current practice, upon receipt of any payment in respect of securities such as the exchange notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of exchange notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee or Equitable. Neither Equitable nor the Trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the exchange notes, and Equitable and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

        Subject to the transfer restrictions set forth under "Notice to Investors," transfers between Participants in DTC will be effected in accordance with DTC's procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

        Subject to compliance with the transfer restrictions applicable to the exchange notes described herein, cross-market transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC's rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream.

        DTC has advised Equitable that it will take any action permitted to be taken by a holder of exchange notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount

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of the exchange notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the exchange notes, DTC reserves the right to exchange the Global Notes for legended exchange notes in certificated form, and to distribute such exchange notes to its Participants.

        Although DTC, Euroclear, and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Rule 144A Global Notes and the Regulation S Global Notes among participants in DTC, Euroclear, and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. Neither Equitable nor the Trustee nor any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Exchange Notes

        A Global Note is exchangeable for definitive exchange notes in registered certificated form ("Certificated Exchange Notes") if:

        In addition, beneficial interests in a Global Note may be exchanged for Certificated Exchange Notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the Indenture. In all cases, Certificated Exchange Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend referred to in "Notice to Investors," unless that legend is not required by applicable law.

Exchange of Certificated Exchange Notes for Global Notes

        Certificated Exchange Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the Trustee a written certificate (in the form provided in the Indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such exchange notes. See "Notice to Investors."

Same Day Settlement and Payment

        Equitable will make payments in respect of the exchange notes represented by the Global Notes (including principal, premium, if any, interest, and additional interest, if any) by wire transfer of immediately available funds to the accounts specified by the Global Note holder. Equitable will make all payments of principal, interest, and premium, with respect to Certificated Exchange Notes by wire transfer of immediately available funds to the accounts specified by the holders of the Certificated Exchange Notes or, if no such account is specified, by mailing a check to each such Holder's registered

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address. The exchange notes represented by the Global Notes are expected to trade in DTC's Same-Day Funds Settlement System, and any permitted secondary market trading activity in such exchange notes will, therefore, be required by DTC to be settled in immediately available funds. Equitable expects that secondary trading in any Certificated Exchange Notes will also be settled in immediately available funds.

        Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant in DTC will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised Equitable that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC's settlement date.

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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

        The following discussion is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), applicable Treasury regulations, judicial authority, and administrative rulings and practice as of the date hereof. The Internal Revenue Service (the "IRS") may take a contrary view, and no ruling from the IRS has been or will be sought. Legislative, judicial or administrative changes or interpretations may be forthcoming that could alter or modify the following statements and conditions. Any changes or interpretations may or may not be retroactive and could affect the tax consequences to holders. The discussion does not address all the tax consequences that may be relevant to a particular holder or to certain holders subject to special treatment under U.S. federal income tax laws (including, but not limited to, certain financial institutions, tax-exempt organizations, insurance companies, broker-dealers, and persons that have a functional currency other than the U.S. Dollar or persons in special circumstances, such as those who have elected to mark securities to market or those who hold exchange notes as part of a straddle, hedge, conversion transaction, or other integrated investment).

        The exchange of the original notes for exchange notes pursuant to the exchange offer will not be treated as an "exchange" for federal income tax purposes because the exchange notes will not be considered to differ materially in kind or extent from the original notes. Rather, the exchange notes received by a holder will be treated as a continuation of the original notes in the hands of such holder. As a result, there will be no federal income tax consequences to holders exchanging original notes for exchange notes pursuant to the exchange offer. The foregoing is based upon the Code, the Treasury Department regulations promulgated or proposed thereunder and administrative and judicial interpretations thereof, all as of the date hereof and all of which are subject to change, possibly on a retroactive basis. We have not sought any ruling from the IRS with respect to the statements made and the conclusions reached in this summary, and we cannot assure you that the IRS will agree with such statements and conclusions.

        We recommend that each holder consult his own tax advisor as the particular tax consequences of exchanging such holder's original notes for exchange notes, including the applicability and effect of any state, local or foreign tax law.

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PLAN OF DISTRIBUTION

        Each broker-dealer that receives exchange notes for its own account in the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of exchange notes. Broker-dealers may use this prospectus, as it may be amended or supplemented from to time, in connection with resales of exchange notes received in exchange for original notes if the broker-dealer acquired the original notes as a result of market-making activities or other trading activities. We have agreed that for a period of 180 days after the effective date of the registration statement of which this prospectus is a part we will make this prospectus, as amended or supplemented, available to any broker-dealer who requests it in the letter of transmittal for use in connection with any such resale. In addition, until October 13, 2003, all dealers effecting transactions in the exchange notes may be required to deliver a prospectus.

        We will not receive any proceeds from any sale of exchange notes by broker-dealers or other persons. Broker-dealers may from time to time sell exchange notes received for their own accounts in the exchange offer in one or more transactions:

        Broker-dealers may resell exchange notes directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer and/or the purchasers of the exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of the exchange notes may be deemed to be "underwriters" within the meaning of the Securities Act, and any profit on any resale of exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

        We have agreed to pay all expenses incident to our performance of, or compliance with, the registration rights agreement and will indemnify the holders of the notes (including any broker-dealers) against liabilities under the Securities Act.

        By its acceptance of the exchange offer, any broker-dealer that receives exchange notes pursuant to the exchange offer agrees to notify us in writing before using the prospectus in connection with the sale or transfer of exchange notes. The broker-dealer further acknowledges and agrees that, upon receipt of notice from us of the happening of any event which makes any statement in the prospectus untrue in any material respect or which requires the making of any changes in the prospectus to make the statements in the prospectus not misleading or which may impose upon us disclosure obligations that my have a material adverse effect on us, which notice we agree to deliver promptly to the broker-dealer, the broker-dealer will suspend use of the prospectus until we have notified the broker-dealer that delivery of the prospectus may resume and have furnished to the broker-dealer copies of any amendment or supplement to the prospectus. We have agreed in the registration rights agreement that for a period of 180 days after the effective date of the registration statement of which this prospectus is

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a part we will make this prospectus, as amended or supplemented, available to any broker-dealer who requests it in writing for use in connection with any such resale.


LEGAL MATTERS

        Certain legal matters in connection with the notes will be passed upon for us by Reed Smith LLP, Pittsburgh, Pennsylvania.


EXPERTS

        The consolidated financial statements of Equitable Resources, Inc. at December 31, 2001 and 2000 and for each of the three years in the period ended December 31, 2001, incorporated by reference in this prospectus and registration statement, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon incorporated by reference herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

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EQUITABLE
RESOURCES

        If you are a broker-dealer that receives exchange notes for your own account as a result of market-making or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any resale of the exchange notes. The letter of transmittal accompanying this prospectus states that by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an "underwriter" within the meaning of the Securities Act. You may use this prospectus, as we may amend or supplement it in the future, for your resales of exchange notes. We will make this prospectus available to any broker-dealer for use in connection with any such resale for a period of 180 days after the date of expiration of this exchange offer. See "Plan of Distribution."



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TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS
WHERE YOU CAN FIND MORE INFORMATION
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
PROSPECTUS SUMMARY
About Equitable Resources, Inc.
The Exchange Offer
The Exchange Notes
RISK FACTORS
Risks Relating to Our Business
Risks Related to the Exchange Notes
RATIO OF EARNINGS TO FIXED CHARGES
THE EXCHANGE OFFER
USE OF PROCEEDS
CAPITALIZATION
SUMMARY SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Critical Accounting Policies Involving Significant Estimates
Consolidated Results of Operations
BUSINESS
MANAGEMENT
DESCRIPTION OF OTHER INDEBTEDNESS
DESCRIPTION OF EXCHANGE NOTES
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS
PLAN OF DISTRIBUTION
LEGAL MATTERS
EXPERTS
EQUITABLE RESOURCES