UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006

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

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-3551

EQUITABLE RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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

225 North Shore Drive
Pittsburgh, Pennsylvania		15212
(Address of principal executive offices)		(Zip Code)

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

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

Title of each class		Name of each exchange on which registered
Common Stock, no par value		New York Stock Exchange
Preferred Stock Purchase Rights		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No x

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b–2 of the Exchange Act. (Check one):

Large accelerated filer x Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No x

The aggregate market value of voting stock held by non-affiliates of the registrant as of June 30, 2006: $3,987,703,990

The number of shares of common stock outstanding as of January 31, 2007: 121,625,746

DOCUMENTS INCORPORATED BY REFERENCE

The Company’s definitive proxy statement relating to the annual meeting of shareowners, to be held April 11, 2007, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2006, is incorporated by reference in Part III to the extent described therein.

		Glossary of Commonly Used Terms, Abbreviations, and Measurements

PART I

Item 1		Business
Item 1A		Risk Factors
Item 1B		Unresolved Staff Comments
Item 2		Properties
Item 3		Legal Proceedings
Item 4		Submission of Matters to a Vote of Security Holders
		Executive Officers of the Registrant

PART II

Item 5		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6		Selected Financial Data
Item 7		Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A		Quantitative and Qualitative Disclosures About Market Risk
Item 8		Financial Statements and Supplementary Data
Item 9		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A		Controls and Procedures
Item 9B		Other Information

PART III

Item 10		Directors, Executive Officers and Corporate Governance
Item 11		Executive Compensation
Item 12		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13		Certain Relationships and Related Transactions, and Director Independence
Item 14		Principal Accounting Fees and Services

PART IV

Item 15		Exhibits, Financial Statement Schedules
		Index to Financial Statements Covered by Report of Independent Registered Public Accounting Firm
		Index to Exhibits
		Signatures
		Certifications

Glossary of Commonly Used Terms, Abbreviations, and Measurements

Commonly Used Terms

Appalachian Basin – The area of the United States comprised of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie at the foot of the Appalachian Mountains.

basis – When referring to natural gas, the difference between the futures price for a commodity and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location and contract pricing.

Btu – One British thermal unit – a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

cash flow hedge – A derivative instrument that complies with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.

collar – A financial arrangement that effectively establishes a price range for the underlying commodity. The producer bears the risk of fluctuation between the minimum (floor) price and the maximum (ceiling) price.

dekatherm(dth) – A measurement unit of heat energy equal to 1,000,000 British thermal units.

development well – A well drilled into a known producing formation in a previously discovered field.

exploratory well – A well drilled into a previously untested geologic prospect to determine the presence of gas or oil.

farm tap – Natural gas supply service in which the customer is served directly from a well or gathering pipeline.

futures contract – An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price.

gas – All references to “gas” in this report refer to natural gas.

gross – “Gross” natural gas and oil wells or “gross” acres equal the total number of wells or acres in which the Company has a working interest.

heating degree days – Measure used to assess weather’s impact on natural gas usage calculated by adding the difference between 65 degrees Fahrenheit and the average temperature of each day in the period (if less than 65 degrees Fahrenheit). Each degree of temperature by which the average temperature falls below 65 degrees Fahrenheit represents one heating degree day. For example, a day with an average temperature of 50 degrees Fahrenheit will have 15 heating degree days.

hedging – The use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility.

horizontal drilling – Drilling that ultimately is horizontal or near horizontal to increase the length of the well bore penetrating the target formation.

infill drilling – Drilling between producing wells in a developed field to increase production.

margin deposits – Funds or good faith deposits posted during the trading life of a futures contract to guarantee fulfillment of contract obligations.

Glossary of Commonly Used Terms, Abbreviations, and Measurements

margin call – A demand for additional or variation margin deposits when futures prices move adversely to a hedging party’s position.

multiple completion well – A well producing oil and/or gas from different zones at different depths in the same well bore with separate tubing strings for each zone.

net – “Net” gas and oil wells or “net” acres are determined by summing the fractional ownership working interests the Company has in gross wells or acres.

net revenue interest – The interest retained by the Company in the revenues from a well or property after giving effect to all third party royalty interests (equal to 100% minus all royalties on a well or property).

proved reserves – Reserves that, based on geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reserves under existing economic and operating conditions.

proved developed reserves – Proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.

reservoir – A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

royalty interest – the land owner’s share of oil or gas production (typically 1/8, 1/6, or 1/4) free of cost.

transportation – Moving gas through pipelines on a contract basis for others.

throughput – Total volumes of natural gas sold or transported by an entity.

working interest – An interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.

Abbreviations

APB No. 18 – Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock”

APB No. 25 – Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”

EITF No. 02-3 – Emerging Issues Task Force Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10 and 00-17”

FASB – Financial Accounting Standards Board

FERC – Federal Energy Regulatory Commission

FIN 45 – FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others – an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34”

FIN 48 – FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109”

IRC – Internal Revenue Code of 1986

IRS – Internal Revenue Service

NYMEX – New York Mercantile Exchange

OTC – Over the Counter

PA PUC – Pennsylvania Public Utility Commission

SEC – Securities and Exchange Commission

Glossary of Commonly Used Terms, Abbreviations, and Measurements

SFAS – Statement of Financial Accounting Standards

SFAS No. 5 – Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”

SFAS No. 19 – Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”

SFAS No. 69 – Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities – an amendment of FASB Statements 19, 25, 33, and 39”

SFAS No. 71 – Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”

SFAS No. 87 – Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions”

SFAS No. 88 – Statement of Financial Accounting Standards No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”

SFAS No. 106 – Statement of Financial Accounting Standards No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”

SFAS No. 109 – Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”

SFAS No. 115 – Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities”

SFAS No. 123 – Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”

SFAS No. 123R – Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based

Payment”

SFAS No. 133 – Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended

SFAS No. 143 – Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”

SFAS No. 144 – Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”

SFAS No. 146 – Statement of Financial Accounting Standards No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”

SFAS No. 157 – Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”

SFAS No. 158 – Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106 and 132(R)”

SFAS No. 159 – Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”

WV PSC – Public Service Commission of West Virginia

Measurements

Bbl = barrel

Bcf = billion cubic feet

Bcfe = billion cubic feet of natural gas equivalents

Mcf = thousand cubic feet

Mcfe = thousand cubic feet of natural gas equivalents

MMBtu = million British thermal units

MMcf = million cubic feet

MMcfe = million cubic feet of natural gas equivalents

PART I

Forward-Looking Statements

Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “forecasts,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this report include the matters discussed in the sections captioned “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s drilling and infrastructure programs, production volumes, reserves, capital expenditures, the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc., the financing of that acquisition, and the Company’s move to a holding company structure. A variety of factors could cause the Company’s actual results to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, those set forth under Item 1A, “Risk Factors.”

Any forward-looking statement speaks only as of the date on which such statement is made and the Company does not intend to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.

Item 1. Business

General

In this Form 10-K, references to “we,” “us,” “our,” “Equitable,” “Equitable Resources” and “the Company” refer collectively to Equitable Resources, Inc. and its consolidated subsidiaries, unless otherwise specified.

Equitable Resources, Inc. is an integrated energy company, with an emphasis on Appalachian area natural gas supply activities including production and gathering and natural gas distribution and transmission. The Company and its subsidiaries offer energy (natural gas, and a limited amount of natural gas liquids and crude oil) products and services to wholesale and retail customers through two business segments: Equitable Utilities and Equitable Supply. In December 2005, the Company discontinued and sold the operations of its NORESCO segment, which provided energy efficiency solutions to customers including governmental, military, institutional, commercial and industrial end-users.

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

The Company and its subsidiaries had approximately 1,340 employees at the end of 2006, of which 332 employees were subject to collective bargaining agreements. In January 2007, the Company and one union reached agreement on a three-year renewal contract for various clerical employees represented by the union. Although one union representing 14 employees has been operating without a contract since April 19, 2004, the Company believes that its employee relations are generally good.

The Company makes certain filings with the SEC, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, available free of charge through its website, http://www.eqt.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. The

Company’s annual reports to shareholders, press releases and recent analyst presentations are also available on the Company’s website.

Business Segments

Equitable Utilities

Equitable Utilities’ operations comprise the gathering, transportation, storage, distribution and sale of natural gas. Equitable Utilities has both regulated and nonregulated operations. The regulated activities consist of the Company’s state-regulated distribution operations and federally-regulated pipeline and storage operations. The nonregulated activities include the non-jurisdictional marketing of natural gas, risk management activities for the Company and the sale of energy-related products and services. Equitable Utilities generated approximately 36% of the Company’s net operating revenues in 2006.

Distribution Operations

Equitable Utilities’ distribution operations are carried out by Equitable Gas Company (Equitable Gas), a division of the Company. The service territory for the distribution operations includes southwestern Pennsylvania, municipalities in northern West Virginia and field line sales, also referred to as farm tap service, in eastern Kentucky and West Virginia. These areas have a rather static population and economy. The distribution operations provide natural gas services to approximately 274,000 customers, comprising 255,400 residential customers and 18,600 commercial and industrial customers. Equitable Gas purchases gas through contracts with various sources including major and independent producers in the Gulf Coast, local producers in the Appalachian area and gas marketers (including an affiliate). These contracts contain various pricing mechanisms, ranging from fixed prices to several different index-related prices.

Equitable Gas’ distribution rates, terms of service, contracts with affiliates and issuance of securities are subject to comprehensive regulation by the PA PUC and the WV PSC. The field line sales rates in Kentucky are also subject to rate regulation by the Kentucky Public Service Commission. Equitable Gas also operates a small gathering system in Pennsylvania, which is not subject to comprehensive regulation.

The Company must usually seek approval of one or more of its regulators prior to increasing (or decreasing) its rates. Currently, Equitable Gas passes through to its regulated customers the cost of its purchased gas and transportation activities. It is allowed to recover a return in addition to the costs of its transportation activities. However, the Company’s regulators do not guarantee recovery and may require that certain costs of operation be recovered over an extended term. Equitable Gas has worked with, and continues to work with, regulators to implement alternative performance-based rates. Equitable Gas’ tariffs for commercial and industrial customers allow for negotiated rates in limited circumstances. Equitable Gas has not filed a base rate case since 1997, and its predominant approach to maximizing value is cost control and operational excellence. Regulators periodically audit the Company’s compliance with applicable regulatory requirements. The Company is not aware of any significant non-compliance as a result of any completed audits.

Because most of its customers use natural gas for heating purposes, Equitable Gas’ revenues are seasonal, with approximately 72% of calendar year 2006 revenues occurring during the winter heating season (the months of January, February, March, November and December). Significant quantities of purchased natural gas are placed in underground storage inventory during the off-peak season to accommodate higher demand during the winter heating season.

On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion Resources, Inc.’s natural gas distribution assets in Pennsylvania and in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. The transaction requires approvals from the PA PUC and the WV PSC and is also under review by the Pennsylvania Attorney General and by the Federal Trade Commission (FTC). On February 9, 2007 an administrative law judge for the PA PUC issued an initial decision approving the stock acquisition, subject to the terms and conditions of the Joint Petition for Settlement filed by the Company and a number of the intervening parties. The Joint Petition for

Settlement includes, among other things, an agreement by the Company that Equitable Gas Company and The Peoples Natural Gas Company will not make base rate case filings prior to January 1, 2009. Under the Commission’s rules a period for filing exceptions and reply exceptions has begun to run. Based upon the thorough manner in which the administrative law judge addressed the testimony of opposing parties, the Company believes it likely that the PA PUC will approve the stock acquisition when it reviews the application in March or April of 2007. The WV PSC procedural schedule calls for hearings in mid-May 2007. The WV PSC staff and consumer advocate, the Independent Oil and Gas Association of West Virginia and the Utility Workers Union of America Local 69 Division 1 have intervened in the West Virginia regulatory case. The Company continues to engage in settlement negotiations with these interveners. The Company is complying with the information requests of the Pennsylvania Attorney General and the FTC and is targeting an approval timeframe not long after receiving approval from the PA PUC. No assurance is given that the targeted timeframes will be achieved. The Company’s acquisition agreement expires on March 31, 2007 unless a closing has not occurred due to a failure to obtain a required governmental consent or authorization and such is being diligently pursued, in which case the expiration date is automatically extended to June 30, 2007. The agreement will then terminate if no closing occurs by June 30, 2007, unless the parties agree to an extension. The assets to be acquired will increase: customers in the distribution operations by 475,000 or 173%; total storage capacity by 33 Bcf or 60%, miles of gathering pipelines by 936 miles; gathered volumes by 40%; and miles of high pressure transmission by 466 miles or 42%. Transition planning activities have commenced at Equitable Utilities to plan for the integration of the assets, resources, and business processes of The Peoples Natural Gas Company and Hope Gas, Inc.’s into Equitable Resources.

Pipeline (Transportation and Storage) Operations

Equitable Utilities’ interstate pipeline operations are carried out by Equitrans, L.P. (Equitrans). These operations offer gas gathering, transportation, storage and related services to affiliates and third parties in the northeastern United States, including but not limited to, Dominion Resources, Inc., Keyspan Corporation, NiSource, Inc., PECO Energy Company and Amerada Hess Corporation. In 2006, approximately 77% of transportation volumes and approximately 62% of transportation revenues were from affiliates.

In the second quarter of 2006, the Company filed a certificate application with the FERC for approval to build a 70-mile, 20-inch diameter pipeline which will connect the Company-operated Kentucky hydrocarbon processing plant in Langley, Kentucky, to the Tennessee Gas Pipeline in Carter County, Kentucky, and will initially provide up to 130,000 dekatherms per day of firm transportation service. The pipeline, known as The Big Sandy Pipeline, is owned and operated by Equitrans and is targeted for completion in 2007. Equitrans has secured most of the materials, labor and rights-of-way necessary to complete the project. Equitrans received a FERC certificate on November 15, 2006, authorizing construction of the pipeline subject to certain operational, commercial and environmental conditions. Equitrans’ implementation plan addressed those conditions and received FERC approval on November 29, 2006. Capital expenditures incurred by the Company in 2006 related to the Big Sandy Pipeline are included in the Equitable Supply business segment.

Equitrans’ rates are subject to regulation by the FERC. On April 5, 2006, the FERC approved a settlement to Equitrans’ consolidated 2005 and 2004 rate case filings. The settlement became effective on June 1, 2006. The settlement provided for the following:

· An expected annual revenue increase of $6.0 million and an expected operating income increase of $3.2 million

· Replenishment of 7.1 Bcf of migrated base gas from prior periods

· Consolidation of transmission assets into a single transmission system with a system-wide rate

· Consolidation of gathering assets into a single gathering system with a system-wide rate

· Tracking and recovery of costs relating to compliance with the Pipeline Safety Improvement Act of 2002

· Redesigned contract storage services

· Five-year rate moratorium on gathering rates

· Three-year rate moratorium on transmission rates

Equitrans’ firm transportation contracts expire between 2007 and 2009. The Company anticipates that the majority of the related volumes will be fully subscribed when they become available.

Energy Marketing

Equitable Utilities’ unregulated marketing operations include the non-jurisdictional marketing of natural gas at Equitable Gas, marketing and risk management activities at Equitable Energy, LLC (Equitable Energy), and the sale of energy-related products and services by Equitable Homeworks, LLC. Services and products offered by the marketing operations include commodity procurement, delivery and storage services, such as park and loan services, risk management and other services for energy consumers including large industrial, utility, commercial and institutional end-users. Equitable Energy also engages in trading and risk management activities for the Company. The objective of these activities is to limit the Company’s exposure to shifts in market prices and to optimize the use of the Company’s assets.

Equitable Supply

Equitable Supply’s production business develops, produces and sells natural gas and, to a limited extent, crude oil and natural gas liquids, in the Appalachian region of the United States. Its gathering business consists of gathering the Company’s and third party gas and the processing of natural gas liquids. Equitable Supply generated approximately 64% of the Company’s net operating revenues in 2006.

Production

Equitable Supply’s production business, operating through Equitable Production Company and several other affiliates (collectively referred to as “Equitable Production”), is the largest owner of proved natural gas reserves in the Appalachian Basin. The Company’s reserves are located entirely in the Appalachian Basin, where Equitable Production currently operates approximately 12,000 producing wells.

The Appalachian Basin is characterized by wells with comparatively low rates of annual decline in production, long well lives, low production costs per well and high energy content. Many of the Company’s wells have been producing for decades, and in some cases since the early 1900’s. Management believes that virtually all of the Company’s wells are low risk development wells because they are drilled in areas known to be productive. Many of these wells are completed in more than one producing formation, including coal formations in certain areas, and production from these formations may be commingled. The Company’s 2006 drilling program was comprised dominantly of vertical wells, but also included horizontal drilling.

In 2006, Equitable Production drilled 560 gross operated wells (427 net operated wells), including 5 horizontal wells, and 95 gross non-operated wells (28 net non-operated wells) at a success rate of nearly 100%. Drilling was concentrated within Equitable’s core areas of southwestern Virginia, southeastern Kentucky and southern West Virginia. This activity resulted in proved developed reserve additions of approximately 120 Bcfe. Of the proved developed reserve additions, approximately 60 Bcfe relates to proved undeveloped reserves that were transferred to proved developed reserves and an equal amount relates to proved developed extensions, discoveries and other additions that were not previously classified as proved.

The natural gas produced by Equitable Supply is a commodity and therefore the Company receives market-based pricing. The market price for gas located in the Appalachian Basin is generally higher than the price for gas located in the Gulf Coast, largely due to the differential in the cost to transport gas to customers in the northeastern United States. The recent increase in production in the Appalachian Basin by the Company and other producers is putting pressure on the capacity of existing gathering and midstream transport systems. As a result, the Company has entered into certain discounted sales arrangements to ensure that its gas continues to flow.

The combination of long-lived production, low drilling costs, high drilling completion rates and proximity to natural gas markets has resulted in a highly fragmented operating environment in the Appalachian Basin. Natural gas drilling activity has increased as suppliers in the Appalachian Basin attempt to take advantage of higher than normal natural gas prices. While increased activity can place constraints on capacity of labor, equipment, pipeline

availability and other resources in the Appalachian Basin, it also provides opportunities for expansion of natural gas gathering activities and potential for higher quality rigs and labor providers in the future.

Equitable Supply hedges a portion of its forecasted natural gas production. It also hedges third party purchases and sales. The Company’s hedging strategy and information regarding its derivative instruments are outlined in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” and in Notes 1 and 3 to the Consolidated Financial Statements.

Gathering

Equitable Gathering derives its revenues from charges to customers for use of its gathering system in the Appalachian Basin. As of December 31, 2006, the system included approximately 7,100 miles of gathering line located throughout West Virginia, eastern Kentucky and southwestern Virginia. Over 85% of the gathering system volumes are transported to interconnects with three major interstate pipelines: Columbia Gas Transmission, East Tennessee Natural Gas Company and Dominion Transmission. The gathering system also maintains interconnects with Equitrans, the Company’s interstate pipeline affiliate. Maintaining these interconnects provides the Company with access to geographically diverse markets.

Gathering system sales volumes for 2006 totaled 108.6 Bcfe, of which approximately 64% related to the gathering of Equitable Production’s gas volumes, 26% related to third party volumes, and the remainder related to volumes in which interests were sold by the Company but which the Company continued to operate for a fee. Approximately 82% of Equitable Gathering’s 2006 revenues were from affiliates. Due to increased operating costs and capital investment, Equitable Gathering is, in certain cases, charging gathering rates which are below its cost of service. Equitable Gathering continues to pursue full recovery of these costs by increasing rates charged to its customers.

Key competitors for new gathering systems include independent gas gatherers and integrated Appalachian energy companies. See “Outlook” under Equitable Supply’s section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussion of the Company’s strategy in regards to its midstream gathering operations.

Transfer of Gathering Assets

Effective January 1, 2006, certain gathering assets, consisting of 1,400 miles of gathering line and related facilities with approximately 13.3 Bcf of annual throughput, were transferred from Equitable Supply to Equitable Utilities for segment reporting purposes. The effect of the transfer is not material to the results of operations or financial position of the Equitable Utilities or Equitable Supply segments; segment results have not been restated for this transfer.

Discontinued Operations

In the fourth quarter of 2005, the Company sold its NORESCO domestic business for $82 million before customary purchase price adjustments. In the second quarter of 2006, the Company completed the sale of the remaining interest in its investment in IGC/ERI Pan-Am Thermal Generating Limited (Pan Am), previously included in the NORESCO business segment, for total proceeds of $2.6 million. As a result of these transactions, the Company has reclassified its financial statements for all periods presented to reflect the operating results of the NORESCO segment as discontinued operations.

Composition of Segment Operating Revenues

Presented below are operating revenues as a percentage of total operating revenues for each class of products and services representing greater than 10% of total operating revenues during the years 2006, 2005 and 2004.

	2006		2005		2004
Equitable Utilities:
Residential natural gas sales	24	%	26	%	29	%
Marketed natural gas sales	30	%	27	%	23	%
Equitable Supply:
Natural gas equivalents sales	29	%	30	%	29	%

Financial Information About Segments

See Note 2 to the Consolidated Financial Statements for financial information by business segment including, but not limited to, revenues from external customers, operating income, and total assets.

Financial Information About Geographic Areas

Substantially all of the Company’s assets and operations are located in the continental United States.

Environmental

See Note 19 to the Consolidated Financial Statements for information regarding environmental matters.

Item 1A. Risk Factors

Risks Relating to Our Business

In addition to the other information contained in this Form 10-K, the following risk factors should be considered in evaluating our business. Please note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations.

Natural gas price volatility may have an adverse effect on our revenue, profitability and liquidity.

Our revenue, profitability and liquidity depend on the price for natural gas. The markets for natural gas are volatile and fluctuations in prices will affect our financial results. Natural gas prices are affected by a number of factors beyond our control, which include: weather conditions; the supply of and demand for natural gas; national and worldwide economic and political conditions; the price and availability of alternative fuels; the proximity to, and availability of capacity on, transportation facilities; and government regulations, such as regulation of natural gas transportation, royalties and price controls.

Increases in natural gas prices may be accompanied by or result in increased well drilling costs, increased deferral of purchased gas costs for our distribution operations, increased production taxes, increased lease operating expenses, increased exposure to credit losses resulting from potential increases in uncollectible accounts receivable from our distribution customers, increased volatility in seasonal gas price spreads for our storage assets, and increased customer conservation or conversion to alternative fuels. Significant price increases, such as occurred in the fall and winter of 2005, subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including futures contracts, swap agreements and exchange traded instruments) which require us to post significant amounts of cash collateral with our hedge counterparties. The cash collateral, which is interest-bearing, provided to our hedge counterparties is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related hedged transaction. In such cases we are, however, exposed to the risk of non-performance by our hedge counterparties of their obligations under the derivative contracts. In addition, to the extent we have hedged our current production at prices below the current market price, we are unable to benefit fully from the increase in the price of natural gas.

Lower natural gas prices, increases in our estimates of development costs or changes to our production assumptions may result in our having to make downward adjustments to our estimated proved reserves, change our production plans, and incur non-cash charges to earnings.

Our failure to assess production opportunities based on market conditions could negatively impact our long-term growth prospects for our production business.

Our goal of sustaining long-term growth for our production business is contingent upon our ability to identify production opportunities based on market conditions. Successfully identifying production opportunities involves a high degree of business experience, knowledge and careful evaluation of potential opportunities, along with subjective judgments and assumptions which may prove to be incorrect.

Our failure to develop and maintain the necessary infrastructure to successfully deliver gas to market may adversely affect our earnings, cash flows and results of operations.

Our gas delivery depends on the availability of adequate transportation infrastructure. We have announced a significant investment in transportation infrastructure (the Big Sandy Pipeline) which is intended to address a lack of capacity on and access to existing transportation pipelines as well as curtailments on such pipelines. We are also planning an upgrade to the Company-operated hydrocarbon processing plant in Langley, Kentucky for completion in early 2008. Our infrastructure development program can involve significant risks, including those related to timing and cost overruns and these risks can be affected by the availability of capital, materials, and a qualified work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology and other factors. In addition, we may not be able to obtain sufficient third party transportation contracts to recover the costs of our infrastructure development program. We also deliver to and are served by third party gas gathering, transportation,

processing and storage facilities which are limited in number and geographically concentrated. An extended interruption of access to or service from these facilities could result in material adverse consequences to us.

The amount and timing of actual future gas production is difficult to predict and may vary significantly from our estimates which may reduce our earnings.

Our future success depends on our ability to develop additional gas reserves that are economically recoverable and to maximize existing well production, and our failure to do so may reduce our earnings. We have expanded our drilling program in recent years, and we have subsequently announced further expansion. Our drilling of development wells can involve significant risks, including those related to timing and cost overruns and these risks can be affected by the availability of capital, leases, rigs and a qualified work force, as well as weather conditions, gas price volatility, government approvals, title problems, 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 due to inadequate well operation and compressor availability. Without continued successful development or acquisition activities, our reserves and revenues will decline as a result of our current reserves being depleted by production.

We may engage in acquisition and disposition strategies that involve a number of inherent risks, any of which may cause us not to realize anticipated benefits and may adversely affect our earnings, cash flows and results of operations.

On March 1, 2006, we signed a purchase agreement to acquire the capital stock of The Peoples Natural Gas Company and Hope Gas, Inc. from Consolidated Natural Gas Company, a wholly-owned subsidiary of Dominion Resources, Inc. In addition, we intend to continue to strategically position our business in order to improve our ability to compete. Acquisitions, joint ventures 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; the constraints imposed by regulators in approving such transactions; the potential for unions of an acquired business to strike; our ability to achieve identified financial and operating synergies anticipated to result from an acquisition or other transaction; demands on management related to the increase in size after an 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 such transactions. In addition, various factors including prevailing market conditions and the incursion of related contingent liabilities could negatively impact the benefits we receive from transactions.

If we fail to achieve our strategic or financial goals in any acquisition or disposition transaction, it could have a significant adverse affect on our earnings, cash flows and results of operations. Furthermore, if we borrow money to finance an acquisition, which we plan to do in connection with the acquisition of The Peoples Natural Gas Company and Hope Gas, Inc., our failure to achieve our stated goals could impact our ability to repay such borrowings or other borrowings and could weaken our financial condition. Moreover, additional debt could increase our vulnerability to the effects of interest rate movements.

We are subject to risks associated with the operation of our pipelines and facilities.

Our business operations are subject to all of the inherent hazards and risks normally incidental to the production, transportation, storage and distribution of natural gas. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that insurance policies we maintain to limit our liability of such losses will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that such levels of insurance will be available in the future at economical prices.

Our need to comply with comprehensive, complex and sometimes unpredictable government regulations may increase our costs and limit our revenue growth, which may result in reduced earnings.

Significant portions of our gathering, transportation, storage and distribution businesses are subject to state and federal regulation including regulation of the rates which we may assess our customers. The agencies that regulate our rates may prohibit us from realizing a level of return which we believe is appropriate. These restrictions may take the form of imputed revenue credits, cost disallowances (including purchased gas cost recoveries) and/or expense deferrals. Additionally, we may be required to provide additional assistance to low income residential customers to help pay their bills.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, restoration of drilling properties after drilling is completed, pipeline safety and work practices related to employee health and safety. Complying with these requirements could have a significant effect on our costs of operations and competitive position. If we fail to comply with these requirements, even if caused by factors beyond our control, such failure could result in the assessment of civil or criminal penalties and damages against us.

The rates of federal, state and local taxes applicable to the industries in which we operate, including production 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 cash flows and profitability.

See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for further discussion regarding the Company’s exposure to market risks, including the risks associated with our use of derivative contracts to hedge commodity prices.

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

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

Headquarters. In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building, which the Company leases, located at the North Shore in Pittsburgh, Pennsylvania. The Company still maintains leases for properties previously used for its administrative operations that were not being utilized for a period of time following the relocation and were deemed to have no economic benefit to the Company. However, during the second quarter of 2006, the Company began to utilize certain of the leased space previously deemed to have no economic benefit to the Company for the transition planning activities relating to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc.

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

The distribution operations consist of approximately 4,100 miles of pipe in Pennsylvania, West Virginia and Kentucky. The interstate pipeline operations consist of approximately 2,900 miles of transmission, storage, and gathering lines and interconnections with five major interstate pipelines. The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania. Equitrans has 15 natural gas storage reservoirs with approximately 496 MMcf per day of peak delivery capability and 57 Bcf of storage capacity of which 27 Bcf is working gas. These storage reservoirs are clustered, with 8 in northern West Virginia and 7 in southwestern Pennsylvania.

Equitable Supply. This segment’s production and gathering properties are located in the Appalachian Basin, specifically Kentucky, Pennsylvania, Virginia and West Virginia. This segment currently has an inventory of approximately 3.3 million gross acres (approximately 71% of which is considered undeveloped), which encompasses nearly all of the Company’s acreage of proved developed and undeveloped natural gas and oil production properties. Although most of its wells are drilled to relatively shallow depths (2,000 to 6,500 feet below the surface), the Company retains what are normally considered “deep rights” on the majority of its acreage. As of December 31, 2006, the Company estimated its total proved reserves to be 2,497 Bcfe, including proved undeveloped reserves of 772 Bcfe. No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company’s estimated total reserves. Additional information relating to the Company’s estimates of natural gas and crude oil reserves and future net cash flows is provided in Note 24 (unaudited) to the Consolidated Financial Statements.

Natural Gas and Crude Oil Production:

	2006		2005		2004
Natural Gas:
MMcf produced	80,698		78,105		72,226
Average well-head sales price per Mcfe sold (net of hedges)	$	4.79	$	5.13	$	4.45
Crude Oil:
Thousands of Bbls produced	112		108		83
Average sales price per Bbl	$	58.35	$	53.07	$	37.38

Average production cost, including severance taxes (lifting cost), of natural gas and crude oil during 2006, 2005, and 2004 was $0.768, $0.771, and $0.583 per Mcfe, respectively.

	Natural Gas	Oil
Total productive wells at December 31, 2006:
Total gross productive wells	12,402	22
Total net productive wells	9,270	19

At December 31, 2006, the Company had approximately 117 multiple completion wells.

Total acreage at December 31, 2006:
Total gross productive acres		964,840
Total net productive acres		906,950
Total gross undeveloped acres		2,330,550
Total net undeveloped acres		2,191,833

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

	2006	2005	2004
Exploratory wells:
Productive	—	—	—
Dry	—	—	—
Development wells:
Productive	455.0	344.2	246.5
Dry	1.0	1.0	—

Selected data by state (at December 31, 2006 unless otherwise noted):

	Kentucky		Virginia		West Virginia		Pennsylvania		Ohio(a)	Total
Natural gas and oil production (MMcfe) – 2006	35,699		23,723		20,534		1,415		—	81,371
Natural gas and oil production (MMcfe) – 2005	33,849		21,913		19,924		2,247		822	78,755
Natural gas and oil production (MMcfe) – 2004	30,183		20,497		18,019		2,415		1,646	72,760

Net revenue interest (%)	84.3	%	67.5	%	61.5	%	88.4	%	—	72.3	%

Total gross productive wells	4,876		2,223		4,621		704		—	12,424
Total net productive wells	4,047		1,754		2,784		704		—	9,289

Total gross acreage	1,442,481		527,284		1,201,304		124,321		—	3,295,390
Total net acreage	1,379,615		507,992		1,086,923		124,253		—	3,098,783

Proved developed reserves (Bcfe)	886		337		472		30		—	1,725
Proved undeveloped reserves (Bcfe)	339		98		335		—		—	772
Proved developed and undeveloped reserves (Bcfe)	1,225		435		807		30		—	2,497

Gross proved undeveloped drilling locations	1,069		656		1,189		—		—	2,914
Net proved undeveloped drilling locations	1,050		375		1,174		—		—	2,599

Approximate miles of gathering line	3,300		1,200		2,600		—		—	7,100

(a) Relates to certain non-core gas properties sold in May 2005. See Note 4 to the Company’s Consolidated Financial Statements.

Wells located in Kentucky are primarily in shale formations with depths ranging from 2,500 feet to 6,000 feet and average spacing of 72 acres. Wells located in Virginia are primarily in coal bed methane formations with depths ranging from 2,000 feet to 3,000 feet and average spacing of 60 acres. Wells located in West Virginia are primarily in tight sand formations with depths ranging from 2,500 feet to 6,500 feet and average spacing of 40 acres in the northern part of the state and 60 acres in the southern part of the state. Wells located in Pennsylvania are primarily in tight sand formations with depths ranging from 3,000 feet to 5,000 feet and average spacing of 40 acres.

The gathering operations own or operate approximately 7,100 miles of gathering line and 180 compressor units comprising 107 compressor stations with approximately 123,000 horse power of installed capacity, as well as other general property and equipment.

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

Equitable Supply leases office space in Pennsylvania, West Virginia, Virginia and Kentucky.

Item 3. Legal Proceedings

In the ordinary course of business, various legal claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.

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

No matters were submitted to a vote of the Company’s security holders during the last quarter of its fiscal year ended December 31, 2006.

Executive Officers of the Registrant (as of February 21, 2007)

Name and Age	Current Title (Year Initially Elected an Executive Officer)	Business Experience

John A. Bergonzi (54)	Vice President and Corporate Controller (2003)	Elected to present position January 2003; Corporate Controller and Assistant Treasurer from December 1995 to December 2002.

Philip P. Conti (47)	Senior Vice President and Chief Financial Officer (2000)	Elected to present position February 2007; Vice President and Chief Financial Officer from January 2005 to February 2007, also Treasurer until January 2006; Vice President, Finance and Treasurer from August 2000 to January 2005.

Randall L. Crawford (44)	Senior Vice President, and President, Equitable Utilities (2003)	Elected to present position February 2007; Vice President, and President, Equitable Utilities from February 2004 to February 2007; President, Equitable Gas Company from January 2003 to January 2004; Executive Vice President, Equitable Gas Company from November 2000 to December 2002.

Martin A. Fritz (42)	Vice President and Chief Administrative Officer (2006)	Elected to present position February 2007; Vice President and Chief Information Officer from April 2006 to February 2007; Chief Information Officer from May 2003 to March 2006; Deputy General Counsel from April 1999 to April 2003.

Murry S. Gerber (53)	Chairman and Chief Executive Officer (1998)	Elected to present position February 2007; Chairman, President and Chief Executive Officer from May 2000 to February 2007; President and Chief Executive Officer from June 1, 1998 to February 2007.

Joseph E. O’Brien (54)	Senior Vice President, and President, Equitable Supply (2001)	Elected to present position February 2007; Vice President, and President Equitable Supply from February 2006 to February 2007; Vice President, Facility Construction from July 2005 to January 2006. President, NORESCO, LLC from January 2000 to June 2005.

Johanna G. O’Loughlin (60)	Senior Vice President, General Counsel and Corporate Secretary (1996)	Elected to present position January 2002; Vice President, General Counsel and Secretary from May 1999 to January 2002.

Charlene Petrelli (46)	Vice President and Chief Human Resources Officer (2003)	Elected to present position February 2007; Vice President, Human Resources from January 2003 to February 2007; Director of Corporate Human Resources from October 2000 to December 2002.

David L. Porges (49)	Vice Chairman, President and Chief Operating Officer (1998)	Elected to present position February 2007; Vice Chairman and Executive Vice President, Finance and Administration from January 2005 to February 2007; Executive Vice President and Chief Financial Officer from February 2000 to January 2005.

All executive officers have executed agreements with the Company and serve at the pleasure of the Company’s Board of Directors. Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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

	2006						2005 (a)
	High		Low		Dividend		High		Low		Dividend
1st Quarter	$	39.02	$	34.05	$	0.21	$	30.62	$	27.89	$	0.19
2nd Quarter	37.00		31.59		0.22		34.42		28.16		0.21
3rd Quarter	37.48		32.55		0.22		39.90		34.01		0.21
4th Quarter	44.48		34.83		0.22		41.18		34.51		0.21

(a) Adjusted to reflect the two-for-one stock split effective September 1, 2005.

As of February 12, 2007, there were 3,992 shareholders of record of the Company’s common stock.

The amount and timing of dividends is subject to the discretion of the Board of Directors and depends on business conditions, the Company’s results of operations and financial condition and other factors. Based on currently foreseeable market conditions, the Company anticipates that comparable dividends will be paid on a regular quarterly basis.

The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended December 31, 2006.

Period	Total number of shares (or units) purchased (a)	Average price paid per share (or unit)		Total number of shares (or units) purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs (b)

October 2006 (October 1 – October 31)	12,941	$	37.82	—	8,385,400

November 2006 (November 1 – November 30)	9,721	$	42.86	—	8,385,400

December 2006 (December 1 – December 31)	8,235	$	43.31	—	8,385,400

Total	30,897			—

(a) Includes 16,724 shares delivered in exchange for the exercise of stock options to cover award cost and 14,173 shares for Company-directed purchases made by the Company’s 401(k) plans.

(b) Equitable’s Board of Directors previously authorized a share repurchase program with a maximum of 50.0 million shares and no expiration date. The program was initially publicly announced on October 7, 1998, with subsequent amendments announced on November 12, 1999, July 20, 2000, April 15, 2004 and July 13, 2005.

Stock Performance Graph

The following graph compares the most recent five-year cumulative total return attained by shareholders of Equitable Resources’ common stock with the cumulative total returns of the S & P 500 index, and a customized peer group of eleven companies listed in footnote 1 below whose principal businesses are natural gas distribution, exploration and production, and transmission. An investment of $100 (with reinvestment of all dividends) is assumed to have been made on December 31, 2001 in the Company’s common stock, in the S&P 500 index, and in the peer group. Relative performance is tracked through December 31, 2006.

	2001	2002	2003	2004	2005	2006
EQUITABLE RESOURCES, INC.	100.00	104.90	131.69	191.65	237.77	277.02
SELF-CONSTRUCTED PEER GROUP (1)	100.00	88.54	110.19	137.39	167.99	203.86
S & P 500	100.00	77.90	100.24	111.15	116.61	135.03

(1) The following eleven companies are included in the customized peer group: CMS Energy Corporation, Energen Corporation, Keyspan Corporation, Kinder Morgan, Inc, National Fuel Gas Company, NiSource Inc, OGE Energy Corp., ONEOK, Inc, Peoples Energy Corp., Questar Corporation and Southwestern Energy Company. This is the same peer group used for the company’s short-term incentive plans. The company uses other peer groups for other purposes, including its executive performance incentive program under the 1999 Long-Term Incentive Plan.

Item 6. Selected Financial Data

	As of and for the year ended December 31, (a)
	2006		2005		2004		2003		2002
	(Thousands, except per share amounts)

Operating revenues	$	1,267,910	$	1,253,724	$	1,045,183	$	876,574	$	878,961
Income from continuing operations before cumulative effect of accounting change (b)	$	216,025	$	258,574	$	298,790	$	165,750	$	145,731
Income from continuing operations before cumulative effect of accounting change per share of common stock (c)
Basic	$	1.79	$	2.14	$	2.42	$	1.34	$	1.16
Diluted	$	1.77	$	2.09	$	2.37	$	1.31	$	1.14
Total assets	$	3,256,911	$	3,342,285	$	3,205,346	$	2,948,073	$	2,440,396
Long-term debt	$	753,500	$	766,500	$	626,500	$	647,000	$	471,250
Preferred trust securities	$	—	$	—	$	—	$	—	$	125,000
Cash dividends declared per share of common stock (c)	$	0.870	$	0.820	$	0.720	$	0.485	$	0.335

(a) Amounts have been reclassified to reflect the operating results of the NORESCO segment as discontinued operations for all periods presented.

(b) The year ended December 31, 2003, excludes the negative cumulative effect of an accounting change of $3.6 million related to the adoption of SFAS No. 143. The year ended December 31, 2002, excludes the negative cumulative effect of accounting change of $5.5 million related to the adoption of SFAS No. 142 and income from discontinued operations of $9.0 million related to the sale of the Company’s natural gas midstream operations.

See Item 1A, “Risk Factors,” Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 4 and 5 to the Consolidated Financial Statements for other matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.

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

Consolidated Results of Operations

Equitable’s consolidated income from continuing operations for 2006 was $216.0 million, or $1.77 per diluted share, compared with $258.6 million, or $2.09 per diluted share, for 2005, and $298.8 million, or $2.37 per diluted share, for 2004.

The $42.6 million decrease in income from continuing operations from 2005 to 2006 included the impact of several factors. In 2005, the Company recognized a pre-tax gain of $110.3 million on the sale of Kerr-McGee Corporation (Kerr-McGee) shares. In 2006, the Company incurred $12.3 million of transition planning expenses relating to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. The Company also established a reserve for West Virginia royalty disputes. The impact of lower realized selling prices ($25.8 million) and warmer weather ($9.3 million) also contributed to the decrease between years.

Decreases in income from continuing operations between years were partially offset by 2005 charges of $16.0 million for the termination and settlement of certain defined benefit pension plans and of $7.8 million for the Company’s office consolidation, as well as the 2006 favorable impact of the Equitrans rate case settlement. Additionally, income from continuing operations for 2006 was positively impacted by reduced expenses related to the executive performance incentive programs ($22.7 million), favorable storage asset optimization ($16.4 million), and higher production sales volumes ($11.6 million).

The $40.2 million decrease in income from continuing operations from 2004 to 2005 was primarily the result of several factors. The Company recorded a gain in 2004 as a result of the Westport Resources Corporation (Westport)/Kerr-McGee merger in the second quarter of 2004 as well as a gain on the sale of 0.8 million Kerr-McGee shares subsequent to the merger. These gains were partially offset by an expense related to the Company’s charitable contribution of 0.4 million Kerr-McGee shares to the Equitable Resources Foundation, Inc. in 2004. The 2005 gain from the sale of the Company’s remaining Kerr-McGee shares partially offset the impact of the 2004 items.

Income from continuing operations was favorably impacted in 2005 compared to 2004 as a result of higher realized selling prices, an increase in sales volumes from production and increased revenues from storage asset optimization. These increases were offset in some part by increased operating costs resulting primarily from higher natural gas prices and sales volumes, increased incentive expenses and impairment charges related to the Company’s office consolidation.

The Company’s effective tax rate for its continuing operations for the year ended December 31, 2006, was 33.7% compared to 37.2% for the year ended December 31, 2005, and 34.2% for the year ended December 31, 2004. The higher effective tax rate in 2005 was primarily the result of tax benefit disallowances under Section 162(m) of the IRC. See Note 6 to the Consolidated Financial Statements.

Business Segment Results

Business segment operating results are presented in the segment discussions and financial tables on the following pages. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity in earnings of nonconsolidated investments, and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters expenses are not allocated to the operating segments. Certain performance-related incentive costs, pension costs and administrative costs totaling $21.9 million, $48.0 million and $45.8 million in 2006, 2005 and 2004, respectively, were not allocated to business segments. The decrease in unallocated expenses from 2005 to 2006 was primarily related to decreased long-term incentive expenses.

The Company has reconciled each segment’s operating income, equity in earnings of nonconsolidated investments and other income, net to the Company’s consolidated operating income, equity in earnings of nonconsolidated investments and other income, net totals in Note 2 to the Consolidated Financial Statements.

Additionally, these subtotals are reconciled to the Company’s consolidated net income in Note 2. The Company has also reported the components of each segment’s operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. Equitable’s management believes that presentation of this information is useful to management and investors in assessing the financial condition, operations and trends of each of Equitable’s segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations. In addition, management uses these measures for budget planning purposes.

Equitable Utilities

Overview

Equitable Utilities’ net operating revenues increased 8.5% from 2005 to 2006. This increase was primarily due to increased pipeline revenues from the settlement of the Equitrans rate case effective June 1, 2006, as well as favorable marketing revenues resulting from volatile natural gas prices, as the marketing operations were able to take advantage of their asset position and achieve record margins from that business in 2006. The marketing business is primarily driven by Equitable Utilities’ physical and contractual gas storage assets which allow the segment to purchase gas and store it in lower price markets and simultaneously enter into contracts to sell it later at higher prices, taking advantage of near term seasonal gas price spreads. Those spreads are unpredictable and at times were considerably wider in 2006 than they were in 2005.

The positive results from the pipeline and marketing operations were partially offset by reduced revenues in Equitable Utilities’ distribution operations, as the weather in Equitable Gas’ service territory in 2006 was 15% warmer than the 30 year average and 10% warmer than 2005. The National Oceanic and Atmospheric Administration (NOAA) reported that the 2006 average annual temperature for the contiguous U.S. was the warmest on record. NOAA also reported that, based on the unusually warm temperatures during much of the first half of the winter season (October to December 2006), the nation’s residential energy demand was approximately 13.5 percent lower than what would have occurred under average climate conditions for the season.

Operating expenses at Equitable Utilities decreased 3%, driven primarily by the absence of charges related to pension plans and the Company’s office consolidation that occurred in 2005, offset somewhat by transition planning expenses incurred in 2006 related to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. and the recognition of costs previously deferred as a result of the Equitrans rate case settlement.

Expenses were also positively impacted by a reduction in bad debt expense. In 2006, Equitable continued its consistent and aggressive collections strategy as permitted by The Responsible Utility Customer Protection Act, which became effective on December 14, 2004. In December 2005, the PA PUC approved Equitable Gas’s petition requesting approval to use up to $7 million of pipeline supplier refunds to benefit low-income customers in its service territory, primarily during the winter heating season. Approximately $4.9 million and $0.3 million of this amount was credited to eligible customers’ accounts during 2006 and 2005, respectively. The execution of the collections strategy and provision of additional customer energy assistance enabled Equitable Utilities to reduce its delinquent customer base by 20% as of December 2006 compared to December 2005. These efforts were significant in enabling Equitable Utilities to reduce its bad debt expense in 2006, despite unusually high gas cost rates in effect during 2006 and 2005.

manner in which the administrative law judge addressed the testimony of opposing parties, the Company believes it likely that the PA PUC will approve the stock acquisition when it reviews the application in March or April of 2007. The WV PSC procedural schedule calls for hearings in mid-May 2007. The WV PSC staff and consumer advocate, the Independent Oil and Gas Association of West Virginia and the Utility Workers Union of America Local 69 Division 1 have intervened in the West Virginia regulatory case. The Company continues to engage in settlement negotiations with these interveners. The Company is complying with the information requests of the Pennsylvania Attorney General and the FTC and is targeting an approval timeframe not long after receiving approval from the PA PUC. No assurance is given that the targeted timeframes will be achieved. The Company’s acquisition agreement expires on March 31, 2007 unless a closing has not occurred due to a failure to obtain a required governmental consent or authorization and such is being diligently pursued, in which case the expiration date is automatically extended to June 30, 2007. The agreement will then terminate if no closing occurs by June 30, 2007, unless the parties agree to an extension.

With the relatively recent repeal of the Public Utility Holding Company Act of 1935, the Company has filed applications with the PA PUC and WV PSC to reorganize as a holding company. Currently, Equitable Gas is a division of Equitable Resources, Inc., which requires the Company to obtain regulatory approval for many actions that are not directly related to the distribution operations, such as acquisitions and financings. This requirement restricts the Company’s ability to take advantage of opportunities and market conditions. The Company successfully completed a request for direction to holders of notes under the indentures governing its long-term debt. Upon receipt of the other required approvals, the Company expects to complete the reorganization. In 2006, the Company expensed $1.6 million of costs related to the holding company implementation.

Results of Operations

	Years Ended December 31,
	2006			2005			% change 2006 - 2005		2004			% change 2005 - 2004

OPERATIONAL DATA

Heating degree days (30 year average = 5,829)	4,976			5,543			(10.2	)	5,360			3.4

Residential sales and transportation volume (MMcf)	21,014			24,680			(14.9	)	25,520			(3.3	)
Commercial and industrial volume (MMcf)	23,841			25,368			(6.0	)	29,597			(14.3	)
Total throughput (MMcf) – Distribution Operations	44,855			50,048			(10.4	)	55,117			(9.2	)

Net operating revenues (thousands):
Distribution Operations (regulated):
Residential	$	92,497		$	102,457		(9.7	)	$	104,612		(2.1	)
Commercial & industrial	42,519			46,857			(9.3	)	48,563			(3.5	)
Other	8,319			7,544			10.3		5,950			26.8
Total Distribution Operations	143,335			156,858			(8.6	)	159,125			(1.4	)
Pipeline Operations (regulated)	72,586			53,767			35.0		55,123			(2.5	)
Energy Marketing	59,089			42,739			38.3		28,457			50.2
Total net operating revenues	$	275,010		$	253,364		8.5		$	242,705		4.4

Total operating expenses as a % of net operating revenues	54.47		%	61.22		%			55.44		%

Operating income (thousands):
Distribution Operations (regulated)	$	34,807		$	40,322		(13.7	)	$	56,877		(29.1	)
Pipeline Operations (regulated)	33,240			17,345			91.6		24,656			(29.7	)
Energy Marketing	57,162			40,587			40.8		26,616			52.5
Total operating income	$	125,209		$	98,254		27.4		$	108,149		(9.1	)

Depreciation, depletion and amortization (DD&A) (thousands):
Distribution Operations	$	19,938		$	19,483		2.3		$	17,474		11.5
Pipeline Operations	8,737			8,317			5.0		7,985			4.2
Energy Marketing	56			74			(24.3	)	170			(56.5	)
Total DD&A	$	28,731		$	27,874		3.1		$	25,629		8.8

Capital expenditures (thousands)	$	64,974		$	61,349		5.9		$	56,274		9.0

	Years Ended December 31,
	2006			2005			% change 2006 - 2005		2004			% change 2005 - 2004

FINANCIAL DATA (thousands)

Distribution revenues (regulated)	$	445,168		$	469,102		(5.1	)	$	422,438		11.0
Pipeline revenues (regulated)	74,010			57,534			28.6		55,123			4.4
Marketing revenues	380,149			365,625			4.0		300,513			21.7
Less: intrasegment revenues	(56,163		)	(45,804		)	22.6		(46,213		)	(0.9	)
Total operating revenues	843,164			846,457			(0.4	)	731,861			15.7

Purchased gas costs	568,154			593,093			(4.2	)	489,156			21.2
Net operating revenues	275,010			253,364			8.5		242,705			4.4

Operating expenses:
Operating and maintenance (O & M)	58,186			57,315			1.5		52,481			9.2
Selling, general and administrative (SG&A)	65,280			66,080			(1.2	)	56,446			17.1
Impairment charges	(2,396		)	3,841			(162.4	)	—			100.0
DD&A	28,731			27,874			3.1		25,629			8.8
Total operating expenses	149,801			155,110			(3.4	)	134,556			15.3
Operating income	$	125,209		$	98,254		27.4		$	108,149		(9.1	)

Fiscal Year Ended December 31, 2006 vs. December 31, 2005

Equitable Utilities’ operating income totaled $125.2 million for 2006 compared to $98.3 million for 2005. Equitable Utilities’ operating income increased $26.9 million primarily due to increased net marketing revenues, lower expenses related to defined benefit pension plans, increased pipeline operating income, reduction in bad debt expense, an impairment charge in 2005 in connection with the Company’s office consolidation and a gain in 2006 as a result of the partial reversal of the office impairment charge recorded in 2005. These improvements are partially offset by the impact of costs incurred in planning for the pending acquisition of The Peoples Natural Gas Company and Hope Gas Inc. and a reduction in distribution gas sales margins due to weather 15% warmer than the 30-year average.

Net operating revenues were $275.0 million for 2006 compared to $253.4 million for 2005. The $21.6 million increase in net operating revenues was primarily due to increased pipeline and marketing net operating revenues, partially offset by lower distribution net operating revenues. Pipeline operations’ net operating revenues increased $18.8 million from 2005 to 2006 primarily due to the settlement of Equitrans’ 2003 FERC rate case and the implementation of new rates and contracts in connection with that settlement. The settlement’s approval, which occurred in April 2006, improved net operating revenues by $7.0 million related to years 2005 and prior and an additional $5.7 million related to the transfer of certain gathering assets from Equitable Supply. New contract rates and billing determinants in the settlement result in the remaining $6.1 increase in pipeline net operating revenues. The increase in marketing net operating revenues of $16.4 million resulted primarily from increased storage asset opportunities realized in the volatile natural gas commodity price environment. Distribution operations’ net operating revenues decreased $13.5 million primarily due to decreased residential sales and transportation volumes, which decreased 3,666 MMcf from 2005 to 2006 due primarily to warmer weather.

Operating expenses totaled $149.8 million for 2006 compared to $155.1 million for 2005. Operating expenses for 2005 included $16.0 million in charges related to the termination and settlement of certain defined benefit pension plans and a $3.8 million loss related to the impairment of certain leased offices, furniture and equipment in connection with the Company’s relocation into its new, consolidated office space. Operating expenses for 2006 include $12.3 million of costs incurred in planning for the pending acquisition of The Peoples Natural Gas

Company and Hope Gas, Inc.; a $2.9 million increase in gathering expenses as a result of the transfer of certain assets from Equitable Supply; the recognition of $4.6 million of previously deferred post-retirement benefit obligation expenses in the pipeline business, both in connection with the FERC rate case settlement; and the reversal of $2.4 million of the 2005 office impairment charge, as the space previously abandoned was put back into use for the transition planning activities relating to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. Excluding these items, operating expenses decreased $2.9 million, which was primarily a result of decreases in distribution and marketing bad debt expense totaling $5.2 million, offset by increases of $0.9 million in depreciation expense and $0.8 million in general liability insurance expenses. The improvements in bad debt expense are a result of the more timely termination of non-paying customers, improved efforts to obtain alternative funding for low income customers and other improvements in the collections process. The increased depreciation expense is a result of increased capital spending in Equitable Utilities over the past two years and is primarily related to computer hardware and software, distribution mainline and service line replacements and the installation of automated meter reading devices.

Fiscal Year Ended December 31, 2005 vs. December 31, 2004

Equitable Utilities’ operating income totaled $98.3 million for 2005 compared to $108.1 million for 2004. Net operating income for 2005 included charges for the termination and settlement of defined benefit pension plans and an impairment charge in connection with the Company’s office consolidation.

Net operating revenues were $253.4 million for 2005 compared to $242.7 million for 2004. The $10.7 million increase in net operating revenues was primarily due to increased marketing net operating revenues of $14.2 million, resulting primarily from increased storage asset opportunities realized in a high and increasingly volatile natural gas commodity price environment. Distribution operations’ net operating revenues decreased $2.2 million due to decreased volumes. Distribution operations’ residential sales and transportation volumes decreased 840 MMcf from 2004 to 2005 due to decreased base load and lower customer use per degree day. These reductions resulted from increased customer conservation, more timely termination of non-paying customers in 2005 and other factors. Increased volumes as a result of colder weather partially offset these decreases in residential volumes, as heating degree days were 5,543 in 2005, which was 3% colder than the 5,360 heating degree days in 2004 although still warmer than normal. Distribution operations’ commercial and industrial volumes decreased 4,229 MMcf from 2004 to 2005 primarily due to a reduction in industrial throughput to two major steel-making customers. These high volume industrial sales have very low unit margins and did not significantly impact total net operating revenues. Pipeline operations’ net operating revenues decreased $1.3 million from 2004 to 2005 primarily due to a $3.8 million loss on fuel and retention in excess of the current rates. This loss was partially offset by increased revenues earned in loaning and parking services. These services are contracted on an as-available basis, as opposed to long-term firm storage contracts. This flexibility allows customers, including the Company’s marketing affiliate, to take advantage of the pipeline’s available storage to secure future supply at favorable prices. These services were heavily subscribed in 2005, as higher volatility in natural gas prices provided substantial value for storage options.

Operating expenses totaled $155.1 million for 2005 compared to $134.6 million for 2004. Operating expenses for 2005 included $16.0 million in charges related to the termination and settlement of certain defined benefit pension plans and a $3.8 million loss related to the impairment of certain leased offices, furniture and equipment in connection with the Company’s relocation into its new, consolidated office space. Excluding these items, operating expenses increased $0.7 million, which resulted from increases of $2.3 million in depreciation expense, $2.2 million in incentive compensation, $1.4 million in customer operations expenses and $1.1 million in employee benefit costs, largely offset by decreases of $4.7 million in bad debt expense and $1.4 million in insurance costs. The increased depreciation expense is a result of increased capital spending in Equitable Utilities over the past two years and is primarily related to computer hardware and software, distribution mainline and service line replacements and the installation of automated meter reading devices. The improvements in bad debt expense are a result of the more timely termination of non-paying customers, a full year impact of a $0.30 per Mcf regulatory surcharge instituted in April 2004, improved efforts to obtain alternative funding for low income customers and other improvements in the collections process. These improvements were offset somewhat in the fourth quarter of 2005 by high commodity rates and cold weather, which resulted in increased provisions for bad debt in that period compared to the prior year.

See “Capital Resources and Liquidity” section for discussion of Equitable Utilities’ capital expenditures during 2006, 2005 and 2004.

Outlook

Equitable Utilities’ business strategy is focused on operational excellence. Success in this strategy depends upon efficiently and effectively operating its gas distribution assets to optimize a return on assets. Going forward, Equitable Utilities expects to grow its gas distribution business selectively by acquisition. It also expects to continue to develop a portfolio of closely related unregulated businesses. Key elements of Equitable Utilities’ strategy include:

· Enhancing the value and growth potential of the regulated utility operations. Equitable Utilities will seek to enhance the value and growth of its existing utility assets by managing its capital spending effectively; establishing a reputation for excellent customer service; continuing to leverage technology; working to achieve authorized returns in each jurisdiction and, in those jurisdictions where it has performance-based rates, sharing the benefits with its customers; and maintaining earnings and rate stability through regulatory arrangements that fairly balance the interests of customers and shareholders.

· Closing and integrating the acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. Equitable Utilities is focused on obtaining the required regulatory approvals to close the acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. Transition planning activities have commenced at Equitable Utilities to plan for the integration of The Peoples Natural Gas Company and Hope Gas, Inc. into Equitable Resources, with $12.3 million of expenses incurred through December 31, 2006. The assets to be acquired will increase: customers in the distribution operations by 475,000 or 173%; total storage capacity by 33 Bcf or 60%, miles of gathering pipelines by 936 miles; gathered volumes by 40%; and miles of high pressure transmission by 466 miles or 42%. Based on the work completed to date, the Company expects that the conversion activities will continue at a similar monthly rate through June 2007 and increase Equitable Utilities’ operating expenses in the first and second quarter of 2007 in anticipation of closing the transaction.

· Selectively expanding Equitable Utilities natural gas storage and gathering operations. Equitable Utilities will endeavor to continue to expand its natural gas storage and gathering businesses to provide disciplined incremental earnings growth for shareholders. Equitable Utilities also intends to continue to invest capital in its underground storage business to expand its operational capabilities by increasing storage deliverability, thereby providing an opportunity to capture increased value from the volatility in natural gas prices. Equitable Utilities intends to grow its asset management business by providing its customers with gas supply, storage and asset management options; capturing value from increased natural gas gathering margins; providing producers with access to markets for their increased production; and arbitraging pipeline and storage assets across various gas markets and time horizons. Capturing this value from Equitable Utilities’ storage assets may increase the volatility of reported earnings from this business. Equitable Utilities will continue to focus on marketing energy to customers from its own assets; controlling costs; and managing its portfolio with smart business decisions while looking for additional opportunities to provide economical storage services in the regions in which the Company operates.

Equitable Supply

Overview

Equitable Supply’s sales revenues for 2006 were essentially flat in comparison with 2005 revenues. Sales volumes increased more than 5% from 2005 excluding volumes from properties sold during 2005, primarily as a result of increased production from the 2006 and 2005 drilling programs partially offset by the normal production decline in the Company’s existing wells. Equitable Supply drilled 560 gross operated wells in 2006 compared to 420 gross operated wells in 2005, a 33% increase. The 560 operated wells included 5 horizontal wells and 16 wells drilled as part of a coal bed methane infill pilot.

The positive results experienced from the increased sales volumes were more than offset by a 7% decline in the average well-head sales price, due primarily to decreased market prices. The average NYMEX price decreased 16% in 2006 from the abnormally high price levels in 2005, negatively impacting revenues from sales of unhedged volumes.

Operating expenses at Equitable Supply increased 12% primarily due to certain non-recurring charges for royalty disputes, bad debt expenses and pension and other postretirement plans, as well as higher DD&A and gathering and compression expenses resulting from increased drilling and infrastructure investments, as the Company continues to expand its development and midstream activities in the Appalachian Basin.

Results of Operations

	Years Ended December 31,
	2006		2005			% change 2006 - 2005		2004			% change 2005 - 2004

OPERATIONAL DATA

Capital expenditures (thousands) (a)	$	336,748	$	264,095		27.5		$	141,661		86.4

Production:
Total sales volumes (MMcfe)	76,156		73,909			3.0		67,731			9.1
Average (well-head) sales price ($/Mcfe)	$	4.83	$	5.17		(6.6	)	$	4.46		15.9

Company usage, line loss (MMcfe)	5,215		4,897			6.5		5,090			(3.8	)

Natural gas inventory usage, net (MMcfe)	—		(51		)	100.0		(61		)	(16.4	)

Natural gas and oil production (MMcfe) (b)	81,371		78,755			3.3		72,760			8.2

Lease operating expenses (LOE), excluding production taxes ($/Mcfe)	$	0.30	$	0.29		3.4		$	0.26		11.5
Production taxes ($/Mcfe)	$	0.48	$	0.49		(2.0	)	$	0.34		44.1
Production depletion ($/Mcfe)	$	0.62	$	0.59		5.1		$	0.54		9.3

Gathering:
Gathered volumes (MMcfe)	108,592		121,044			(10.3	)	127,339			(4.9	)
Average gathering fee ($/Mcfe)	$	1.02	$	0.82		24.4		$	0.58		41.4
Gathering and compression expense ($/Mcfe)	$	0.42	$	0.31		35.5		$	0.28		10.7
Gathering and compression depreciation ($/Mcfe)	$	0.14	$	0.12		16.7		$	0.11		9.1

(in thousands)
Production operating income	$	231,849	$	260,931		(11.1	)	$	212,657		22.7
Gathering operating income	37,315		32,650			14.3		14,712			121.9
Total operating income	$	269,164	$	293,581		(8.3	)	$	227,369		29.1

Production depletion	$	50,330	$	46,750		7.7		$	39,100		19.6
Gathering and compression depreciation	15,411		14,312			7.7		13,441			6.5
Other DD&A	4,759		3,835			24.1		3,295			16.4
Total DD&A	$	70,500	$	64,897		8.6		$	55,836		16.2

	Years Ended December 31,
	2006		2005		% change 2006 - 2005		2004		% change 2005 - 2004

FINANCIAL DATA (thousands)

Production revenues	$	377,626	$	390,290	(3.2	)	$	315,986	23.5
Gathering revenues (c)	110,945		98,901		12.2		74,442		32.9
Total operating revenues	488,571		489,191		(0.1	)	390,428		25.3

Operating expenses:
LOE, excluding production taxes	24,620		23,195		6.1		18,685		24.1
Production taxes (d)	38,653		38,288		1.0		24,589		55.7
Gathering and compression (O&M)	45,860		38,101		20.4		35,494		7.3
SG&A	39,774		30,610		29.9		28,455		7.6
Impairment charges	—		519		(100.0	)	—		100.0
DD&A	70,500		64,897		8.6		55,836		16.2
Total operating expenses	219,407		195,610		12.2		163,059		20.0
Operating income	$	269,164	$	293,581	(8.3	)	$	227,369	29.1

Equity in earnings of nonconsolidated investments	$	129	$	493	(73.8	)	$	688	(28.3	)
Other income, net	$	—	$	—	—		$	576	(100.0	)

(a) 2005 capital expenditures include $57.5 million for the acquisition of the limited partnership interest in Eastern Seven Partners, L.P. (ESP).

(b) Natural gas and oil production represents the Company’s interest in gas and oil production measured at the well-head. It is equal to the sum of total sales volumes, Company usage, line loss, and natural gas inventory usage, net.

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

(d) Production taxes include severance and production-related ad valorem and other property taxes.

Fiscal Year Ended December 31, 2006 vs. December 31, 2005

Equitable Supply’s operating income totaled $269.2 million for 2006 compared to $293.6 million for 2005, a decrease of $24.4 million between years. Production operating income decreased $29.1 million primarily due to a decrease in well-head sales price and an increase in production operating expenses, partially offset by increased sales volumes. Gathering operating income increased $4.7 million due to an increase in the average gathering fee, partially offset by decreased gathered volumes and increased gathering operating expenses.

Total operating revenues were $488.6 million for 2006 compared to $489.2 million for 2005. The $0.6 million decrease in net operating revenues was primarily due to a 7% per Mcfe decrease in the average well-head sales price, partially offset by a 3% increase in production total sales volumes and a 12% increase in gathering revenues. The $0.34 per Mcfe decrease in the average well-head sales price was mainly attributable to decreased market prices on unhedged volumes and increased gathering charges, partially offset by the absence of a 2005

negative price adjustment. The 2005 adjustment was principally due to the Company’s conclusion that the well-head sales price allocated to a third party’s working interest gas in previous periods may have been lower than the Company was obligated to pay. The 3% increase in production total sales volumes was primarily the result of the 2006 and 2005 drilling programs, partially offset by the sale of certain non-core gas properties in 2005 and the normal production decline in the Company’s wells. The 12% increase in gathering revenues was attributable to a 24% increase in the average gathering fee, partially offset by a 10% decline in gathered volumes. The increase in average gathering fee is reflective of the Company’s commitment to an increased infrastructure capital program, along with higher gas prices and related operating cost increases. The average gathering fee was also positively impacted by the transfer of certain regulated gathering facilities to Equitable Utilities. The decrease in gathered volumes in 2006 was primarily due to the transfer of gathering facilities to Equitable Utilities, the sale of gathering assets in 2005 and third-party customer volume shut-ins caused by maintenance projects on interstate pipelines. These factors were partially offset by increased gathered volumes for Company production in 2006.

Operating expenses totaled $219.4 million for 2006 compared to $195.6 million for 2005. The $23.8 million increase in operating expenses was due to increases of $9.2 million in SG&A, $7.8 million in gathering and compression, $5.6 million in DD&A, $1.4 million in LOE, and $0.4 million in production taxes, partially offset by a $0.5 million impairment charge in 2005 related to the Company’s office consolidation. The increase in SG&A was the result of reserves established in connection with West Virginia royalty disputes and bad debt expenses. The increase in gathering and compression was primarily due to pension and other postretirement benefits charges for an early retirement program totaling $3.3 million, increased compressor station operation and repair costs, including electricity on newly installed compressors, increased property taxes and increased field labor and related employment costs. These factors were partially offset by the transfer of gathering facilities to Equitable Utilities and the sale of gathering assets in 2005. The increase in DD&A was due to a $0.03 per Mcf increase in the unit depletion rate ($2.0 million), increased depreciation on a higher asset base ($2.0 million) and increased produced volumes ($1.6 million). The increase in the unit depletion rate was primarily due to the net development capital additions in 2005 on a relatively consistent proved reserve base. The increase in LOE was primarily due to increased direct well expenses and well and location repairs and maintenance, partially offset by the sale of gas properties in 2005. The increase in production taxes was due to increased property taxes ($2.4 million), partially offset by decreased severance taxes ($2.0 million). The increase in property taxes was a direct result of increased prices and sales volumes in prior years, as property taxes in several of the taxing jurisdictions where the Company’s wells are located are calculated based on historical gas commodity prices and sales volumes. The decrease in severance taxes (a production tax directly imposed on the value of gas extracted) was primarily due to lower gas commodity prices in the various taxing jurisdictions that impose such taxes. The impairment charges in 2005 were related to the Company’s relocation of its corporate headquarters and other operations of its new consolidated office space.

Fiscal Year Ended December 31, 2005 vs. December 31, 2004

Equitable Supply’s operating income totaled $293.6 million for 2005 compared to $227.4 million for 2004, an increase of $66.2 million between years. Production operating income increased $48.2 million primarily due to an increase in well-head sales price and an increase in sales volumes, partially offset by increased production operating expenses. Gathering operating income increased $18.0 million due to an increase in the average gathering fee, partially offset by decreased gathered volumes and increased gathering operating expenses.

Total operating revenues were $489.2 million for 2005 compared to $390.4 million for 2004. The $98.8 million increase in net operating revenues was primarily due to a 16% increase in the average well-head sales price, a 9% increase in production total sales volumes and a 33% increase in gathering revenues. The $0.71 per Mcfe increase in the average well-head sales price was mainly attributable to increased market prices on unhedged volumes partially offset by the adjustment related to a third party’s working interest gas as previously discussed. The 9% increase in production total sales volumes was primarily the result of the purchase of ESP, partially offset by the sale of gas properties. The 33% increase in revenues from gathering fees was attributable to a 41% increase in the average gathering fee, partially offset by a 5% decline in gathered volumes. The increase in average gathering fee is reflective of the Company’s commitment to an increased infrastructure capital program, along with higher gas prices and related operating cost increases. The decrease in gathered volumes in 2005 was primarily due to the sale of gathering assets and third-party customer volume shut-ins caused by maintenance projects on interstate pipelines. These factors were partially offset by increased gathered volumes for Company production in 2005. These increases

in production and gathering revenues were partially offset by the recognition of a gain of $2.7 million in 2004 that resulted from the renegotiation of a processing agreement.

Operating expenses totaled $195.6 million for 2005 compared to $163.1 million for 2004. A significant reason for this $32.5 million increase was due to additional costs of $15.0 million resulting from the purchase of ESP. The $15.0 million of costs were primarily related to DD&A ($4.7 million), production taxes ($4.6 million), lease operating expenses ($3.7 million) and gathering expenses ($2.0 million). Excluding the ESP costs, the $17.5 million increase in operating expenses was due to increases of $9.1 million in production taxes, $4.4 million in DD&A, $2.1 million in SG&A, $0.8 million in LOE, $0.6 million in gathering expenses and $0.5 million in impairment charges related to the Company’s office consolidation. The increase in production taxes was due to increased property taxes ($5.4 million) and severance taxes ($3.7 million). The increase in property taxes was a direct result of increased prices and sales volumes in prior years. The increase in severance taxes was primarily due to higher gas commodity prices and sales volumes in 2005 as compared to prior years.

The increase in DD&A excluding ESP was due to a $0.05 per Mcf increase in the unit depletion rate ($4.3 million) and increased depreciation on a higher asset base ($1.4 million), partially offset by lower depletion as a result of decreased volumes from the sale of gas properties ($1.3 million). The increase in the unit depletion rate was primarily due to the net development capital additions in 2005 and 2004. The increase in SG&A was the result of increased legal and professional fees and bad debt expenses. The increase in LOE was the result of the Company’s strategy to focus on current infrastructure as well as increased costs from vendors due to higher gas prices. The increase in gathering expenses was primarily attributable to increased electricity charges resulting from newly installed electric compressors, field labor and related employment costs and compressor station operation and repair costs. The gathering and compression increases are consistent with the Company’s strategic decision to focus on improving gathering and compression and metering effectiveness. Such increases were partially offset by reductions in gathering expenses due to reduced gathered volumes.

Other income, net for 2004 was the result of a $6.1 million settlement received from a previously disputed insurance coverage claim, offset by a $5.5 million expense related to the Company’s settlement of a prepaid forward contract in 2004.

See “Capital Resources and Liquidity” section for discussion of Equitable Supply’s capital expenditures during 2006, 2005 and 2004.

Outlook

Equitable Supply’s Appalachian Basin business strategy is focused on growing through expansion of its drilling program and gathering systems. The Company will continue to emphasize operational excellence, including cost control in all areas of its operations. Key elements of Equitable Supply’s strategy include:

· Expanding production through the drilling program. Equitable Supply has a multi-year drilling program which includes increased drilling of conventional wells, down spacing coal bed methane wells, continuing its horizontal drilling efforts and selectively participating in non-operated wells developed on acreage held by the Company. These efforts will enable the Company to continue the growth of its production business. Equitable Supply intends to drill 650 gross operated wells in 2007, including at least 25 horizontal wells, a 16% increase over the 560 gross operated wells drilled in 2006. Through testing a variety of horizontal drilling techniques, the Company expects to better understand reservoir response and the economic viability of reserve development through horizontal drilling. Similarly, through the ongoing infill pilot, the Company will evaluate the economic viability of accelerating production by down spacing coal bed methane wells. Equitable Supply believes that its 772 Bcfe of proved undeveloped reserves will be developed within a reasonable time period (currently estimated to be five years) because Equitable Supply (i) completed substantially all of the wells it drilled in the last three years and (ii) developed proved undeveloped reserves of 60 Bcfe and 70 Bcfe during 2006 and 2005, respectively. Equitable Supply’s plans include developing similar levels of proved undeveloped reserves going forward.

· Investing in midstream gathering and processing in the Appalachian Basin. Infrastructure to support the Company’s increased drilling, to mitigate curtailments on and increase flexibility and reliability of gathering systems and to move gas from wellhead to market presents an acute need but also a significant opportunity for the Company.

· Through its Equitrans affiliate, the Company is constructing the Big Sandy Pipeline, which will provide for a significant increase in midstream throughput capacity. The Company is also planning an upgrade to the Company-operated hydrocarbon processing plant in Langley, Kentucky for completion in early 2008. The projects are projected to cost an aggregate of $191 million.

· The Company plans to expand its gathering systems by approximately 200 miles of gathering line and approximately 25,000 horsepower of compression in 2007. Many of the existing gathering lines will be increased in size to handle these additional volumes and new gathering lines will be constructed to expanded drilling areas. The Company plans to build new compression stations as well as expand existing stations in order to transport gas to sales points on interstate pipelines.

· The Company is also evaluating several other processing, gathering line and compression expansion opportunities in Appalachia and expects to invest in additional projects in 2007 and beyond.

These efforts will assist the Company to move not only its gas, but also third party producer gas, from wellhead to market.

Other Income Statement Items

	Years Ended December 31,
	2006		2005		2004
	(Thousands)
Income (loss) from discontinued operations	$	4,261	$	1,481	$	(18,936	)
Gain on sale of available-for-sale securities, net	—		110,280		3,024
Other income, net	—		1,195		3,692
Gain on exchange of Westport for Kerr-McGee shares	—		—		217,212
Charitable foundation contribution	—		—		(18,226		)

As noted in Item 1, the Company’s NORESCO business is classified as discontinued operations due to the sale of the NORESCO domestic business in 2005 and sale of the Company’s remaining international investment in early 2006. Income (loss) from discontinued operations for 2006 included a tax benefit of $3.2 million due to a reduced tax liability on the sale and after-tax income of $1.1 million resulting from the Company’s reassessment of its remaining obligations for costs incurred related to the sale. Income (loss) from discontinued operations for 2004 included approximately $23.9 million of after-tax impairments on international investments and charges for related reserves, while income (loss) from discontinued operations for 2005 included the reversal of approximately $7.8 million of these reserves (after tax) due to improved business conditions in the related international markets, as well as a $6.4 million tax benefit from the reorganization of the Company’s international assets in 2005. These increases in 2005 as compared to 2004 were partially offset by $18.7 million in after-tax charges recorded in 2005, related to the recording of $13.7 million of income taxes on the sale and other costs incurred as a result of the sale transaction.

During 2005, the Company sold its remaining 7.0 million Kerr-McGee shares resulting in pre-tax gains net of collar termination costs totaling $110.3 million. During 2004, the Company sold 0.8 million Kerr-McGee shares, resulting in a pre-tax gain of $3.0 million.

Other income, net includes pre-tax dividend income relating to the Kerr-McGee shares held by the Company of $1.2 million and $3.1 million for 2005 and 2004, respectively.

As a result of the 2004 merger between Westport and Kerr-McGee, the Company recognized a gain of $217.2 million on the exchange of its Westport shares for Kerr-McGee shares. See Note 9 to the Company’s Consolidated Financial Statements for further information on this transaction.

In 2004, the Company contributed approximately 0.4 million Kerr-McGee shares to Equitable Resources Foundation, Inc., resulting in the Company recording a charitable foundation contribution expense of $18.2 million during 2004. See Note 9 to the Company’s Consolidated Financial Statements for further information on this transaction.

Interest Expense

	Years Ended December 31,
	2006		2005		2004
	(Thousands)

Interest expense	$	47,052	$	44,437	$	42,520

Interest expense increased by $2.7 million from 2005 to 2006 primarily due to a full year of interest expense in 2006 from the issuance of $150 million of notes with a stated interest rate of 5% on September 30, 2005 and an increase in the average annual short-term debt interest rate, partially offset by lower average short-term debt during 2006.

Interest expense increased by $1.9 million from 2004 to 2005 primarily due to the issuance of $150 million of notes with a stated interest rate of 5% on September 30, 2005 and an increase in the average annual short-term debt interest rate. These increases were partially offset by the maturity of $10 million of medium-term notes during 2005.

Average annual interest rates on the Company’s short-term debt were 4.6%, 3.5%, and 1.7% for 2006, 2005 and 2004, respectively.

Capital Resources and Liquidity

Operating Activities

Cash flows provided by operating activities totaled $619.3 million for 2006 as compared to $312.0 million of cash flows used in operating activities for 2005, a net increase of $931.3 million in cash flows provided by operating activities between years. The increase in cash flows provided by operating activities was attributable to the following:

· a $598.7 million net reduction in cash required for margin deposit requirements on the Company’s natural gas hedge agreements, primarily due to significantly higher than normal gas prices in 2005 which resulted in increased deposit remittances in that year;

· a decrease in tax payments to $58.6 million in 2006 from $251.5 million in 2005, primarily due to taxes paid in 2005 related to the sale of the Company’s Kerr-McGee shares, the sale of the NORESCO discontinued operations and the sale of non-core gas properties for significant taxable gains, all in 2005;

· a decrease in accounts receivable of $63.5 million in 2006 compared to an increase of $78.0 million in 2005, primarily due to decreased natural gas prices during 2006 as compared to significant increases in prices in 2005;

· a decrease in inventory of $20.8 million during 2006 as compared to an increase of $85.3 million in 2005, primarily due to increased natural gas prices on volumes stored in 2005 as well as decreased prices in 2006;

partially offset by:

· a decrease in accounts payable of $29.3 million in 2006 compared to an increase of $71.5 million in 2005, primarily due to decreased natural gas prices during 2006 as compared to significant increases in prices in 2005;

· a large reduction in other current liabilities during 2006, as significant amounts were outstanding at December 31, 2005 for which payment was remitted shortly after the 2005 year-end.

Cash flows used in operating activities totaled $312.0 million for 2005 as compared to $180.0 million of cash flows provided by operating activities for 2004, a net increase of $492.0 in cash flows used in operating activities between years. The increase in cash flows used in operating activities was attributable to the following:

· an increase in margin deposit requirements to $317.8 million as of December 31, 2005, from $36.9 million as of December 31, 2004, primarily resulting from increased natural gas prices during 2005;

· an increase in tax payments to $251.5 million in 2005 compared to $23.0 million in 2004 as described above;

· an increase in inventory to $289.9 million as of December 31, 2005, from $204.6 million as of December 31, 2004, primarily due to increased natural gas prices on volumes stored in 2005 compared to 2004;

partially offset by:

· an increase in accounts payable to $242.6 million as of December 31, 2005, from $171.2 million as of December 31, 2004, largely due to increased operating costs resulting from increased drilling activity and higher natural gas prices.

Investing Activities

Cash flows used in investing activities totaled $407.7 million for 2006 as compared to $347.7 million of cash flows provided by investing activities for 2005, a net increase of $755.4 million in cash flows used in investing activities between years. The increase in cash flows used in investing activities was attributable to the following:

· net proceeds of $460.5 million received from the sale of approximately 7.0 million shares of Kerr-McGee Corporation common stock in 2005;

· proceeds of $142.0 million from the sale of certain non-core gas properties and associated gathering assets in 2005;

· an increase in capital expenditures to $404.5 million in 2006 from $275.8 million in 2005. See discussion of capital expenditures below;

· proceeds of $80.0 million from the sale of the domestic operations of the Company’s NORESCO business segment in 2005;

partially offset by:

· the Company’s acquisition of the 99% limited partnership interest in ESP for $57.5 million in 2005.

Cash flows provided by investing activities totaled $347.7 million for 2005 as compared to $158.5 million of cash flows used in investing activities for 2004, a net increase of $506.2 million in cash flows provided by investing activities between years. The increase in cash flows provided by investing activities was attributable to the following:

· a $417.6 million year-over-year increase in net proceeds received from the sale of shares of Kerr-McGee;

· proceeds of $142.0 million from the sale of properties in 2005;

· proceeds of $80.0 million from the sale of NORESCO in 2005;

partially offset by:

· an increase in capital expenditures to $333.3 million in 2005 from $201.8 million in 2004. See discussion of capital expenditures below.

Capital Commitments and Expenditures

The Company forecasts $588 million of capital commitments for 2007. This forecast includes $237 million for well development, $256 million for Supply infrastructure, $92 million for Equitable Utilities and $3 million for Headquarters. A portion of these capital commitments is not expected to impact cash flow until 2008 and beyond.

Capital Expenditures

2007 Forecast

2006 Actual

2005 Actual

2004 Actual

Well development (primarily drilling)

231 million

200 million

$131 million
plus $58
million for the
purchase of ESP

92 million

Supply infrastructure

396 million

137 million

75 million

50 million

Equitable Utilities

82 million

65 million

61 million

56 million

Headquarters

3 million

8 million

4 million

Total*

712 million

405 million

333 million

202 million

* The 2007 capital expenditures do not include amounts related to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. The 2007 capital expenditures include 2006 capital commitments totaling $361 million, including $257 million for Supply infrastructure, $92 million for well development, and $12 million for Equitable Utilities.

Capital expenditures for well development and Supply infrastructure increased in 2006 as compared to 2005 primarily due to an increased drilling and development plan in 2006, capital expended for construction of the Big Sandy Pipeline and other throughput optimization projects. Capital expenditures for well development and Supply infrastructure increased in 2005 as compared to 2004 primarily due to an increased drilling and development plan in 2005.

Capital expenditures for Equitable Utilities increased in 2006 as compared to 2005 primarily due to increased transmission pipeline replacement associated with pipeline integrity under The Pipeline Safety Improvement Act of 2002 and increased gathering infrastructure expenditures. Capital expenditures for Equitable Utilities increased in 2005 as compared to 2004 due to the installation of electronic meter reading technology on meters in the distribution operations, a project that was substantially completed in the third quarter of 2006.

The Company’s capital expenditures forecasted for 2007 represent a significant increase over capital expenditures in 2006. The $231 million targeted for well development in 2007 represents a $31 million increase over 2006 which is attributable to an expanded drilling program. The $396 million forecasted for 2007 Supply infrastructure includes further expansions in infrastructure to support the Company’s current and future drilling plans as well as expenditures for the Big Sandy Pipeline and Langley plant projects. The $82 million forecasted for Equitable Utilities includes $77 million for infrastructure improvements and $5 million for new business development. The infrastructure improvements include improvements to existing distribution lines, an increase in transmission pipeline replacement and additional investment in gathering system improvements and extensions. The new business capital is planned for extensions of existing infrastructure into adjacent geographic areas.

The Company expects to finance its capital expenditures with cash generated from operations and with short-term debt. See discussion in the “Short-term Borrowings” section below regarding the financing capacity of the Company.

Financing Activities

Cash flows used in financing activities totaled $286.5 million for 2006 as compared to $39.2 million of cash flows provided by financing activities for 2005, a net increase of $325.7 million in cash flows used in financing activities between years. The increase in cash flows used in financing activities was attributable largely to the following:

· a $229.3 million decrease in amounts borrowed under short-term loans in 2006 compared to a $69.8 million increase in short-term borrowings in 2005. The decrease in short-term borrowings in 2006 was primarily the result of decreased requirements for funding margin deposits as previously discussed;

· proceeds in 2005 from the September 2005 issuance of $150.0 million of notes with a stated interest rate of 5% and a maturity date of October 1, 2015;

partially offset by:

· no repurchases of shares of the Company’s outstanding common stock under the Company’s share repurchase program during 2006 in anticipation of the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc., compared to repurchases of $122.3 million of common stock in 2005.

Cash flows provided by financing activities totaled $39.2 million for 2005 as compared to $55.8 million of cash flows used in financing activities for 2004, a net increase of $95.0 million in cash flows provided by financing activities between years. The increase in cash flows provided by financing activities from 2004 to 2005 was attributable largely to the following:

· proceeds of $150.0 million from the issuance of notes in September 2005;

partially offset by:

· less of an increase in amounts borrowed under short-term loans in 2005 as compared to 2004.

The Company believes that cash generated from operations, amounts available under its credit facilities and amounts which the Company could obtain in the debt and equity markets given its financial position, are more than adequate to meet the Company’s reasonably foreseeable liquidity requirements. The Company anticipates financing its capital expenditures and the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. through a combination of debt, equity, and asset sales.

Short-term Borrowings

Cash required for operations is affected primarily by the seasonal nature of the Company’s natural gas distribution operations and the volatility of oil and natural gas commodity prices. The Company’s $1.5 billion, five-year revolving credit agreement may be used for working capital, capital expenditures, share repurchases and other purposes including support of the Company’s commercial paper program. Historically, short-term borrowings under the commercial paper program have been used mainly to support working capital requirements during the summer months and are repaid as natural gas is sold during the heating season. Due to decreased natural gas prices and increased margin deposit thresholds with financial institutions during 2006 and resulting decreases in the Company’s net liability position under its natural gas swap agreements, the Company borrowed decreased amounts through its commercial paper program to fund its interest-bearing margin deposits under its natural gas hedge agreements. The amount of commercial paper outstanding at December 31, 2006 was $136.0 million. Interest rates on these short-term loans averaged 4.6% during 2006.

Security Ratings and Financing Triggers

The table below reflects the current credit ratings for the outstanding debt instruments of the Company. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt and its access to the credit markets.

Rating Service	Unsecured Medium-Term Notes	Commercial Paper
Moody’s Investors Service	A-2	P-1
Standard & Poor’s Ratings Services	A -	A-2

On March 2, 2006, Standard & Poor’s Ratings Services placed the Company’s short and long-term credit ratings on CreditWatch with negative implications and Moody’s Investors Service placed the ratings under review for possible downgrade. These actions resulted from the Company’s announcement that it had entered into a definitive agreement to acquire The Peoples Natural Gas Company and Hope Gas, Inc., subject to anti-trust and regulatory approvals. The final ratings outcomes are expected to be determined after the acquisition financing plan has been reviewed by the ratings agencies and the regulatory approval process is near completion.

The Company’s credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If the credit rating agencies downgrade the Company’s ratings, particularly below investment grade, it may significantly limit the Company’s access to the commercial paper market and borrowing costs would increase. In addition, the Company would likely be required to pay a higher interest rate in future financings, incur increased margin deposit requirements with respect to its hedging instruments, and the potential pool of investors and funding sources would decrease.

The Company’s credit ratings on its non-credit-enhanced, senior unsecured long-term debt determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s credit rating, the higher the level of fees and interest rate. As of December 31, 2006, the Company had no outstanding borrowings against these lines of credit. The Company pays facility fees to maintain credit availability.

The Company’s debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. The most important default events include maintaining covenants with respect to maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations, and change of control provisions. The Company’s current credit facility’s financial covenants require a total debt-to-total capitalization ratio of no greater than 65%. The calculation of this ratio excludes accumulated other comprehensive income

(loss). During an acquisition period, which is defined as the period beginning with the funding of the purchase price for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. and ending on the first fiscal quarter end at least 365 days after the funding of such purchase price, the covenant is relaxed from 65% to 70%. As of December 31, 2006, the Company is in compliance with all existing debt provisions and covenants.

Commodity Risk Management

The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices. The Company’s risk management program includes the use of exchange-traded natural gas futures contracts and options and OTC natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes. The preponderance of derivative commodity instruments currently utilized by the Company are fixed price swaps or collars.

During 2006, the Company increased its hedge position for 2007 through 2013. As a result, the approximate volumes and prices of the Company’s total hedge position for 2007 through 2009 are:

	2007		2008		2009
Swaps
Total Volume (Bcf)	56		54		38
Average Price per Mcf (NYMEX)*	$	4.74	$	4.64	$	5.90

Collars
Total Volume (Bcf)	10		10		10
Average Floor Price per Mcf (NYMEX)*	$	7.61	$	7.61	$	7.61
Average Cap Price per Mcf (NYMEX)*	$	11.27	$	11.27	$	11.27

* The above price is based on a conversion rate of 1.05 MMBtu/Mcf

The Company’s current hedged position provides price protection for a substantial portion of expected equity production for the years 2007 through 2009 and a significant portion of expected equity production for the years 2010 through 2013. The Company’s exposure to a $0.10 change in average NYMEX natural gas price is approximately $0.01 per diluted share for 2007 and ranges from $0.01 to $0.03 per diluted share per year for 2008 and 2009. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices. See Note 3 to the Company’s Consolidated Financial Statements for further discussion.

Investment Securities

The Company’s available-for-sale investments as of December 31, 2006 and 2005 consist of approximately $31.3 million and $25.2 million, respectively, of equity securities that are intended to fund certain liabilities for which the Company is self-insured. These investments are recorded at fair market value. During 2005, the Company sold all of its remaining 7.0 million shares of Kerr-McGee in various transactions for total net pre-tax proceeds of $460.5 million and a total pre-tax gain of $110.3 million, net of $95.8 million in costs associated with the termination of the three related variable share forward transactions entered into in June 2004 subsequent to the Westport/Kerr-McGee merger.

Other Items

Off-Balance Sheet Arrangements

The Company has a non-equity interest in a variable interest entity, Appalachian NPI, LLC (ANPI), in which Equitable was not deemed to be the primary beneficiary. As of December 31, 2006, ANPI had $214 million of total assets and $336 million of total liabilities (including $137 million of long-term debt, including current maturities), excluding minority interest.

The Company provides a liquidity reserve guarantee to ANPI, which is subject to certain restrictions and limitations, and is secured by the fair market value of the assets purchased by the Appalachian Natural Gas Trust (ANGT). The Company received a market-based fee for the issuance of the reserve guarantee. As of December 31, 2006, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $50 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45 and has not been modified subsequent to issuance.

The Company has entered into an agreement with ANGT to provide gathering and operating services to deliver ANGT’s gas to market. In addition, the Company receives a marketing fee for the sale of gas based on the net revenue for gas delivered. The revenue earned from these fees totaled approximately $16.8 million for 2006.

In connection with the sale of its NORESCO domestic business in 2005, the Company agreed to maintain certain guarantees which benefit NORESCO. These guarantees, the majority of which predate the sale of NORESCO, became off-balance sheet arrangements upon the closing of the sale of NORESCO. These arrangements include guarantees of NORESCO’s obligations to the purchasers of certain of NORESCO’s contract receivables and agreements to maintain guarantees supporting NORESCO’s obligations under certain customer contracts. In addition, NORESCO and the purchaser agreed that NORESCO would fully perform its obligations under each underlying agreement and that the purchaser or NORESCO would reimburse the Company for losses under the guarantees. The purchaser’s obligations to reimburse the Company are capped at $6 million. The Company determined that the likelihood the Company will be required to perform on these arrangements is remote, and as such, the Company has not recorded any liabilities in its Consolidated Balance Sheets related to these guarantees. The total maximum potential obligation under these arrangements is estimated to be approximately $484 million as of December 31, 2006, and decreases over time as the guarantees expire or the underlying obligations are fulfilled by NORESCO.

See Note 20 to the Consolidated Financial Statements for further discussion of the Company’s guarantees.

Pension Plans

In September 2006, the FASB issued SFAS No. 158, which requires an employer to recognize a benefit plan’s funded status in its statement of financial position, measure a benefit plan’s assets and obligations as of the end of the employer’s fiscal year and recognize the changes in the benefit plan’s funded status in other comprehensive income in the year in which the changes occur. SFAS No. 158’s requirement to recognize the funded status of a benefit plan and the new disclosure requirements were effective for the year-ended December 31, 2006. See Footnote 13 for information regarding the adoption of SFAS No. 158 as of December 31, 2006.

Total pension expense recognized by the Company in 2006, 2005 and 2004, excluding special termination benefits, settlement losses and curtailment losses, totaled $0.1 million, $0.4 million and $0.4 million, respectively. The Company recognized special termination benefits, settlement losses and curtailment losses in 2006, 2005 and 2004 of $3.0 million, $18.4 million and $16.2 million, respectively. As a result of these costs, the Company’s projected benefit obligation decreased by approximately $36.0 million.

During the fourth quarter of 2006, the Company recognized a settlement expense of approximately $2.7 million for an early retirement program.

During 2005, the Company settled its pension obligation with the United Steelworkers of America, Local Union 12050 representing 182 employees. As a result of this settlement, the Company recognized a settlement expense of $12.1 million during 2005. During the fourth quarter of 2005, the Company settled its pension obligation with certain non-represented employees. As a result of this settlement, the Company recognized a settlement expense of approximately $2.4 million in 2005.

Effective December 31, 2004, the Company settled the pension obligation of those non-represented employees (cash balance participants) whose benefits were frozen as of December 31, 2003. As a result of this settlement, the Company recognized settlement expense of $13.4 million in 2004.

The Company made cash contributions of approximately $1.8 million and $20.4 million to its pension plan during 2006 and 2005, respectively, as a result of the previously described settlements. The Company expects to make cash contributions of approximately $1.0 million to its pension plan during 2007. The Company was not required to, and consequently did not make any contribution to its pension plans during the year ended December 31, 2004.

Incentive Compensation

The Company adopted SFAS No. 123R on January 1, 2006, which results in the Company recognizing compensation cost for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The Company previously applied APB No. 25 in accounting for its share-based compensation and consequently did not recognize any compensation cost for its stock option awards. The Company’s estimate of compensation cost for stock options is based on the use of the Black-Scholes option-pricing model. The Black-Scholes model is considered a “theoretical” or probability model used to estimate the price an option would sell for in the market today. The Company does not represent that this method yields an exact value of what an unrelated third party (i.e., the market) would be willing to pay to acquire such options.

The Company adopted SFAS No. 123R using the modified prospective method, under which the Company recorded compensation expense for its unvested stock options beginning January 1, 2006. As such, the Company did not restate any prior period income statement amounts. In addition, the adoption of SFAS No. 123R did not result in any significant changes to the Company’s method for valuing its stock options from that previously used for pro forma disclosures under SFAS No. 123.

The adoption of SFAS No. 123R did not have a significant impact on the Company’s operating results for 2006, as the Company has shifted its compensation focus to the issuance of performance-based units and time-restricted stock awards for which it already recognized compensation expense under generally accepted accounting principles. Management and the Board of Directors believe that such an incentive compensation approach more closely aligns management’s incentives with shareholder rewards than is the case with traditional stock options. No new stock options have been awarded since 2003; all stock options granted subsequent to 2003 have comprised options granted for reload rights associated with previously-awarded options.

The Company recorded approximately $1.0 million of compensation expense related to stock options in 2006, the majority of which related to stock option reloads which immediately vested under the terms of the related stock option award agreements. The majority of the Company’s previously issued stock options were already vested at the time of adoption of SFAS No. 123R, and associated compensation expense yet to be recognized was insignificant. All stock options outstanding as of December 31, 2006 are fully vested, and as such, the Company does not anticipate incurring any additional compensation expense related to currently outstanding stock options.

Had compensation cost been determined based on the fair value at the grant date for prior periods’ stock option grants consistent with the methodology prescribed in SFAS No. 123R, net income would have been reduced by an estimated $1.5 million, or approximately $0.01 per diluted share, for 2005, and an estimated $4.2 million, or approximately $0.04 per diluted share, for 2004.

The Company recorded the following incentive compensation expense in continuing operations for the periods indicated below:

	Year Ended December 31,
	2006		2005		2004
	(millions)
Short-term incentive compensation expense	$	16.7	$	12.9	$	13.7
Long-term incentive compensation expense	26.6		46.4		28.3
Total incentive compensation expense	$	43.3	$	59.3	$	42.0

The long-term incentive compensation expenses are primarily associated with Executive Performance Incentive Programs (“the Programs”) that were instituted starting in 2002. The long-term incentive compensation expenses during 2006 were lower than during 2005 due to a greater number of unvested units outstanding during 2005 than during 2006, as there were two Programs in effect during 2005 and only one in 2006. The long-term incentive compensation expenses during 2005 were higher than during 2004 primarily due to a higher estimated share price for the Programs being expensed, as a result of the Company’s share price appreciation, and a greater number of unvested units outstanding during 2005 than during 2004.

The Company currently estimates 2007 total incentive compensation expense of approximately $38 million.

Federal Legislation

During 2005, the Company completed its review of the American Jobs Creation Act of 2004’s impact on the Company’s executive compensation plans, and the Compensation Committee of the Company’s Board of Directors decided to end the Company’s deferred compensation programs for employees. As a result, in 2005 the Company recorded $15.3 million in tax benefit disallowances under Section 162(m) of the IRC, primarily due to the impairment of previously recorded deferred tax assets related to the employee deferred compensation programs and the 2003 Executive Performance Incentive Program.

Rate Regulation

The Company’s distribution operations and pipeline operations are subject to various forms of regulation as previously discussed. Accounting for the Company’s regulated operations is performed in accordance with the provisions of SFAS No. 71. As described in Notes 1 and 10 to the Consolidated Financial Statements, regulatory assets and liabilities are recorded to reflect future collections or payments through the regulatory process. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of the deferred costs.

Schedule of Contractual Obligations

The following table details the future projected payments associated with the Company’s contractual obligations as of December 31, 2006.

	Total		2007		2008-2009		2010-2011	2012+
	(Thousands)
Long-term debt	$	763,500	$	10,000	$	4,300

Washington, D.C. 20549

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006

DOCUMENTS INCORPORATED BY REFERENCE

TABLE OF CONTENTS

Forward-Looking Statements

Item 1. Business

Item 1A. Risk Factors

Item 1B. Unresolved Staff Comments

Item 2. Properties