Exhibit 99.1

Glossary of Commonly Used Terms, Abbreviations, and Measurements

Commonly Used Terms

AFUDC — Allowance for Funds Used During Construction, carrying costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives, including the cost of financing construction of assets subject to regulation; the capitalized amount for construction of regulated assets includes interest cost and a designated cost of equity for financing the construction of these regulated assets.

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.

CAP — The Customer Assistance Program, a payment plan for low-income residential gas customers that sets a fixed payment for natural gas usage based on a percentage of total household income.

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 area.

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.

frac spread — the price difference between equivalent amounts of natural gas and natural gas liquids.

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.

Glossary of Commonly Used Terms, Abbreviations, and Measurements

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 area 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.

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.

NGL — or Natural Gas Liquids, those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption, or other methods in gas processing plants. Natural gas liquids include primarily propane, butane, ethane, and isobutane.

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 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.

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.

Glossary of Commonly Used Terms, Abbreviations, and Measurements

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”

Dominion — Dominion Resources, Inc. When used in the context of discussion relating to the now terminated acquisition of Peoples and Hope, references to Dominion are as successor by merger to Consolidated Natural Gas Company, the original counterparty to the terminated acquisition agreement.

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”

Hope - Hope Gas, Inc

IRC — Internal Revenue Code of 1986, as amended

IRS — Internal Revenue Service

NYMEX — New York Mercantile Exchange

OTC — Over the Counter

PA PUC — Pennsylvania Public Utility Commission

Peoples - The Peoples Natural Gas Company

SEC — Securities and Exchange Commission

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. 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. 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)”

Glossary of Commonly Used Terms, Abbreviations, and Measurements

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

Mgal = thousand gallons

MMBtu = million British thermal units

MMcf = million cubic feet

MMcfe = million cubic feet of natural gas equivalents

Forward-Looking Statements

Disclosures in this Report 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 and sales volumes, reserves, capital expenditures, financing requirements, hedging strategy, tax position and the 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” and elsewhere in the Company’s Form 10-K for the year ended December 31, 2007.

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.

PART I

Item 1. Business

General

In this report, 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 activities, including production, gathering, processing, transmission, storage and distribution. The Company and its subsidiaries offer energy (natural gas, NGLs and a limited amount of crude oil) products and services to wholesale and retail customers.

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 1,400 employees at the end of 2007, of which 292 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. The labor agreement with the United Steelworkers (USW), Local 12050 will expire on September 25, 2008 and the labor agreement with USW, Local 8-512 will expire on October 15, 2008. In October 2007, one USW bargaining unit which had been operating without a contract since April 19, 2004, voted to decertify the USW as its collective bargaining representative. As a result, these employees are no longer represented by a union. 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, or furnished to, 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

In 2007, the Company reported its results of operations through two business segments: Equitable Supply and Equitable Utilities. These reporting segments reflected the Company’s lines of business and were reported in the same manner in which the Company evaluated its 2007 operating performance.

In January 2008, the Company announced a change in organizational structure and several changes to executive management of the Company to better align the Company to execute its growth strategy for development and infrastructure expansion in the Appalachian Basin. These changes resulted in changes to the Company’s reporting segments effective for fiscal year 2008. The Company’s 2008 results will be reported through three business segments: Equitable Production, Equitable Midstream and Equitable Distribution. The segment disclosures and discussions contained in this Report have been reclassified to reflect all periods presented under the current organizational structure.

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.

Equitable Production

Equitable Production develops, produces and sells natural gas and, to a limited extent, crude oil, in the Appalachian region of the United States. Equitable Production generated approximately 46% of the Company’s net operating revenues in 2007.

Operating through Equitable Production Company and several other affiliates (collectively referred to as “Equitable Production”), Equitable Production is one of the largest owners of proved natural gas reserves in the Appalachian Basin. Equitable Production’s key operating assets include:

· 1,016,960 gross (954,010 net) productive acres

· 2,286,759 gross (2,145,175 net) undeveloped acres

· total proved reserves at December 31, 2007 of 2,682 Bcfe; 65% of which were proved developed

· 12,889 gross (9,309 net) producing wells

The Company’s proved reserves had discounted future net cash flows before income taxes of $3,989 million ($2,473 million after tax) at December 31, 2007. This standardized measure of discounted future net cash flows is calculated using adjusted year-end prices in accordance with SFAS No. 69. See Note 24 to the Consolidated Financial Statements for more information. These reserves are located entirely in the Appalachian Basin, which is characterized by wells with comparatively low rates of annual decline in production, long lives, low production costs and natural gas containing high energy content. Many of the Company’s wells have been producing for decades, 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 and into reservoirs which are known to be productive.

The Company is focused on continuing its significant organic reserve and production growth through its drilling program and believes that this plan will increase its proved reserves based on the quality of the underlying asset base. From 2005 through 2007, Equitable has drilled 997 wells on locations not classified as proved in the reserve report, with less than 3 dry holes drilled. The Company has announced a significant capital commitment plan to support its reserve growth. Capital spending for well development (primarily drilling) is expected to increase to $624 million in 2008 from $304 million in 2007. A substantial portion of the Company’s 2008 drilling efforts will be focused on drilling horizontal wells in shale formations in Kentucky and West Virginia. The

Company is targeting completion of between 250 and 300 horizontal wells in 2008 and expects an average cost per horizontal well of approximately $1.2 million, below its estimates when it began the horizontal drilling program in the latter part of 2006. The Company expects average recovery results in the range of 0.75 Bcfe to 1.50 Bcfe per horizontal well.

The Company drilled 634 gross wells (456 net) in 2007 consisting of 88 horizontal shale wells, 266 coal bed methane wells and 280 other vertical wells. Included in this total are 36 infill wells. Drilling was concentrated within Equitable’s core areas of southwestern Virginia, southeastern Kentucky and southern West Virginia.

The Company’s drilling activity resulted in proved developed reserve additions of approximately 165 Bcfe in 2007. Of the proved developed reserve additions, approximately 43 Bcfe related to proved undeveloped reserves that were transferred to proved developed reserves. The Company’s 2007 extensions, discoveries and other additions of 321.0 Bcfe exceeded the 2007 production of 83.1 Bcfe (a drill bit reserves replacement ratio of 386%).

Equitable Production’s produced volumes for 2007 increased to 83.1 Bcfe, yielding an average proved reserves-to-production ratio (average reserve life) of approximately 32.3 years at year-end 2007 when compared to the Company’s year-end proved reserves of 2,682 Bcfe. Equitable Production’s fourth quarter 2007 average daily sales were 210 MMcfe per day. Daily sales volumes are expected to reach 235 MMcfe by year-end 2008 with total production sales volumes expected to reach 80-81 Bcfe for the year.

See Note 24 to the Company’s Consolidated Financial Statements for information on reserves, reserve activity, costs and the standard measure of discounted future cash flows.

The natural gas produced by Equitable Production 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 processing and transport systems. As a result, the Company has entered into certain discounted sales arrangements to obtain transportation capacity, so 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 natural gas prices which continue to be higher than historical levels. While increased activity can place constraints on availability of labor, equipment, pipeline transport and other resources in the Appalachian Basin, it also provides opportunities for expansion of natural gas gathering activities and potential to attract higher quality rigs and labor providers in the future.

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

Equitable Midstream

Equitable Midstream’s operations comprise the gathering, processing, transportation and storage of natural gas and NGLs. Equitable Midstream has both regulated and non-regulated operations. The regulated activities consist of the Company’s federally-regulated transmission and storage operations and certain state-regulated gathering operations. The non-regulated activities include certain gathering and transportation operations, processing of NGLs and risk management activities. Equitable Midstream generated approximately 33% of the Company’s net operating revenues in 2007.

Gathering and Processing

Equitable Midstream’s gathering and processing operations are carried out by Equitable Gathering, Inc. and several other affiliates (collectively referred to as “Equitable Gathering”). Equitable Gathering derives its gathering

revenues from charges to customers for use of its gathering system in the Appalachian Basin. As of December 31, 2007, the system included approximately 9,900 miles of gathering lines located throughout Pennsylvania, West Virginia, eastern Kentucky and southwestern Virginia. Over 90% 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, L.P. (Equitrans), the Company’s interstate pipeline affiliate. Maintaining these interconnects provides the Company with access to geographically diverse markets.

Gathering system transportation volumes for 2007 totaled 143.3 MMBtu, of which approximately 54% related to the gathering of Equitable Production’s gas volumes, 26% related to third party volumes, 11% related to volumes for other affiliates of the Company, 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 81% of 2007 gathering revenues were from affiliates. As a result of the gathering asset contribution to Nora Gathering, LLC in 2007 discussed in Note 4 to the Company’s Consolidated Financial Statements, operations related to the Nora area gathering activities are no longer included in Equitable Gathering’s operating results. Equitable Gathering records its 50% equity interest in the earnings of Nora Gathering, LLC under the equity method of accounting and reports its share of Nora Gathering, LLC earnings as “equity in earnings of nonconsolidated investments.”

Key competitors for new gathering systems include independent gas gatherers and integrated Appalachian energy companies. See “Outlook” under Equitable Midstream’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 regard to its midstream gathering operations.

Equitable Gathering also owns and operates a hydrocarbon processing plant and gas compression facilities located in Langley, Kentucky. NGLs are recovered at the Company’s processing plant and transported to a fractionation plant owned by a third party for separation into commercial components and subsequent marketing, with the third party retaining an agreed-upon percentage of NGLs delivered. The Company also has contractual processing arrangements whereby the Company sells gas to a third party processor at a weighted average liquids component price. The Company is currently in the process of upgrading the hydrocarbon processing plant in Langley, Kentucky.

Transmission and Storage

Equitable Midstream’s transmission and storage operations are carried out by Equitrans and Equitable Energy, LLC (Equitable Energy) through Company-owned and operated transmission and underground storage facilities. These operations offer gas transportation, storage, risk management 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 UGI Energy Services, Inc.

Equitrans’ operations are subject to regulation by the FERC and consist of approximately 900 miles of transmission and storage lines and interconnections with five major interstate pipelines. The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania. The addition of the Big Sandy Pipeline is expected to add 68 miles of transmission line and 9,000 horse power of installed capacity in Kentucky. Equitrans has 14 natural gas storage reservoirs with approximately 496 MMcf per day of peak delivery capability and 63 Bcf of storage capacity of which 32 Bcf is working gas. These storage reservoirs are clustered, with 8 in northern West Virginia and 6 in southwestern Pennsylvania. In 2007, approximately 69% of transportation volumes and approximately 82% of transportation revenues were from affiliates.

Services and products offered by Equitable Energy 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 energy 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.

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 will be operated by Equitrans. On October 16, 2007, the FERC granted Equitrans’ request for an extension of time until March 31, 2008 to complete construction of the Big Sandy Pipeline.

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. This settlement allows Equitrans to institute an annual surcharge for the tracking and recovery of all costs (operations, maintenance and return on invested capital) incurred on and after September 1, 2005, related to Equitrans’ Pipeline Safety Program under the Pipeline Safety Improvement Act of 2002. Filings to modify the surcharge must be made on or before March 1st of each year for approval by the FERC. On March 29, 2007, the Company received approval, subject to refund, to institute the surcharge, and on April 1, 2007, the Company commenced billing the surcharge. On November 26, 2007, the FERC removed the refund condition and approved the surcharge effective April 1, 2007. The Company anticipates that additional filings to modify the surcharge will continue to be made in future years to recover costs incurred in connection with its Pipeline Safety Program.

Equitrans’ firm transportation contracts on its mainline system expire between 2009 and 2011 and the firm transportation contracts on its Big Sandy Pipeline expire in 2018. The Company anticipates that the capacity associated with these expiring contracts will be remarketed such that the capacity will remain fully subscribed.

Equitable Distribution

Equitable Distribution’s operations comprise state-regulated distribution of natural gas by Equitable Gas Company (Equitable Gas), Equitable Gas’s off-system sales activities which include the purchase and delivery of gas to a customer at mutually agreed-upon points on facilities not owned by the Company and the sale of energy-related products and services by Equitable Homeworks, LLC. Equitable Distribution generated approximately 21% of the Company’s net operating revenues in 2007.

The service territory for Equitable Distribution 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 275,000 customers, consisting of 256,400 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 and contracts with affiliates are subject to comprehensive regulation by the PA PUC and the WV PSC and the issuance of securities is subject to regulation by the PA PUC. 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.

Equitable Gas 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 cost recovery programs. Equitable Gas’ tariffs for commercial and industrial customers allow for negotiated rates in limited circumstances. 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 2007 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.

Pennsylvania law requires that local distribution companies develop and implement programs to assist low income customers with paying their gas bills. The costs of these programs are recovered through rates charged to other residential customers. Equitable Gas has several such programs including the CAP. In October 2006, Equitable Gas submitted a request for PA PUC approval to increase funding to support the increasing costs of its CAP. On September 27, 2007, the PA PUC issued an order approving an increase to Equitable’s surcharge, which is designed to offset the costs of the CAP. The revised surcharge went into effect on October 2, 2007. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information.

On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion’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 Peoples and Hope. In light of the continued delay in achieving the final legal approvals for this transaction, the Company and Dominion agreed to terminate the definitive agreement pursuant to a mutual termination agreement entered into on January 15, 2008. See Item 3, “Legal Proceedings” in the Company’s 2007 Form 10-K for a description of proceedings initiated by the Federal Trade Commission for the purpose of challenging the proposed acquisition.

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 2007, 2006 and 2005.

	2007		2006		2005
Equitable Production:
Natural gas equivalents sales	23	%	24	%	26	%
Equitable Midstream:
Marketed natural gas sales	18	%	13	%	17	%
Equitable Distribution:
Residential natural gas sales	23	%	24	%	26	%

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 20 to the Consolidated Financial Statements for information regarding environmental matters.

Item 2. Properties

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

Equitable Production. This segment’s production 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 69% 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, 2007, the Company estimated its total proved reserves to be 2,682 Bcfe, including proved undeveloped reserves of 923 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:

	2007		2006		2005
Natural Gas:
MMcf produced	82,401		80,698		78,105
Average well-head sales price per Mcfe sold (net of hedges)	$	4.53	$	4.55	$	5.06
Crude Oil:
Thousands of Bbls produced	119		112		108
Average sales price per Bbl	$	62.06	$	58.35	$	53.07

Average production cost, including severance taxes, of natural gas and crude oil during 2007, 2006 and 2005 was $0.740, $0.762 and $0.771 per Mcfe, respectively.

	Natural Gas	Oil
Total productive wells at December 31, 2007:
Total gross productive wells	12,867	22
Total net productive wells	9,290	19
Total in-process wells at December 31, 2007:
Total gross productive wells	107	—
Total net productive wells	83	—

Total acreage at December 31, 2007:
Total gross productive acres		1,016,960
Total net productive acres		954,010
Total gross undeveloped acres		2,286,759
Total net undeveloped acres		2,145,175

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

	2007	2006	2005
Exploratory wells:
Productive	—	—	—
Dry	—	—	—
Development wells:
Productive	455.8	455.0	344.2
Dry	0.5	1.0	1.0

Selected data by state (at December 31, 2007 unless otherwise noted):

	Kentucky		West Virginia		Virginia		Pennsylvania		Ohio(a)	Total
Natural gas and oil production (MMcfe) — 2007	37,488		21,205		23,044		1,377		—	83,114
Natural gas and oil production (MMcfe) — 2006	35,699		20,534		23,723		1,415		—	81,371
Natural gas and oil production (MMcfe) — 2005	33,849		19,924		21,913		2,247		822	78,755

Net revenue interest (%)	84.7	%	63.8	%	52.4	%	88.6	%	—	68.0	%

Total gross productive wells (b)	4,968		4,696		2,538		687		—	12,889
Total net productive wells	4,132		2,914		1,576		687		—	9,309

Total gross acreage	1,440,903		1,202,114		536,503		124,199		—	3,303,719
Total net acreage	1,374,619		1,085,761		514,674		124,131		—	3,099,185

Proved developed reserves (Bcfe)	926		498		307		28		—	1,759
Proved undeveloped reserves (Bcfe)	423		380		120		—		—	923
Proved developed and undeveloped reserves (Bcfe)	1,349		878		427		28		—	2,682

Gross proved undeveloped drilling locations	1,270		1,285		856		—		—	3,411
Net proved undeveloped drilling locations	1,229		1,260		474		—		—	2,963

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

(b) At December 31, 2007, the Company had approximately 116 multiple completion wells.

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 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 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 Pennsylvania are primarily in tight sand formations with depths ranging from 3,000 feet to 5,000 feet and average spacing of 40 acres.

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

Equitable Midstream. The gathering and processing operations own or operate approximately 9,900 miles of gathering line and 233 compressor units comprising 128 compressor stations with approximately 200,000 horse power of installed capacity, as well as other general property and equipment.

Substantially all of the gathering operations’ 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.

		Kentucky		West Virginia		Virginia		Pennsylvania		Total
Approximate miles of gathering line		3,400		4,700		1,500		300		9,900

The gathering and processing business also owns a hydrocarbon processing plant and gas compression facilities located in Langley, Kentucky. The Company is currently in the process of upgrading the hydrocarbon processing plant.

The transmission and storage operations own and operate underground storage and transmission facilities in Pennsylvania and West Virginia. These operations consist of approximately 900 miles of transmission and storage lines and interconnections with five major interstate pipelines. The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania. The addition of the Big Sandy Pipeline is expected to add 68 miles of transmission line and 9,000 horse power of installed capacity in Kentucky. Equitrans has 14 natural gas storage reservoirs with approximately 496 MMcf per day of peak delivery capability and 63 Bcf of storage capacity of which 32 Bcf is working gas. These storage reservoirs are clustered, with 8 in northern West Virginia and 6 in southwestern Pennsylvania.

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

Equitable Distribution. 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 distribution operations consist of approximately 4,100 miles of pipe in Pennsylvania, West Virginia and Kentucky.

Headquarters. The corporate headquarters and other operations are located in leased office space in Pittsburgh, Pennsylvania.

Item 6. Selected Financial Data

	As of and for the year ended December 31,
	2007		2006		2005		2004(a)		2003(a)
	(Thousands, except per share amounts)
Operating revenues	$	1,361,406	$	1,267,910	$	1,253,724	$	1,045,183	$	876,574
Income from continuing operations before cumulative effect of accounting change (b)	$	257,483	$	216,025	$	258,574	$	298,790	$	165,750
Income from continuing operations before cumulative effect of accounting change per share of common stock (c)
Basic	$	2.12	$	1.79	$	2.14	$	2.42	$	1.34
Diluted	$	2.10	$	1.77	$	2.09	$	2.37	$	1.31
Total assets (d)	$	3,936,971	$	3,282,255	$	3,342,285	$	3,205,346	$	2,948,073
Long-term debt (d)	$	753,500	$	763,500	$	766,500	$	626,500	$	647,000
Cash dividends declared per share of common stock (c)	$	0.880	$	0.870	$	0.820	$	0.720	$	0.485

(a) Amounts for 2004 and 2003 have been reclassified to reflect the operating results of the NORESCO segment as discontinued operations.

(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.

(d) Certain previously reported amounts have been reclassified to conform to the current year presentation.

See Item 1A, “Risk Factors,” in the Company’s 2007 Form 10-K and 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 2007 was $257.5 million, or $2.10 per diluted share, compared with $216.0 million, or $1.77 per diluted share, for 2006, and $258.6 million, or $2.09 per diluted share, for 2005.

The $41.5 million increase in income from continuing operations from 2006 to 2007 resulted from several factors, including the 2007 pre-tax gain of $126.1 million on the sale of assets in the Nora area. At Equitable Distribution, revenues increased primarily due to colder weather in Equitable Gas’s service territory. At Equitable Midstream, an increase in transmission and storage revenues due to increased storage asset optimization transactions and utilization of contractual transmission capacity to increase its wholesale marketing activities and an increase in gathering and processing net operating revenues due to higher frac spreads for NGLs extracted in 2007 were partially offset by a decrease in revenues due to the 2006 favorable impact of the settlement of the Equitrans rate case. At Equitable Production, revenues increased due to higher production sales volumes.

The increases in revenue between years were partially offset by a $70.2 million increase in purchased gas costs, a $46.2 million increase in incentive compensation expense, the $10.1 million write-off of deferred transaction costs related to the termination of the proposed acquisition of Peoples and Hope, and $9.7 million in higher depletion, depreciation and amortization, primarily at Equitable Production. In addition, higher labor costs and charges for certain legal reserves, settlements and related expenses partially offset the increases in income from continuing operations.

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 now terminated acquisition of Peoples and Hope. The Company also recorded a reserve for certain legal disputes. The impact of lower realized selling prices ($38.0 million) and warmer weather ($9.3 million) also contributed to the decrease between years.

These unfavorable effects on income from continuing operations between 2005 and 2006 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 higher transmission and storage net operating income primarily due to favorable storage asset optimization ($30.0 million), reduced expenses related to the executive performance incentive programs ($22.7 million), higher gathering and processing operating income ($19.7 million) and higher production sales volumes ($11.4 million).

The Company’s effective tax rate for its continuing operations for the year ended December 31, 2007, was 35.9% compared to 33.7% for the year ended December 31, 2006, and 37.2% for the year ended December 31, 2005. The higher effective tax rate in 2007 is the result of several factors including a change in the West Virginia state tax law and a reduced 2006 rate resulting from the release of state valuation allowances related to state net operating loss carryovers. 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. 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 $65.3 million, $21.9 million and $48.0 million in 2007, 2006 and

2005, respectively, were not allocated to business segments. The higher unallocated expenses in 2007 and 2005 compared to 2006 primarily relate to lower long-term incentive expenses in 2006.

The Company has reconciled each segment’s operating income, equity in earnings of nonconsolidated investments and other income to the Company’s consolidated operating income, equity in earnings of nonconsolidated investments and other income 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 Production

Overview

Equitable Production is focused on organic reserve and production growth through its drilling program. The Company drilled 634 gross wells (456 net wells) in 2007, including 88 horizontal shale wells. Proved reserves increased 185 Bcfe (7%) to 2,682 Bcfe during the year.

Equitable Production’s revenues for 2007 increased approximately 1% compared to 2006 revenues. Sales volumes increased more than 5% from 2006, excluding volumes from properties sold during 2007, primarily as a result of increased production from the 2007 and 2006 drilling programs partially offset by the normal production decline in the Company’s producing wells.

Operating expenses at Equitable Production increased 13% primarily due to charges for legal reserves, settlements and related expenses, as well as higher depletion resulting from increased drilling investments, as the Company continues to expand its development in the Appalachian Basin.

During 2007, the Equitable Production segment sold to Pine Mountain Oil and Gas, Inc. (PMOG), a subsidiary of Range Resources Corporation (Range), a portion of the Company’s interests in certain gas properties in the Nora area totaling approximately 74 Bcf of proved reserves. See Note 4 to the Company’s Consolidated Financial Statements for further discussion. The Company is working to obtain the third party consents required to complete the transaction on a portion of the property not included in the 2007 closing. A final closing covering the remainder of the gas properties included in the above transaction would reduce the Company’s proved reserves by a maximum of approximately 9 Bcf.

During the third quarter of 2007, the Equitable Production segment purchased an additional working interest of approximately 13.5% in certain gas properties in the Roaring Fork area totaling approximately 12.3 Bcf of proved reserves from the minority interest holders. See Note 5 to the Company’s Consolidated Financial Statements for further discussion of this transaction.

Results of Operations

	Years Ended December 31,
	2007			2006			% change 2007 - 2006		2005			% change 2006 - 2005

OPERATIONAL DATA

Production:
Natural gas and oil production (MMcfe) (a)	83,114			81,371			2.1		78,755			3.3
Company usage, line loss (MMcfe)	(6,035		)	(5,215		)	15.7		(4,897		)	6.5
Natural gas inventory usage, net (MMcfe)	—			—			—		51			(100.0	)
Total sales volumes (MMcfe)	77,079			76,156			1.2		73,909			3.0

Average (well-head) sales price ($/Mcfe)	$	4.59		$	4.60		(0.2	)	$	5.09		(9.6	)

Lease operating expenses (LOE), excluding production taxes ($/Mcfe)	$	0.31		$	0.29		6.9		$	0.28		3.6
Production taxes ($/Mcfe)	$	0.43		$	0.47		(8.5	)	$	0.49		(4.1	)
Production depletion ($/Mcfe)	$	0.70		$	0.62		12.9		$	0.59		5.1

Production depletion	$	58,264		$	50,330		15.8		$	46,750		7.7
Other depreciation, depletion and amortization (DD&A)	3,820			3,141			21.6		2,485			26.4
Total DD&A	$	62,084		$	53,471		16.1		$	49,235		8.6

Capital expenditures (thousands) (b)	$	328,080		$	205,047		60.0		$	183,859		11.5

FINANCIAL DATA (thousands)

Total operating revenues	$	364,396		$	359,526		1.4		$	384,885		(6.6	)

Operating expenses:
LOE, excluding production taxes	25,361			23,818			6.5		22,427			6.2
Production taxes (c)	36,123			38,198			(5.4	)	38,288			(0.2	)
Exploration expense	862			802			7.5		768			4.4
Selling, general and administrative (SG&A)	37,947			27,814			36.4		18,636			49.2
Impairment charges	—			—			—		519			(100.0	)
DD&A	62,084			53,471			16.1		49,235			8.6
Total operating expenses	162,377			144,103			12.7		129,873			11.0
Operating income	$	202,019		$	215,423		(6.2	)	$	255,012		(15.5	)

(a) 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.

(b) 2007 capital expenditures include $24.4 million for the acquisition of working interests in wells in the Roaring Fork area and 2005 capital expenditures include $57.5 million for the acquisition of a limited partnership interest in Eastern Seven Partners, L.P. (ESP).

Fiscal Year Ended December 31, 2007 vs. December 31, 2006

Equitable Production’s operating income totaled $202.0 million for 2007 compared to $215.4 million for 2006, a decrease of $13.4 million between years, primarily due to an increase in operating expenses, partially offset by increased sales volumes.

Total operating revenues were $364.4 million for 2007 compared to $359.5 million for 2006. The $4.9 million increase in operating revenues was primarily due to a 1% increase in total sales volumes as a result of the 2007 and 2006 drilling programs, partially offset by the normal production decline in the Company’s wells and the 2007 sale to PMOG of interests which provided sales of 3,044 MMcfe during 2006. In addition, the average well-head sales price decreased $0.01 per Mcfe primarily due to a decrease in NYMEX natural gas prices, partially offset by a higher percentage of unhedged gas sales and a higher realized hedge price.

Operating expenses totaled $162.4 million for 2007 compared to $144.1 million for 2006. The $18.3 million increase in operating expenses was due to increases of $10.1 million in SG&A, $8.6 million in DD&A and $1.5 million in LOE, excluding production taxes, partially offset by a decrease of $2.1 million in production taxes. The increase in SG&A was primarily due to increased legal reserves, settlements and related expenses in 2007 compared to the reduction of certain liability reserves in 2006, partially offset by 2006 increases to the reserve established for uncollectible accounts. The increase in DD&A was primarily due to increased depletion expense resulting from both increases in the unit rate ($6.9 million) and volume ($1.0 million). The $0.08 increase in the depletion rate is primarily attributable to the increased investment in oil and gas producing properties. The increase in LOE, excluding production taxes, was attributable to personnel costs, environmental costs and liability insurance costs. The decrease in production taxes was primarily due to a decrease in severance taxes arising out of the sale of assets in the Nora area.

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

Equitable Production’s operating income totaled $215.4 million for 2006 compared to $255.0 million for 2005, a decrease of $39.6 million between years, primarily due to a decrease in well-head sales price and an increase in operating expenses, partially offset by increased sales volumes.

Total operating revenues were $359.5 million for 2006 compared to $384.9 million for 2005. The $25.4 million decrease in operating revenues was primarily due to a 10% per Mcfe decrease in the average well-head sales price, partially offset by a 3% increase in total sales volumes. The $0.49 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 and increased prices on hedged volumes. The 2005 price 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 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.

Operating expenses totaled $144.1 million for 2006 compared to $129.9 million for 2005. The $14.2 million increase in operating expenses was due to increases of $9.2 million in SG&A, $4.3 million in DD&A and $1.4 million in LOE, excluding production taxes. The increase in SG&A was the result of reserves established in connection with certain legal disputes and bad debt expenses. The increase in DD&A was primarily due to a $0.03 per Mcfe increase in the unit depletion rate ($2.1 million) and increased produced volumes ($1.5 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, excluding production taxes, 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. In addition, while production taxes decreased only slightly, this decrease was the result of decreased severance taxes ($2.5 million), partially offset by increased property taxes ($2.4 million). 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 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 impairment charges in 2005 were related to the Company’s relocation of its corporate headquarters and other operations to its new consolidated office space.

See “Capital Resources and Liquidity” section for discussion of Equitable Production’s capital expenditures during 2007, 2006 and 2005.

Outlook

Equitable Production’s business strategy is focused on organic growth of the Company’s natural gas reserves. Key elements of Equitable Production’s strategy include:

· Expanding reserves and production through horizontal drilling in Kentucky and West Virginia. The Company’s capital commitments budget for 2008 includes $536 million for well development. Through this capital program the Company will seek to maximize the value of its existing asset base by developing its large acreage position, which the Company believes holds significant production and reserve growth potential. A substantial portion of the Company’s 2008 drilling efforts will be focused on drilling horizontal wells in shale formations in Kentucky and West Virginia.

· Exploiting additional reserve potential through key emerging development plays. In 2008, the Company will examine the potential for exploitation of gas reserves in new geological formations and through different technologies. Plans include re-entry wells in the Devonian shale, testing the Devonian shale in Virginia, and high and low pressure Marcellus shale wells. In addition, the Company will obtain proprietary seismic data in order to evaluate deep drilling opportunities for 2009. Approximately 15% of wells drilled in 2008 are expected to be located in these emerging development plays in the Appalachian Basin.

Equitable Midstream

Overview

Equitable Midstream’s net operating revenues increased by 3% from 2006 to 2007. This increase was primarily due to higher average NGL sales prices in the gathering and processing business and favorable storage asset optimization in the transmission and storage business. The storage revenues are primarily driven by the optimization of the Company’s 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 wider for transactions settled in 2007 than they were for contracts which settled in 2006. Increases in net operating revenues were partially offset by a 5% increase in total operating expenses in 2007 due primarily to an overall increase in activity for the Midstream businesses.

During 2007, the Equitable Midstream segment contributed certain Nora area gathering facilities and pipelines to Nora Gathering, LLC, a newly formed entity that is equally owned by the Company and PMOG, in exchange for a 50% equity interest in the LLC and cash. See Note 4 to the Company’s Consolidated Financial Statements for further discussion of this transaction. As a result of the gathering asset contribution, gathered volumes, gathering revenues and gathering-related expenses related to the Nora area gathering activities are no longer included in Equitable Midstream’s operating results. However, Equitable Midstream records its 50% equity interest in the earnings of Nora Gathering, LLC in equity in earnings of nonconsolidated investments. Also in 2007, the Equitable Midstream segment purchased certain gathering assets in the Roaring Fork area from the minority interest holders. See Note 5 to the Company’s Consolidated Financial Statements for further discussion of this transaction.

On April 5, 2006, Equitrans entered into a settlement with the FERC that allows Equitrans to institute an annual surcharge for the tracking and recovery of all costs (operations, maintenance and return on invested capital) incurred on and after September 1, 2005, related to Equitrans’ Pipeline Safety Program under the Pipeline Safety

Improvement Act of 2002. Filings to modify the surcharge must be made on or before March 1st of each year for approval by the FERC. On March 29, 2007, the Company received approval, subject to refund, to institute the surcharge, and on April 1, 2007, the Company commenced billing the surcharge. On November 26, 2007, the FERC removed the refund condition and approved the surcharge effective April 1, 2007. As a result of the FERC order, in 2007 Equitrans recognized $1.2 million in deferred revenue as well as $0.7 million in pipeline integrity and safety maintenance costs that were deferred pending receipt of the final FERC order. The Company anticipates that additional filings to modify the surcharge will continue to be made in future years to recover costs incurred in connection with its Pipeline Safety Program.

Results of Operations

	Years Ended December 31,
	2007		2006		% change 2007 - 2006		2005		% change 2006 - 2005

OPERATIONAL DATA

Gathering and processing:
Gathered volumes (MMBtu)	143,338		157,248		(8.8	)	153,305		2.6
Average gathering fee ($/MBtu)	$	0.84	$	0.79	6.3		$	0.69	14.5
Gathering and compression expense ($/MBtu)	$	0.35	$	0.30	16.7		$	0.25	20.0
NGLs sold (Mgal) (a)	72,430		70,963		2.1		69,918		1.5
Average NGL sales price($/gal)	$	1.07	$	0.95	12.6		$	0.92	3.3

Transmission and storage:
Transmission pipeline throughput (MMBtu)	53,514		53,151		0.7		52,196		1.8
Storage capacity (Bcfe)	63		57		10.5		57		—

Net operating revenues (thousands):
Gathering and processing	$	149,590	$	140,312	6.6		$	106,670	31.5
Transmission and storage	112,325		113,080		(0.7	)	84,772		33.4
Total net operating revenues	$	261,915	$	253,392	3.4		$	191,442	32.4

Net operating income (thousands):
Gathering and processing	$	65,003	$	57,047	13.9		$	37,330	52.8
Transmission and storage	75,429		80,130		(5.9	)	50,139		59.8
Total net operating income	$	140,432	$	137,177	2.4		$	87,469	56.8

Capital expenditures (thousands)	$	433,719	$	146,512	196.0		$	93,707	56.4

(a) NGLs sold includes NGLs recovered at the Company’s processing plant and transported to a fractionation plant owned by a third party for separation into commercial components, net of volumes retained, as well as equivalent volumes sold at liquid component prices under the Company’s contractual processing arrangements with third parties.

	Years Ended December 31,
	2007		2006			% change 2007 - 2006		2005		% change 2006 - 2005
FINANCIAL DATA (thousands)

Total operating revenues	$	591,608	$	554,071		6.8		$	483,146	14.7
Purchased gas costs	329,693		300,679			9.6		291,704		3.1
Net operating revenues	261,915		253,392			3.4		191,442		32.4

Operating expenses:
Operating and maintenance (O&M)	66,155		63,811			3.7		52,226		22.2
SG&A	28,995		27,609			5.0		26,193		5.4
Impairment charges	—		(1,027		)	(100.0	)	1,501		(168.4	)
Depreciation and amortization	26,333		25,822			2.0		24,053		7.4
Total operating expenses	121,483		116,215			4.5		103,973		11.8
Operating income	$	140,432	$	137,177		2.4		$	87,469	56.8

Equity in earnings of nonconsolidated investments	$	2,648	$	—		100.0		$	—	—
Other income, net	$	7,253	$	1,149		531.2		$	93	1,135.5

Fiscal Year Ended December 31, 2007 vs. December 31, 2006

Equitable Midstream’s operating income totaled $140.4 million for 2007 compared to $137.2 million for 2006, an increase of $3.2 million between years. An increase in net operating revenues was largely offset by increased operating expenses.

Total net operating revenues were $261.9 million for 2007 compared to $253.4 million for 2006. The $8.5 million increase in total net operating revenues was due primarily to increases in gathering and processing net operating revenues, partially offset by a decrease in transmission and storage net operating revenues. The $9.3 million increase in gathering and processing net operating revenues was due to higher sales prices for the NGL products sold in 2007 as compared to 2006, a 2% increase in NGL volumes sold and a 6% increase in the average gathering fee, partially offset by a 9% decline in gathered volumes. Commodity market prices for propane and other NGLs increased significantly in 2007 compared to 2006. The increase in average gathering fee is reflective of the Company’s commitment to ensuring that this fee is sufficient to cover increasing operating costs. The decrease in gathered volumes is primarily the result of a reduction in volumes gathered for Equitable Production due to the contribution of gathering facilities and pipelines to Nora Gathering, LLC, partially offset by increased Company production. The $0.8 million decrease in transmission and storage net operating revenues was primarily due to the positive effect of the Equitrans rate case settlement of $7.0 million recorded in 2006, partially offset by storage asset optimization realized in 2007 as the Company used contractual storage capacity to capture unusually high summer-to-winter price spreads, Equitrans’ Pipeline Safety surcharge that was formally approved by the FERC in November 2007 and increased firm transportation rates year over year. The storage price spreads were captured at a time of high volatility and the transactions settled in 2007.

Operating expenses totaled $121.5 million for 2007 compared to $116.2 million for 2006. The $5.3 million increase in operating expenses was due to increases of $2.4 million in O&M and $1.4 million in SG&A, $1.0 million in impairment charge reversals recorded in 2006 and an increase of $0.5 million in DD&A. The increase in O&M was due to increased expense in 2007 for the Company’s gathering and transmission facilities primarily due to increased electricity charges on newly installed electric compressors, increased field line and compressor maintenance, increased field labor and related employment costs, increased compliance and maintenance costs and

increased fleet-related costs, as well as the recognition of $0.7 million of pipeline safety costs that were deferred pending the FERC order on the Equitrans Pipeline Safety surcharge. Partially offsetting these increases in O&M was a decrease in O&M expenses relating to the gathering asset contribution to Nora Gathering, LLC and a decrease due to a 2006 pension and other postretirement benefits charge of $3.3 million for an early retirement program relating to the gathering and processing business. The increase in SG&A is primarily due to higher labor costs including higher incentive compensation costs, partially offset by decreased SG&A for the gathering assets contributed to Nora Gathering, LLC. The increase in DD&A was primarily due to the increased investment in gathering infrastructure during 2007 partially offset by decreased depreciation relating to the gathering asset contribution to Nora Gathering, LLC.

Equity in earnings of nonconsolidated investments totaled $2.6 million for 2007 and related to equity earnings recorded for Equitable Gathering’s investment in Nora Gathering, LLC.

Other income represents AFUDC-Equity and the $6.2 million increase from 2006 to 2007 was primarily the result of increased capital spending for the Big Sandy Pipeline as well as spending on pipeline safety and integrity projects.

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

Equitable Midstream’s operating income totaled $137.2 million for 2006 compared to $87.5 million for 2005, an increase of $49.7 million between years. An increase in net operating revenues of $62.0 million was partially offset by increased operating expenses of approximately $12.2 million.

Total net operating revenues were $253.4 million for 2006 compared to $191.4 million for 2005, a $62.0 million increase between years. The $33.6 million increase in gathering and processing net operating revenues was attributable to a 15% increase in the average gathering fee, a 3% increase in gathered volumes, higher realized spreads for the NGL products sold in 2006 as compared to 2005, a 2% increase in NGL volumes sold and the favorable impact of a 2005 loss on fuel and retention in excess of then-current rates. The increase in average gathering fee is reflective of the Company’s commitment to ensuring that this fee is sufficient to cover increasing operating costs, along with higher gas prices and related operating cost increases. The increase in gathered volumes was the result of increased gathered volumes for Equitable Production in 2006, mostly offset by the negative impact of the sale of certain gathering assets in 2005 and third-party customer volume shut-ins caused by maintenance projects on interstate pipelines. Net operating revenues from NGL sales were higher in 2006 due to positive frac spreads in 2006 and a negative overall frac spread in 2005. The 2005 negative frac spread primarily resulted from the volatility of natural gas prices in the latter half of 2005 following Hurricane Katrina. The $28.3 million increase in transmission and storage net operating revenues resulted from increased pipeline capacity and storage asset opportunities realized in the volatile natural gas commodity price environment, the 2006 settlement of Equitrans’ 2004 and 2005 FERC rate cases 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; in addition, new contract rates and billing determinants in the settlement resulted in a $6.1 million increase.

Operating expenses totaled $116.2 million for 2006 compared to $104.0 million for 2005. The $12.2 million increase in operating expenses was due to increases of $11.6 million in O&M, $1.7 million in DD&A and $1.4 million in SG&A, partially offset by a $2.5 million decrease in impairment charges. The increase in O&M was primarily due to increased compressor station operation and repair costs, including electricity on newly installed compressors, increased property taxes and increased field labor and related employment costs, as well as the $3.3 million pension and other postretirement benefits charge. These factors were partially offset by an overall reduction in costs as a result of the sale of gathering assets in 2005. The increase in DD&A was mainly a result of increased capital spending in the gathering business which more than offset a reduction due to assets sold. The increase in SG&A was primarily due to the recognition of previously deferred post-retirement benefit obligation expenses in connection with the FERC rate case settlement in 2006, partially offset by the 2005 recognition of a $3.2 million charge related to the termination and settlement of certain defined benefit pension plans. 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. A portion of these impairment charges were reversed in 2006.

Other income primarily represents AFUDC-Equity for the construction of the FERC-regulated Big Sandy Pipeline. The $1.0 million increase from 2005 to 2006 is primarily a result of the Big Sandy Pipeline project starting in 2006.

See “Capital Resources and Liquidity” section for discussion of Equitable Midstream’s capital expenditures during 2007, 2006 and 2005.

Outlook

Equitable Midstream’s business strategy is focused on growing through expansion of its midstream infrastructure programs in the Appalachian Basin. The most significant challenge continuing to face the Company and the Appalachian Basin in general relates to the availability of pipeline infrastructure required to get the gas to market. As the Company’s Equitable Production business and other producers continue to expand the development of their reserves, the need for such infrastructure becomes more vital.

· Investing in midstream transportation, gathering and processing in the Appalachian Basin. The Company’s investment in midstream infrastructure is focused on its transportation, gathering and processing capacity including completion of the Big Sandy Pipeline and the Langley processing facility. Infrastructure investment will help mitigate curtailments and increase the flexibility and reliability of the Company’s gathering systems in transporting gas to market. The Company has adopted a “pipe-driven” business model whereby production growth will occur in conjunction with the completion of a series of pipeline and compression projects known as “corridors.” Each corridor will radiate out from a central processing facility, such as the Company’s Langley facility, which will then connect to larger pipes, such as the Big Sandy Pipeline, that transport gas to interstate markets.

· Growth and expansion of storage, gathering and commercial operations. Equitable Midstream plans to continue to provide disciplined incremental earnings growth through its storage, gathering and commercial operations, including expanding these assets where there are additional opportunities to provide economical storage services in the Company’s operating regions.

· Expansion of market footprint. As Equitable grows its Appalachian production base, the Company is exploring opportunities to expand its market footprint in the Northeast and Mid-Atlantic gas sales markets. To this end, the Company has previously announced its intent to participate with Tennessee Gas Pipeline in the development of the Northeast Passage Project. In addition, the Company continues discussions with other interstate pipelines in the growing Mid-Atlantic and Southeast markets.

Equitable Distribution

Overview

Equitable Distribution’s net operating revenues increased 7% from 2006 to 2007 primarily due to colder weather in Equitable Gas’s service territory in 2007. Increases in net operating revenues were offset by increases in total operating expenses in 2007 of 16%, primarily due to the write-off of Peoples and Hope acquisition-related costs that were previously deferred and higher corporate allocations.

The weather in Equitable Gas’ service territory in 2007 was 7% colder than 2006, but was still 9% warmer than the 30-year National Oceanic and Atmospheric Administration (NOAA) average for the Company’s service territory. The weather in 2006 was 15% warmer than the 30-year average.

Pennsylvania law requires that local distribution companies develop and implement programs to assist low income customers with paying their gas bills. The costs of these programs are recovered through rates charged to other residential customers. Equitable Gas has several such programs including the CAP. In October 2006, Equitable Gas submitted a request for PA PUC approval to increase funding to support the increasing costs of its CAP. On September 27, 2007, the PA PUC issued an order approving an increase to Equitable’s surcharge, which is designed to offset the costs of CAP. The revised surcharge went into effect on October 2, 2007.

On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion’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 Peoples and Hope. In light of the continued delay in achieving the final legal approvals for this transaction, the Company and Dominion agreed to terminate the definitive agreement pursuant to a mutual termination agreement entered into on January 15, 2008. As a result, in the fourth quarter of 2007, the Company recognized a charge of $10.1 million for acquisition costs that were previously deferred. Proceedings were initiated by the Federal Trade Commission for the purpose of challenging the Company’s proposed acquisition of Peoples. See Item 3, “Legal Proceedings” in the Company’s 2007 Form 10-K for a description of these proceedings.

Results of Operations

	Years Ended December 31,
	2007		2006			% change 2007 - 2006		2005		% change 2006 - 2005
OPERATIONAL DATA

Heating degree days (30 year average = 5,829)	5,332		4,976			7.2		5,543		(10.2	)

Residential sales and transportation volume (MMcf)	23,494		21,014			11.8		24,680		(14.9	)
Commercial and industrial volume (MMcf)	25,971		23,841			8.9		25,368		(6.0	)
Total throughput (MMcf) — Distribution	49,465		44,855			10.3		50,048		(10.4	)

Net operating revenues (thousands):
Residential	$	99,050	$	92,497		7.1		$	102,457	(9.7	)
Commercial & industrial	42,558		42,519			0.1		46,857		(9.3	)
Off-system and energy services	19,021		15,647			21.6		16,914		(7.5	)
Total net operating revenues	$	160,629	$	150,663		6.6		$	166,228	(9.4	)

Capital expenditures (thousands)	$	41,684	$	48,721		(14.4	)	$	47,534	2.5

FINANCIAL DATA (thousands)

Total operating revenues	$	624,744	$	586,194		6.6		$	651,771	(10.1	)
Purchased gas costs	464,115		435,531			6.6		485,543		(10.3	)
Net operating revenues	160,629		150,663			6.6		166,228		(9.4	)

Operating expenses:
O & M	41,613		40,690			2.3		43,190		(5.8	)
SG&A	64,454		49,631			29.9		51,861		(4.3	)
Impairment charges	—		(1,369		)	(100.0	)	2,340		(158.5	)
DD&A	20,021		19,938			0.4		19,483		2.3
Total operating expenses	126,088		108,890			15.8		116,874		(6.8	)
Operating income	$	34,541	$	41,773		(17.3	)	$	49,354	(15.4	)

Fiscal Year Ended December 31, 2007 vs. December 31, 2006

Equitable Distribution’s operating income totaled $34.5 million for 2007 compared to $41.8 million for 2006. An increase in net operating revenues was more than offset by increased operating expenses primarily related to the fourth quarter of 2007 write-off of deferred acquisition costs that resulted from the termination of the agreement to acquire Peoples and Hope.

Net operating revenues were $160.6 million for 2007 compared to $150.7 million for 2006. The $9.9 million increase in net operating revenues was primarily a result of weather that was 7% colder than the prior year, resulting in a 2,480 MMcf increase in residential sales and transportation volumes from 2006 to 2007. Commercial and industrial volumes increased 2,130 MMcf from 2006 to 2007 primarily due to an increase in usage by one industrial customer. These high volume industrial sales have very low margins and did not significantly impact total net operating revenues.

Operating expenses totaled $126.1 million for 2007 compared to $108.9 million for 2006. Operating expenses for 2007 included a $10.1 million write-off of costs previously deferred related to the now terminated agreement to acquire Peoples and Hope, while 2006 included a one-time benefit of $1.4 million from the partial reversal of a 2005 impairment charge in connection with the Company’s office consolidation. Other increases in operating expenses included higher corporate overhead allocations, increased labor costs including information technology enhancements and costs associated with a customer experience study of Equitable Gas customers. These increases were partially offset by a reduction in bad debt expense as a result of the continued organizational focus on collections, which resulted in reductions in delinquent accounts receivable and net write-offs.

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

Equitable Distribution’s operating income totaled $41.8 million for 2006 compared to $49.4 million for 2005. The $7.6 million decrease in operating income was primarily due to a reduction in net operating revenues resulting from weather that was 15% warmer than the 30-year average and the impact of transition planning costs incurred for the now terminated agreement to acquire Peoples and Hope, partially offset by lower expenses related to defined benefit pension plans and impairment charges.

Net operating revenues were $150.7 million for 2006 compared to $166.2 million for 2005. The $15.5 million decrease in net operating revenues was primarily a result of a 3,666 MMcf decrease in residential sales and transportation volumes due to weather that was 10% warmer than the prior year.

Operating expenses totaled $108.9 million for 2006 compared to $116.9 million for 2005. Operating expenses for 2005 included $12.8 million in charges related to the termination and settlement of certain defined benefit pension plans and a $2.3 million loss related to the office impairment in connection with the Company’s relocation into its new, consolidated office space. Operating expenses for 2006 included $12.3 million of transition planning costs incurred for the now terminated agreement to acquire Peoples and Hope and the reversal of $1.4 million of the 2005 office impairment charge. Excluding these items, operating expenses decreased $3.8 million, which was primarily a result of a decrease in bad debt expense totaling $5.2 million, partially offset by costs related to the holding company implementation of $1.6 million in 2006. The improvement in bad debt expense is 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.

See “Capital Resources and Liquidity” section for discussion of Equitable Distribution’s capital expenditures during 2007, 2006 and 2005.

Outlook

Equitable Distribution’s business strategy is focused on efficiently and effectively operating the Company’s assets to optimize its return. Equitable Distribution will seek to enhance the value of its existing distribution assets by establishing a reputation for excellent customer service; effectively managing its capital spending; improving the efficiency of its work force through superior work management; and continuing to leverage technology throughout its operations. Equitable Distribution is currently evaluating a base rate case filing for the Pennsylvania distribution

business in order to improve returns through regulatory arrangements that fairly balance the interests of customers and shareholders.

Other Income Statement Items

	Years Ended December 31,
	2007		2006		2005
	(Thousands)
Gain on sale of assets, net	$	126,088	$	—	$	—
Gain on sale of available-for-sale securities, net	1,042		—		110,280
Other income	7,645		1,442		1,539
Income from discontinued operations	—		4,261		1,481

During 2007, the Equitable Production segment sold to Pine Mountain Oil and Gas, Inc. (PMOG) a portion of the Company’s interests in certain gas properties in the Nora area totaling approximately 74 Bcf of proved reserves. Also during 2007, the Equitable Midstream segment contributed certain Nora area gathering facilities and pipelines to Nora Gathering, LLC in exchange for a 50% equity interest in Nora Gathering, LLC and cash. These transactions resulted in a net gain of $126.1 million. See Note 4 to the Company’s Consolidated Financial Statements for further discussion of these transactions.

As discussed in Note 9 to the Company’s Consolidated Financial Statements, in 2007 the Company reviewed its investment portfolio (including its investment allocation) and sold equity funds with a cost basis of $6.3 million for total proceeds of $7.3 million, resulting in the Company recognizing a gain of $1.0 million. 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.

In 2007 and 2006, other income primarily relates to the equity portion of AFUDC. Prior to 2007, the amount of AFUDC — Equity was not significant and was included as an offset to interest expense in the Statements of Consolidated Income.�� As a result of the significance of the carrying costs related to the Big Sandy Pipeline and other regulated projects, AFUDC — Equity has been reclassified to other income in the Statements of Consolidated Income for all periods presented. Other income in 2005 includes pre-tax dividend income of $1.2 million relating to the Kerr-McGee shares held by the Company in that year.

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 from discontinued operations for 2006 included a tax benefit of $3.2 million due to a reduced tax liability on the sale of the domestic business 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 of the domestic business. Income from discontinued operations for 2005 included the reversal of approximately $7.8 million of reserves (after tax) established in 2004, 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 2005 income items 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 of the domestic NORESCO business.

Interest Expense

	2007		2006		2005

Interest expense	$	47,669	$	48,494	$	44,781

Interest expense decreased by $0.8 million from 2006 to 2007 primarily as a result of the repayment of long-term debt. A 1.2% increase in the average annual short-term interest rate was more than offset by an overall reduction in weighted average net short-term debt outstanding, in part due to the proceeds from the sale of properties during the year.

Interest expense increased by $3.7 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.

Average annual interest rates on the Company’s short-term debt were 5.8%, 4.6% and 3.5% for 2007, 2006 and 2005, respectively.

Capital Resources and Liquidity

Operating Activities

Cash flows provided by operating activities totaled $426.7 million for 2007 as compared to $617.8 million for 2006, a net decrease of $191.1 million in cash flows provided by operating activities between years. The decrease in cash flows provided by operating activities was attributable to the following:

· a $5.9 million increase in cash required for margin deposits on the Company’s natural gas hedge agreements in 2007 compared to a $317.8 million decrease in cash required for margin deposits in 2006. The decrease in 2006 was primarily due to significantly higher than normal gas prices in 2005 which resulted in increased deposit remittances in that year;

· a decrease in accounts receivable of $2.5 million in 2007 compared to a decrease in accounts receivable of $63.5 million in 2006. The decrease in 2006 was primarily due to decreased natural gas prices during 2006 as compared to significant increases in prices in 2005;

partially offset by:

· an increase in other current liabilities of $99.4 million in 2007 compared to a decrease of $31.9 million in 2006, primarily related to long-term incentive compensation plans and the timing of payments;

· an increase in accounts payable of $65.9 million in 2007 compared to a decrease of $29.3 million in 2006. The increase in accounts payable in 2007 was primarily the result of increased capital spending, while the decrease in 2006 was primarily due to decreased natural gas prices during 2006.

Cash flows provided by operating activities totaled $617.8 million for 2006 as compared to $312.3 million of cash flows used in operating activities for 2005, a net increase of $930.1 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 higher natural gas prices on volumes stored in 2005 compared to 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 $31.9 million 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.

Investing Activities

Cash flows used in investing activities totaled $590.1 million for 2007 as compared to $406.3 million for 2006, a net increase of $183.8 million in cash flows used in investing activities between years. The increase in cash flows used in investing activities was attributable to the following:

· an increase in capital expenditures to $776.7 million in 2007 from $403.1 million in 2006. See discussion of capital expenditures below;

· an increase of $28.1 million in 2007 from the Company’s purchase of an additional working interest of approximately 13.5% in the Roaring Fork area in Virginia;

partially offset by:

· proceeds received in the second quarter of 2007 from the sale and contribution of assets. See Note 4 to the Company’s Consolidated Financial Statements.

Cash flows used in investing activities totaled $406.3 million for 2006 as compared to $348.1 million of cash flows provided by investing activities for 2005, a net increase of $754.4 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 $403.1 million in 2006 from $275.5 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 Eastern Seven Partners, L.P. (ESP) for $57.5 million in 2005. See discussion of capital expenditures below.

Capital Commitments and Expenditures

The Company forecasts approximately $1.2 billion of capital commitments for 2008. This forecast includes $536 million for well development, $648 million for midstream infrastructure, and $37 million for distribution infrastructure projects. Over 50% of the capital commitments in 2008 are for drilling and infrastructure in Kentucky. A portion of these capital commitments is not expected to impact cash flow until 2009 and beyond.

Capital Expenditures

2008 Forecast

2007 Actual

2006 Actual

2005 Actual

Well development (primarily drilling)

624 million

304 million

205 million

131 million

Midstream infrastructure

555 million

430 million

146 million

88 million

Distribution infrastructure

37 million

42 million

49 million

48 million

Acquisitions and other

5 million

29 million

3 million

66 million

***

Total

1,221 million

805 million

403 million

333 million

* The forecasted 2008 capital expenditures include 2007 capital commitments totaling $422 million, including $259 million for midstream infrastructure, $155 million for well development, and $8 million for Equitable Distribution.

** Includes $28.1 million related to the Company’s purchase of an additional working interest of approximately 13.5% in the Roaring Fork area in Virginia and certain gathering assets from a minority interest holder. See Note 5 to the Company’s Consolidated Financial Statements.

*** Includes $57.5 million for the acquisition of the 99% limited partnership interest in Eastern Seven Partners, L.P. See Note 5 to the Company’s Consolidated Financial Statements.

Capital expenditures for well development and midstream infrastructure increased in 2007 as compared to 2006 primarily due to an increased drilling and development program in 2007, capital expended for construction of the Big Sandy Pipeline, upgrades to the Langley plant and increased investment in gathering system compression and pipelines. Capital expenditures for well development and midstream infrastructure increased in 2006 as compared to 2005 primarily due to an increased drilling and development program in 2006, capital expended for construction of the Big Sandy Pipeline and other throughput optimization projects. Capital expenditures for distribution infrastructure decreased in 2007 as compared to 2006 primarily due to the installation of electronic meter reading technology on meters in 2006, a project that was substantially completed in the third quarter of 2006. Capital expenditures for distribution infrastructure in 2006 were comparable to such expenditures in 2005.

The Company’s forecasted 2008 capital expenditures represent a significant increase over capital expenditures in 2007. The $624 million targeted for well development in 2008 represents a $320 million increase over 2007 which is driven by expected increased drilling activity of up to 750 wells in 2008 compared to 634 wells in 2007. The ultimate number of wells drilled will depend on the mix of horizontal shale wells, vertical conventional wells in sandstone and shale, and coal bed methane wells. The Company plans to drill between 250 and 300 horizontal wells in 2008, with the intent to drill more if efficiency improvements experienced in 2007 continue. The $555 million forecast for 2008 midstream infrastructure includes incremental Appalachian midstream infrastructure to move new gas volumes to market, including approximately 60,000 horsepower of compression and approximately 400 miles of gathering lines. The $37 million forecasted for Equitable Distribution infrastructure projects primarily relates to mainline replacement.

The Company expects to finance its capital expenditures with cash generated from operations, short-term debt and capital market transactions completed during 2008. See discussion in the “Financing Activities” section below regarding the financing capacity of the Company.

For federal income tax purposes the Company typically deducts as intangible drilling costs (IDC) approximately 70% of its vertical drilling costs and 75% of its horizontal drilling costs in the year incurred. The Company expects that the IDC deduction resulting from its increased drilling program coupled with accelerated tax depreciation for expansion of the gathering infrastructure will most likely put the Company into an overall federal tax net operating loss position in 2008 which is likely to continue as long as expansion in Appalachia continues. The result of this change is that the Company expects minimal cash taxes for the foreseeable future.

Financing Activities

Cash flows provided by financing activities totaled $245.1 million for 2007 as compared to $286.5 million of cash flows used in financing activities for 2006, a net increase of $531.6 million in cash flows provided by financing activities between years. The increase in cash flows provided by financing activities was attributable largely to the following:

· a $314.0 million increase in amounts borrowed under short-term loans in 2007 compared to a $229.3 million decrease in short-term borrowings in 2006. The increase in short-term borrowings in 2007 was for the purposes of funding capital expenditures and working capital requirements.

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 now terminated agreement to acquire Peoples and Hope, compared to repurchases of $122.3 million of common stock in 2005.

The Company is committed to maintaining a cost effective capital structure and intends to finance future cash requirements, including the portion of the 2008 capital expenditure forecast not financed by cash flows from operations, using capital market transactions.

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 have been used mainly to support working capital and capital expenditure requirements during the summer months and were generally repaid as natural gas was sold during the heating season.

Due to the volatility in the short-term debt markets during the second half of 2007, the Company determined that its lowest cost of short term borrowings would be obtained by borrowing directly under its $1.5 billion revolving credit facility. The Company will continue to evaluate whether the commercial paper markets or direct loans under the revolving credit facility offer the lowest cost of short-term debt capital, and will obtain short-term funding to meet its liquidity needs from either source as needed. As of December 31, 2007, the Company had

outstanding short-term loans under the revolving credit facility of $450.0 million and no commercial paper balances. Interest rates on short-term borrowings averaged 5.8% during 2007.

The Company’s short-term borrowings generally have original maturities of three months or less.

Security Ratings and Financing Triggers

The table below reflects the credit ratings for the outstanding debt instruments of the Company as of February 9, 2008. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt and its access to the credit markets.

	Unsecured
	Medium-Term	Commercial
Rating Service	Notes	Paper
Moody’s Investors Service	Baa1	P-2
Standard & Poor’s Ratings Services	BBB	A-2

On January 15, 2008, Standard & Poor’s Ratings Services (S&P) lowered its corporate credit and senior unsecured ratings on Equitable Resources, Inc. to ‘BBB’ from ‘A-’ and removed the Company from CreditWatch. S&P had put Equitable on CreditWatch with negative implications on March 2, 2006 because of the possibility that the Company would finance its purchase of Peoples and Hope largely with debt. Following Equitable’s announcement of the termination of the purchase agreement, S&P removed the Company from CreditWatch and lowered its ratings, with a negative outlook. In its publication regarding the downgrade, S&P stated that Equitable has been rapidly expanding its gas exploration and production and gas-gathering activities in the Appalachian region and the negative outlook reflects the increasing influence of Equitable’s exploration and production operations over the entire Company.

On October 31, 2007, Moody’s Investors Service (Moody’s) completed its review of the Company’s credit rating and downgraded Equitable’s ratings to ‘Baa1’ for senior unsecured long-term debt and ‘Prime-2’ for commercial paper. Moody’s stated that its rating reflects the Company’s increased tolerance for business and financial risk as the Company adopts a more growth-oriented strategy. Moody’s did not take any further ratings action following the Company’s announcement of the termination of the Peoples and Hope purchase agreement.

The Company’s credit ratings may be subject to further 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. For example, the Company was required to post cash margin deposits of approximately $100 million as of January 31, 2008. Had the Company’s ratings not been downgraded, the cash margin deposit required on January 31, 2008 would have been less than $5 million. The margin amount can change as a result of gas prices, as well as credit thresholds set forth in agreements between the hedging counterparties and the Company.

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, 2007, the Company had $450.0 million of borrowings against these lines of credit. The Company also pays facility fees to maintain credit availability. As a result of the S&P credit rating downgrade, the Company’s annualized facility fees changed from approximately $1.0 million to $1.5 million.

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 the effects of accumulated other comprehensive income (loss). As of December 31, 2007, 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.

As a result, the approximate volumes and prices of the Company’s total hedge position for 2008 through 2010 are:

	2008		2009		2010
Swaps
Total Volume (Bcf)	50		37		35
Average Price per Mcf (NYMEX)*	$	4.62	$	5.91	$	5.96

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 2008 and a significant portion of expected equity production for the years 2009 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 2008 and ranges from $0.02 to $0.03 per diluted share per year for 2009 and 2010. 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 the Quantitative and Qualitative Disclosures About Market Risk in Item 7A and Note 3 to the Company’s Consolidated Financial Statements for further discussion.

Other Items

Off-Balance Sheet Arrangements

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 total maximum potential obligation under these arrangements is estimated to be approximately $388 million as of December 31, 2007, and decreases over time as the guarantees expire or the underlying obligations are fulfilled by

NORESCO. 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.

In November 1995, Equitable, through a subsidiary, guaranteed a tax indemnification to the limited partners of Appalachian Basin Partners, LP (ABP) for any potential tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closes. The Company does not have any recourse provisions with third parties or any collateral held by third parties associated with this guarantee that could be liquidated to recover amounts paid, if any, under the guarantee. As of December 31, 2007, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $46 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. Additionally, based on the status of the Company’s IRS examinations, the Company has determined that any potential loss from this guarantee is remote.

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, 2007, ANPI had $200 million of total assets and $333 million of total liabilities (including $120 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 that limit the amount of the guarantee to the calculated present value of the project’s future cash flows from the preceding year-end until the termination date of the agreement. This liquidity reserve guarantee 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, 2007, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $20 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.

As noted above, on January 15, 2008, S&P lowered the Company’s corporate credit and senior unsecured rating to ‘BBB.’ As a result of this downgrade, the terms of this guarantee require the Company to provide a letter of credit in favor of ANPI as security for its obligations under the liquidity reserve guarantee. The amount of this letter of credit requirement is approximately $26.4 million and is expected to decline over time under the terms of the liquidity reserve guarantee.

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 $15.8 million, $16.8 million and $15.5 million for 2007, 2006 and 2005, respectively.

See Note 21 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 required 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. The Company adopted SFAS No. 158 as of December 31, 2006.

Total pension expense recognized by the Company in 2007, 2006 and 2005, excluding special termination benefits, settlement losses and curtailment losses, totaled $0.6 million, $0.1 million and $0.4 million, respectively. The Company recognized special termination benefits, settlement losses and curtailment losses in 2007, 2006 and 2005 of $1.4 million, $3.0 million and $18.4 million, respectively.

During 2007, the Company recognized a settlement expense of $0.5 million due to a plan design change for a specific union and an additional settlement expense for $0.5 million due to the transfer of some current active employees to non-union employment.

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 USW, 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.

The Company made cash contributions of approximately $1.3 million, $1.8 million and $20.4 million to its pension plan during 2007, 2006 and 2005, respectively, as a result of the previously described settlements. The Company expects to make cash contributions of less than $0.1 million to its pension plan during 2008.

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, in its financial statements. 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’s recent compensation practices have focused primarily on the issuance of performance-based units and time-restricted stock awards for which it recognizes compensation expense over the applicable vesting periods. Management and the Board of Directors believe that such an incentive compensation approach closely aligns management’s incentives with shareholder rewards. No new stock options were awarded in 2007; all stock options granted subsequent to 2003 have comprised options granted for reload rights associated with previously-awarded options.

The Company recorded approximately $0.2 million and $1.0 million, respectively, of compensation expense related to stock options in 2007 and 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, 2007 are fully vested.

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.

The Company recorded the following incentive compensation cost, including amounts both expensed and capitalized, in its financial statements for the periods indicated below:

	Year Ended December 31,
	2007		2006		2005
	(millions)
Short-term incentive compensation	$	22.9	$	16.7	$	12.9
Long-term incentive compensation	70.0		26.6		46.4
Total incentive compensation	$	92.9	$	43.3	$	59.3

The long-term incentive compensation is primarily associated with Executive Performance Incentive Programs (the Programs) that were instituted starting in 2002. The vesting of the awards granted under the 2005

Executive Performance Incentive Program (2005 Program) will occur contingent upon a combination of the level of total shareholder return relative to a fixed group of peer companies and the Company’s average absolute return on total capital, during the four year performance period ending December 31, 2008. Payment of awards is expected to be made in cash and stock based on the price of the Company’s common stock at the end of the performance period, December 31, 2008. The Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards. In 2007, the Company increased its assumptions for both the payout multiple and ultimate share price at the vesting date (December 31, 2008) based on a review of the Company’s performance relative to its peer group under the 2005 Program as well as the significant appreciation in the Company’s stock price during the period. As a result, the Company recognized an additional $42.4 million of long-term incentive expenses associated with the 2005 Program in 2007. The increase in incentive compensation recorded under the Company’s short term incentive plan of $6.2 million from 2006 to 2007 includes an increase of approximately $3.7 million in expensed short-term incentive costs and an increase of approximately $2.5 million in capitalized short-term incentive costs. The increase in short-term incentive compensation was primarily due to favorable asset optimization results realized by Equitable Midstream, the favorable results of Equitable Production’s horizontal drilling program and an overall increase in employee headcount in 2007.

Long-term incentive compensation during 2006 was lower than during 2005 due to a greater number of unvested units outstanding under the Programs during 2005 than during 2006, as two Programs were in effect during 2005 and only one during 2006.

The Company currently forecasts fiscal year 2008 total incentive compensation cost under existing plans of approximately $59 million, including expense of $36 million for the 2005 Program. The 2005 Program terminates on December 31, 2008. The Compensation Committee is currently developing a successor long-term incentive compensation program.

Rate Regulation

The Company’s distribution operations, transmission and storage operations and a portion of its gathering 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, 2007.

	Total		2008		2009-2010		2011-2012		2013+
	(Thousands)
Long-term debt	$	753,500	$	—	$	4,300	$	206,000	$	543,200
Interest payments	453,042		44,317		88,148		86,054		234,523
Purchase obligations	191,140		39,111		70,378		57,109		24,542
Other liabilities	154,592		142,788		—		11,804		—
Operating leases	140,773		38,928		65,490		6,016		30,339
Pension and other post retirement benefits	108,133		12,208		23,363		22,604		49,958
Total contractual obligations	$	1,801,180	$	277,352	$	251,679	$	389,587	$	882,562

The purchase obligations amount relates primarily to annual commitments relating to the Company’s natural gas distribution and production operations for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to ten years. Approximately $25.5 million of these annual costs are believed to be recoverable in customer rates.

The other liabilities line represents the total estimated payout for the 2005 Executive Performance Incentive Program and the 2007 Supply Long-Term Incentive Program. See section titled “Critical Accounting Policies Involving Significant Estimates” and Note 17 to the Consolidated Financial Statements for further discussion regarding factors that affect the ultimate amount of the payout of these obligations.

Operating leases are primarily entered into for various office locations and warehouse buildings, as well as dedicated drilling rigs in support of the Company’s drilling program. In 2007, the Company entered into an agreement with Highlands Drilling, LLC (Highlands) for Highlands to provide drilling equipment and services to the Company. These obligations totaled approximately $84.4 million as of December 31, 2007 and are included in the operating lease obligations above. Also included in operating lease obligations are $1.3 million of terminated operating leases for facilities deemed to have no economic benefit to the Company as a result of the relocation of the Company to a new corporate headquarters in 2005.

As discussed in Note 6 to the Consolidated Financial Statements, the Company had a total FIN 48 liability for unrecognized tax benefits at December 31, 2007 of $50.8 million. The Company is currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities; therefore, this amount has been excluded from the schedule of contractual obligations presented above.

Contingent Liabilities and Commitments

In June 2006, the West Virginia Supreme Court of Appeals issued a decision involving interpretation of certain types of oil and gas leases of an unrelated party, in a case where a class of royalty owners in the state of West Virginia had filed a lawsuit claiming that the defendant underpaid royalties by deducting certain post-production costs not permitted by such types of leases and not paying a fair value for the gas produced from the royalty owners’ leases. In January 2007, the jury in the aforementioned case returned a verdict in favor of the plaintiff royalty owners, awarding the plaintiffs significant compensatory and punitive damages for the alleged underpayment of royalties. While the defendant has appealed the verdict, this decision may ultimately impact other royalty interest rights in West Virginia. Claims have been brought against others in the oil and gas industry, including the Company. The Company is vigorously defending its case and believes that the claims and facts in the unrelated lawsuit can be differentiated from those asserted against the Company. Nevertheless, the Company has reviewed its West Virginia royalty agreements and established a reserve it believes to be appropriate. See Item 3, “Legal Proceedings” for additional description of this litigation.

In the ordinary course of business, various other 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.

See Note 20 to the Consolidated Financial Statements for further discussion of the Company’s contingent liabilities and commitments.

Corporate Reorganization to a Holding Company Structure

The Company has filed applications with the PA PUC and WV PSC to reorganize into a holding company. The Company is pursing a holding company reorganization because the Company believes that the separation of its state-regulated distribution operations into a new subsidiary will better segregate its regulated and unregulated businesses and improve overall financing flexibility. To effect the reorganization, the Company intends to merge with a second tier subsidiary (MergerSub), which will result in a first tier subsidiary (New EQT) becoming the new publicly traded parent company of the Equitable Resources family of companies. Following the merger, the Company will transfer to New EQT all of the assets and liabilities of the Company other than those of the Company’s existing Equitable Gas Company division and New EQT and its subsidiaries will continue to conduct the business and operations that the Company and its subsidiaries conducted immediately before the effective time of the reorganization.

The Company successfully completed a request for direction to holders of notes under the indentures governing its long-term debt. The Company has also received a no-action letter from the SEC satisfactorily addressing certain elements of the proposed reorganization. The Company expects to complete the reorganization upon receipt of PA PUC and WV PSC approvals.

The chart below reflects the simplified organizational structure of the Company immediately before the holding company reorganization:

The chart below reflects the simplified organizational structure of the Company immediately after the holding company reorganization:

Critical Accounting Policies Involving Significant Estimates

The Company’s significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Form 10-K. The discussion and analysis of the Consolidated Financial Statements and results of operations are based upon Equitable’s Consolidated Financial Statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. The following critical accounting policies, which were reviewed and approved by the Company’s Audit Committee, relate to the Company’s more significant judgments and estimates used in the preparation of its Consolidated Financial Statements. There can be no assurance that actual results will not differ from those estimates.

Share-Based Compensation: The Company awards share-based compensation in connection with specific programs established under the 1999 Long-Term Incentive Plan. The Company treats its Executive Performance Incentive Programs as variable plan liabilities. The actual cost to be recorded for the 2005 Executive Performance Incentive Program (2005 Program) will not be known until the measurement date, which is December 31, 2008, requiring the Company to estimate the total expense to be recognized. The number of units to be paid out under the 2005 Program is dependent upon a combination of a level of total shareholder return relative to the performance of a

peer group and the Company’s average absolute return on capital during the four-year performance period. In 2007, the Company implemented the 2007 Supply Long-Term Incentive Program (2007 Supply Program), also a variable plan liability. The number of units to be paid out under the 2007 Supply Program is dependent upon the achievement of pre-determined total sales volumes targets and the satisfaction of certain applicable employment requirements. The Company reviews the assumptions for both programs on a quarterly basis and adjusts its accrual when changes in these assumptions result in a material change in the value of the ultimate payout. In the current period, the Company estimated that the performance measures for the 2005 Program would be met at 225% of the full value of the units and that the estimated end of 2008 share price would be $60.00. This was an increase from the Company’s assumptions in 2006 of 175% of the full value of the units and an estimated end of 2008 share price of $45.00, which resulted in a significant compensation expense charge in 2007. The Company estimated that the performance measures for the 2007 Supply Program would be met at 100% of the full value of the units and that the estimated end of 2010 share price would be $72.00.

The Company believes that the accounting estimates related to share-based compensation are “critical accounting estimates” because they are likely to change from period to period based on changes in the market price of the Company’s shares, the performance of the peer group for the 2005 Program and the achievement of pre-determined total sales volumes targets for the 2007 Supply Program. Additionally, the impact on net income of these changes can be material. Management’s assumptions regarding these performance factors require significant judgment. In regard to the 2005 Program, each peer company’s inherent volatility combined with the volatility in commodity prices make it difficult to provide sensitivity metrics to demonstrate the impact a change in the Company’s stock price will have on the estimated payout. However, assuming no change in the attainment of performance measures, a 10% increase in the Company’s stock price assumption for December 31, 2008 would result in an increase in 2008 compensation expense under the Long-Term Incentive Plan of approximately $14 million. A 10% decrease in the Company’s stock price assumptions would result in a decrease in 2008 compensation expense of the same amount.

Income Taxes: The Company accounts for income taxes under the provisions of SFAS No. 109, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the Company’s Consolidated Financial Statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. See Note 6 to the Company’s Consolidated Financial Statements for further discussion.

The Company has recorded deferred tax assets principally resulting from mark-to-market hedging losses recorded in other comprehensive loss, deferred revenues and expenses and state net operating loss carryforwards. The Company has established a valuation allowance against a portion of the deferred tax assets related to the state net operating loss carryforwards, as it is believed that it is more likely than not that these deferred tax assets will not all be realized. The Company also recorded a $0.1 million charge in 2007 and 2006 and a $15.3 million charge in 2005 related to compensation deferred and accrued under certain executive compensation plans, as it was determined that this compensation will not be deductible under Section 162(m) of the IRC. No other valuation allowances have been established, as it is believed that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize these assets. Any change in the valuation allowance would impact the Company’s income tax expense and net income in the period in which such a determination is made.

The Company accounts for uncertainty in income taxes under the provisions of FIN 48. This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The recognition threshold is the first step which requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If the first step is satisfied, then the Company must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. See Note 6 to the Company’s Consolidated Financial Statements for further discussion.

The Company believes that the accounting estimate related to income taxes is a “critical accounting estimate” because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income and provide judgment on the amount of financial statement benefit that an uncertain tax position will realize upon ultimate settlement. To the extent that it is believed to be more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, a valuation allowance must be established. Significant management judgment is required in determining any valuation allowance recorded against deferred tax assets and in determining the amount of financial statement benefit to record for uncertain tax positions. The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed and considers the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. Evidence used for the valuation allowance includes information about the Company’s current financial position and results of operations for the current and preceding years, as well as all currently available information about future years, including the Company’s anticipated future performance, the reversal of deferred tax assets and liabilities and tax planning strategies available to the Company. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement.

Contingencies and Asset Retirement Obligations: The Company is involved in various regulatory and legal proceedings that arise in the ordinary course of business. The Company records a liability for contingencies based upon its assessment that a loss is probable and the amount of the loss can be reasonably estimated. The recording of contingencies is guided by the principles of SFAS No. 5. The Company considers many factors in making these assessments, including history and specifics of each matter. Estimates are developed in consultation with legal counsel and are based upon an analysis of potential results.

In addition to the obligation to record contingent liabilities, SFAS No. 143 requires that the Company accrue a liability for legal asset retirement obligations based on an estimate of the timing and amount of their settlement. For oil and gas wells, the fair value of the Company’s plugging and abandonment obligations is required to be recorded at the time the obligations are incurred, which is typically at the time the wells are drilled. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion, and amortization, and the initial capitalized costs are depleted over the useful lives of the related assets.

The Company is required to operate and maintain its natural gas pipeline and storage systems, and intends to do so as long as supply and demand for natural gas exists, which the Company expects for the foreseeable future. Therefore, the Company believes that the substantial majority of its natural gas pipeline and storage system assets have indeterminate lives.

The Company believes that the accounting estimates related to contingencies and asset retirement obligations are “critical accounting estimates” because the Company must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligations. In addition, the Company must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.

Accounting for Oil and Gas Producing Activities: The Company uses the successful efforts method of accounting for its oil and gas production activities. Depletion is calculated based on the annual actual production multiplied by the depletion rate per unit. The depletion rate is derived by dividing the total costs capitalized over the number of units expected to be produced over the life of the reserves.

properties that have carrying amounts in excess of estimated future cash flows would be deemed unrecoverable. Those properties would be written down to fair value, which would be estimated using assumptions that marketplace participants would use in their estimates of fair value. In developing estimates of fair value, the Company uses forward market prices.

The Company believes that the accounting estimate related to the accounting for oil and gas producing activities is a “critical accounting estimate” because the Company must assess the remaining recoverable proved reserves a process which is significantly impacted by forward market prices for oil and gas. Should the Company begin to develop new producing regions or begin more significant exploration activities, future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.

Oil and Gas Reserves: Proved reserves are the estimated quantities that geological and engineering data demonstrate, with reasonable certainty, can be recovered in future years from known reservoirs under existing economic and operating conditions. Reserve estimates are prepared and updated by the Company’s engineers and reviewed by the Company’s independent engineers. Additionally, the Company estimates future rates of production, the timing of development expenditures and prospective market prices for oil and gas and applies the appropriate year end income tax rate.

The Company believes that the accounting estimate related to oil and gas reserves is a “critical accounting estimate” because the Company must periodically re-evaluate proved reserves along with estimates of future production and the estimated timing of development expenditures. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.

Item 8. Financial Statements and Supplementary Data

		Page Reference

Management’s Report on Internal Control over Financial Reporting		42

Report of Independent Registered Public Accounting Firm		43

Statements of Consolidated Income for each of the three years in the period ended December 31, 2007		45

Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2007		46

Consolidated Balance Sheets as of December 31, 2007 and 2006		47

Statements of Common Stockholders’ Equity for each of the three years in the period ended December 31, 2007		49

Notes to Consolidated Financial Statements		50

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Equitable is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended). Equitable’s internal control system is designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.

Equitable’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2007.

Ernst & Young LLP, the independent registered public accounting firm that audited the Company’s Consolidated Financial Statements, has issued an attestation report on the Company’s internal control over financial reporting. Ernst & Young’s attestation report on the Company’s internal control over financial reporting appears on page 44 of this exhibit.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Equitable Resources, Inc.

We have audited the accompanying consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of income, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Equitable Resources, Inc. and Subsidiaries at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, in 2007, the Company adopted the provisions of FASB Interpretation No. 48 Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No.109. As discussed in Note 13 to the consolidated financial statements, in 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Equitable Resources, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 6, 2008, expressed an unqualified opinion thereon.

Pittsburgh, Pennsylvania

March 6, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Equitable Resources, Inc.

We have audited Equitable Resources, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Equitable Resources, Inc. and Subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Equitable Resources, Inc. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of income, common shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 6, 2008 expressed an unqualified opinion thereon.

Pittsburgh, Pennsylvania

March 6, 2008

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

YEARS ENDED DECEMBER 31,

	2007		2006			2005
	(Thousands except per share amounts)

Operating revenues	$	1,361,406	$	1,267,910		$	1,253,724
Cost of sales	574,466		504,329			511,169
Net operating revenues (see Note 1)	786,940		763,581			742,555
Operating expenses:
Operation and maintenance	106,965		104,620			95,369
Production	62,273		62,471			60,715
Exploration	862		802			768
Selling, general and administrative	195,365		125,951			140,529
Office consolidation impairment charges	—		(2,908		)	7,835
Depreciation, depletion and amortization	109,802		100,122			93,527
Total operating expenses (see Note 1)	475,267		391,058			398,743
Operating income	311,673		372,523			343,812
Gain on sale of assets, net	126,088		—			—
Gain on sale of available-for-sale securities, net	1,042		—			110,280
Other income	7,645		1,442			1,539
Equity in earnings of nonconsolidated investments	3,099		260			762
Interest expense	47,669		48,494			44,781
Income from continuing operations before income taxes	401,878		325,731			411,612
Income taxes	144,395		109,706			153,038
Income from continuing operations	257,483		216,025			258,574
Income from discontinued operations, net of tax (benefit) provision of ($3,246) and $10,485 for the years ended December 31, 2006 and 2005, respectively	—		4,261			1,481
Net income	$	257,483	$	220,286		$	260,055
Earnings per share of common stock:
Basic:
Income from continuing operations	$	2.12	$	1.79		$	2.14
Income from discontinued operations	—		0.04			0.01
Net income	$	2.12	$	1.83		$	2.15
Diluted:
Income from continuing operations	$	2.10	$	1.77		$	2.09
Income from discontinued operations	—		0.03			0.01
Net income	$	2.10	$	1.80		$	2.10

See notes to consolidated financial statements

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

YEARS ENDED DECEMBER 31,

	2007			2006			2005
	(Thousands)
Cash flows from operating activities:
Net income	$	257,483		$	220,286		$	260,055
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Income from discontinued operations, net of tax	—			(4,261		)	(1,481		)
Provision for losses on accounts receivable	353			4,715			8,273
Depreciation, depletion and amortization	109,802			100,122			93,527
Gain on sale of assets, net	(126,088		)	—			—
Gain on sale of available-for-sale securities, net	(1,042		)	—			(110,280		)
Other income	(7,645		)	(1,442		)	(1,539		)
Equity in earnings of nonconsolidated investments	(3,099		)	(260		)	(762		)
Deferred income taxes	32,380			31,267			(92,912		)
Excess tax benefits from share-based payment arrangements	(15,687		)	(15,739		)	—
Office consolidation impairment charges	—			(2,908		)	7,835
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues	2,455			63,527			(78,049		)
Margin deposits	(5,919		)	317,821			(280,935		)
Inventory	(14,357		)	20,793			(85,296		)
Prepaid expenses and other	39,155			(27,135		)	(27,564		)
Regulatory assets	6,120			576			(2,847		)
Accounts payable	65,931			(29,292		)	71,451
Derivative instruments, at fair value	10,863			(53,846		)	(40,962		)
Deferred income taxes	—			33,375			(32,288		)
Pension contributions and settlementss	(9,179		)	(1,751		)	(20,364		)
Other assets	39			7,790			(18,993		)
Other current liabilities	99,357			(31,878		)	83,059
Other credits	(14,202		)	(13,914		)	8,257
Net cash provided by (used in) continuing operating activities	426,720			617,846			(261,815		)
Net cash used in discontinued operating activities	—			—			(50,491		)
Net cash provided by (used in) operating activities	426,720			617,846			(312,306		)
Cash flows from investing activities:
Capital expenditures	(776,667		)	(403,094		)	(275,454		)
Purchase of working interest	(28,092		)	—			—
Purchase of interest in Eastern Seven Partners, L.P.	—			—			(57,500		)
Proceeds from sale of assets	193,451			—			141,991
Proceeds from contribution of assets	23,584			—			—
Proceeds from sale of available-for-sale securities	7,295			—			—
Investment in available-for-sale securities	(9,709		)	(2,471		)	(4,009		)
Proceeds from sale of Kerr-McGee shares	—			—			460,467
Net cash (used in) provided by continuing investing activities	(590,138		)	(405,565		)	265,495
Net cash (used in) provided by discontinued investing activities	—			(724		)	82,595
Net cash (used in) provided by investing activities	(590,138		)	(406,289		)	348,090
Cash flows from financing activities:
Dividends paid	(107,086		)	(104,871		)	(99,737		)
Purchase of treasury stock	—			—			(122,250		)
Increase (decrease) in short-term loans	314,001			(229,301		)	69,801
Proceeds from issuance of long-term debt	—			—			150,000
Repayments and retirements of long-term debt	(10,000		)	(3,000		)	(10,000		)
Proceeds from note payable to Nora Gathering, LLC	69,786			—			—
Repayments of note payable to Nora Gathering, LLC	(40,457		)	—			—
Proceeds from exercises under employee compensation plans	3,198			34,910			25,016
Excess tax benefits from share-based payment arrangements	15,687			15,739			—
Net cash provided by (used in) continuing financing activities	245,129			(286,523		)	12,830
Net cash provided by discontinued financing activities	—			—			26,352
Net cash provided by (used in) financing activities	245,129			(286,523		)	39,182
Net increase (decrease) in cash and cash equivalents	81,711			(74,966		)	74,966
Cash and cash equivalents at beginning of year	—			74,966			—
Cash and cash equivalents at end of year	$	81,711		$	—		$	74,966
Cash paid during the year for:
Interest, net of amount capitalized	$	48,464		$	48,702		$	49,429
Income taxes, net of refund	$	63,384		$	58,631		$	251,486

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2007		2006
	(Thousands)
Assets
Current assets:
Cash and cash equivalents	$	81,711	$	—
Accounts receivable (less accumulated provision for
doubtful accounts: 2007, $19,829; 2006, $20,442)	188,561		199,486
Unbilled revenues	48,744		40,627
Margin deposits with financial institutions	5,930		11
Inventory	283,485		269,128
Derivative instruments, at fair value	37,143		129,675
Prepaid expenses and other	96,673		87,867
Total current assets	742,247		726,794
Equity in nonconsolidated investments	135,366		35,023
Property, plant and equipment:
Equitable Production	2,122,337		1,864,013
Equitable Midstream	1,201,665		896,722
Equitable Distribution	883,400		856,562
Total property, plant and equipment	4,207,402		3,617,297
Less: accumulated depreciation and depletion	1,287,911		1,239,826
Net property, plant and equipment	2,919,491		2,377,471
Investments, available-for-sale	35,675		31,270
Other assets:
Regulatory assets	78,015		79,289
Other	26,177		32,408
Total other assets	104,192		111,697
Total assets	$	3,936,971	$	3,282,255

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2007			2006
	(Thousands)
Liabilities and Common Stockholders’ Equity
Current liabilities:
Current portion of long-term debt	$	—		$	10,000
Short-term loans	450,000			135,999
Note payable to Nora Gathering, LLC	29,329			—
Accounts payable	279,257			213,326
Derivative instruments, at fair value	516,626			570,251
Other current liabilities	244,096			175,547
Total current liabilities	1,519,308			1,105,123
Long-term debt	753,500			753,500
Other non-current liabilities:
Deferred income taxes and investment tax credits	400,465			338,012
Unrecognized tax benefits	50,845			—
Pension and other post-retirement benefits	41,768			50,947
Other credits	73,613			88,393
Total other non-current liabilities	566,691			477,352
Total liabilities	2,839,499			2,335,975
Common stockholders’ equity:
Common stock, no par value, authorized 320,000 shares; shares issued: 2007 and 2006, 149,008	382,191			366,856
Treasury stock, shares at cost: 2007, 26,853, 2006, 27,405; (net of shares and cost held in trust for deferred compensation of 180, $3,085 and 159, $2,724)	(485,051		)	(469,584		)
Retained earnings	1,509,596			1,363,310
Accumulated other comprehensive loss	(309,264		)	(314,302		)
Total common stockholders’ equity	1,097,472			946,280
Total liabilities and common stockholders’ equity	$	3,936,971		$	3,282,255

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005

	Common Stock								Accumulated Other			Common
	Shares Outstanding		No Par Value			Retained Earnings			Comprehensive (Loss) Income			Stockholders’ Equity
						(Thousands)
Balance, December 31, 2004	122,062		$	(32,558	)	$	1,087,577		$	(180,347	)	$	874,672
Comprehensive loss (net of tax):
Net income						260,055						260,055
Net change in cash flow hedges:
Natural gas, net of tax benefit of $324,817 (see Note 3)									(543,716		)	(543,716		)
Interest rate									97			97
Unrealized gain on available-for-sale securities:
Kerr-McGee									(36,334		)	(36,334		)
Other									375			375
Minimum pension liability adjustment, net of tax benefit of $211									4,325			4,325
Total comprehensive loss												(315,198		)
Dividends ($0.820 per share)						(99,737		)				(99,737		)
Stock-based compensation plans, net	1,412		16,981									16,981
Stock repurchases	(3,568	)	(122,250		)							(122,250		)
Balance, December 31, 2005	119,906		(137,827		)	1,247,895			(755,600		)	354,468
Comprehensive income (net of tax):
Net income						220,286						220,286
Net change in cash flow hedges:
Natural gas, net of tax of $272,066 (see Note 3)									454,817			454,817
Interest rate									116			116
Unrealized gain on available-for-sale securities									2,399			2,399
Pension and other post-retirement benefits liability adjustment prior to the adoption of SFAS No. 158, net of tax benefit of $730									(1,024		)	(1,024		)
Total comprehensive income												676,594
Pension and other post-retirement benefits liability adjustment due to the adoption of SFAS No. 158, net of tax benefit of $9,988									(15,010		)	(15,010		)
Dividends ($0.87 per share)						(104,871		)				(104,871		)
Stock-based compensation plans, net	1,697		35,099									35,099
Balance, December 31, 2006	121,603		(102,728		)	1,363,310			(314,302		)	946,280
Comprehensive income (net of tax):
Net income						257,483						257,483
Net change in cash flow hedges:
Natural gas, net of tax of $370 (see Note 3)									(20		)	(20		)
Interest rate									115			115
Unrealized loss on available-for-sale securities									(97		)	(97		)
Pension and other post-retirement benefits liability adjustment, net of tax benefit of $3,700									5,040			5,040
Total comprehensive income												262,521
Liability adjustment due to the adoption of FIN 48						(4,111		)				(4,111		)
Dividends ($0.88 per share)						(107,086		)				(107,086		)
Stock-based compensation plans, net	549		(132		)							(132		)
Balance, December 31, 2007	122,152		$	(102,860	)	$	1,509,596		$	(309,264	)	$	1,097,472

Common shares authorized: 320,000,000 shares. Preferred shares authorized: 3,000,000 shares. There are no preferred shares issued or outstanding.

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2007

1. Summary of Significant Accounting Policies

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

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

Stock Split: On September 1, 2005, the Company effected a two-for-one stock split payable to shareholders of record on August 12, 2005. All share and per share information has been retroactively adjusted to reflect the stock split.

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

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

Inventories: The Company’s inventory balance consists of natural gas stored underground and materials and supplies recorded at the lower of average cost or market.

Property, Plant and Equipment: The Company’s property, plant and equipment consists of the following:

	December 31,
	2007		2006
	(Thousands)
Oil and gas producing properties, successful efforts method	$	2,029,932	$	1,752,222
Accumulated depletion	621,881		566,118
Net oil and gas producing properties	1,408,051		1,186,104
Distribution plant	877,955		851,114
Accumulated depreciation and amortization	282,379		278,686
Net distribution plant	595,576		572,428
Midstream plant	1,201,665		896,722
Accumulated depreciation and amortization	319,214		335,568
Net midstream plant	882,451		561,154
Other properties, at cost less accumulated depreciation	33,413		57,785
Net property, plant and equipment	$	2,919,491	$	2,377,471

Oil and gas producing properties use the successful efforts method of accounting for production activities. Under this method, the cost of productive wells, including mineral interests, wells and related equipment, development dry holes, as well as productive acreage, are capitalized and depleted on the unit-of-production method. These capitalized costs include salaries, benefits and other internal costs directly attributable to these activities. The Company capitalized internal costs of $14.4 million, $11.3 million and $10.3 million in 2007, 2006 and 2005. Depletion is calculated based on the annual actual production multiplied by the depletion rate per unit. The depletion rate is derived by dividing the total costs capitalized over the number of units expected to be produced over the life of the reserves. Equitable Production calculates a single depletion field including all reserves located in

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

Kentucky, West Virginia, Virginia and Pennsylvania. Costs of exploratory dry holes, geological and geophysical, delay rentals and other property carrying costs are charged to expense. The majority of the Company’s oil and gas producing properties consists of gas producing properties which were depleted at a rate of $0.70/Mcf and $0.62/Mcf produced for the years ended December 31, 2007, and December 31, 2006, respectively.

The carrying values of the Company’s proved oil and gas properties are reviewed for indications of impairment whenever events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its proved oil and gas properties and compares them to their respective carrying values. The estimated future cash flows used to test those properties for recoverability are based on proved reserves utilizing assumptions about the use of the asset and forward market prices for oil and gas. Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows are deemed unrecoverable. Those properties are then written down to fair value, which is estimated using assumptions that marketplace participants would use in their estimates of fair value. In developing estimates of fair value, the Company used forward market prices. For the years ended December 31, 2007, 2006 and 2005, the Company did not recognize impairment charges on oil and gas properties.

Additionally, the costs of unproved oil and gas properties are periodically assessed. If unproved properties are determined to be productive, the related costs are transferred to proved oil and gas properties. If unproved properties are determined not to be productive, or if the value has been otherwise impaired, the excess carrying value is charged to expense. For additional information on oil and gas properties, see Note 24 (unaudited).

Midstream property, plant and equipment is carried at cost. These items are carried at cost and depreciation is calculated using the straight-line method based on estimated service lives. This property consists largely of gathering and transmission systems (25 year estimated service life), buildings (35 year estimated service life), office equipment (3-7 year estimated service life), vehicles (5 year estimated service life), and computer and telecommunications equipment and systems (3-7 year estimated service life).

Distribution property, plant and equipment, principally regulated property, is carried at cost. Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2007, and December 31, 2006, was approximately 3% of net properties.

Major maintenance projects that do not increase the overall life of the related assets are expensed. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized.

Sales and Retirements Policies: No gain or loss is recognized on the partial sale of oil and gas reserves from the depletion pool unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds. Due to the significance of the transaction, gains and losses were recognized on the sale and contribution of Nora assets in 2007. See Note 4.

Regulatory Accounting: Equitable Distribution’s rates, terms of service, and contracts with affiliates are subject to comprehensive regulation by the PA PUC and the WV PSC and the issuance of securities is subject to regulation by the PA PUC. Equitable Distribution also provides field line service, also referred to as “farm tap” service, in Kentucky which is subject only to rate regulation by the Kentucky Public Service Commission. Equitable Midstream’s regulated operations consist of interstate pipeline operations subject to regulation by the FERC and certain state-regulated gathering operations. Accounting for the Company’s regulated operations is performed in accordance with the provisions of SFAS No. 71. The application of this accounting policy allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Statements of Consolidated Income for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the Statements of Consolidated Income in the period in which the same amounts are reflected in rates.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

Where permitted by regulatory authority under purchased natural gas adjustment clauses or similar tariff provisions, Equitable Distribution defers the difference between its purchased natural gas cost, less refunds, and the billing of such cost and amortizes the deferral over subsequent periods in which billings either recover or repay such amounts. Such amounts are reflected on the Company’s Consolidated Balance Sheets as other current assets or liabilities. For further information regarding regulatory assets, see Note 10.

When any portion of Equitable Distribution’s or Equitable Midstream’s regulated operations ceases to meet the criteria for application of regulatory accounting treatment for all or part of their operations, the regulatory assets and liabilities related to those portions are eliminated from the Consolidated Balance Sheets and are included in the Statements of Consolidated Income in the period in which the discontinuance of regulatory accounting treatment occurs.

The following table presents the total regulated net revenues and operating expenses of the Company:

	Years Ended December 31,
	2007		2006		2005
	(Thousands)
Distribution revenues	$	455,506	$	445,168		$	469,102
Midstream revenues	68,547		74,010			57,534
Total regulated revenue	524,053		519,178			526,636

Distribution purchased gas costs	305,706		301,833			312,244
Midstream purchased gas costs	1,030		1,424			3,767
Total purchased gas costs	306,736		303,257			316,011

Distribution net revenue	149,800		143,335			156,858
Midstream net revenue	67,517		72,586			53,767
Total regulated net revenue	217,317		215,921			210,625

Distribution operating expenses	125,729		108,528			116,536
Midstream operating expenses	41,364		39,346			36,422
Total regulated operating expenses	$	167,093	$	147,874		$	152,958

The following table presents the regulated net property, plant and equipment of the Company:

	As of December 31,
	2007		2006

Distribution property, plant & equipment, net	$	595,576	$	572,428
Midstream property, plant & equipment, net	419,356		250,375
Total regulated property, plant & equipment, net	$	1,014,932	$	822,803

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

The Company’s risk management program includes the consideration and, when appropriate, the use of (i) 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 and (ii) interest rate swap agreements to hedge exposures to fluctuations in interest rates. At contract inception, the Company designates its derivative instruments as hedging or trading activities.

All derivative instruments are accounted for in accordance with SFAS No. 133. As a result, the Company recognizes all derivative instruments as either assets or liabilities and measures the effectiveness of the hedges, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at fair value. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, hedge ineffectiveness is recorded. The measurement of fair value is based upon actively quoted market prices when available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based upon valuation methodologies deemed appropriate by the Company’s CRC. The Company assesses the effectiveness of hedging relationships both at the inception of the hedge and on an on-going basis.

The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (loss), net of tax, and is subsequently reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income. If a cash flow hedge is terminated before the settlement date of the hedged item, the amount of accumulated other comprehensive income (loss) recorded up to that date would remain accrued provided that the forecasted transaction remains probable of occurring, and going forward, the change in fair value of the derivative instrument would be recorded in earnings. The derivative instruments that comprise the amount recorded in accumulated other comprehensive income (loss) have been designated and qualify as cash flow hedges. The Company reports all gains and losses on its energy trading contracts net on its Statements of Consolidated Income in accordance with EITF No. 02-3.

Capitalized Interest: Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. Interest costs during 2007, 2006 and 2005 of $6.7 million, $0.6 million and $0.2 million, respectively, were capitalized as a portion of the cost of the related long-term assets.

Allowance for Funds Used in Construction: The Company capitalizes the carrying costs for the construction of certain long-term assets and amortizes the costs over the life of the related assets. For regulated assets, these costs include allowance for equity funds used during construction (AFUDC—Equity) which is presented as other income in the Statements of Consolidated Income. Prior to 2007, the amount of AFUDC—Equity was not significant and was included as an offset to interest expense in the Statements of Consolidated Income. As a result of the significance of the carrying costs related to the construction of the Big Sandy Pipeline, AFUDC—Equity has been reclassified to Other Income in the Statements of Consolidated Income for all periods presented.

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

Revenue Recognition: Revenue is recognized for production and gathering activities when deliveries of natural gas, crude oil and NGLs are made. Revenues from natural gas transportation and storage activities are recognized in the period service is provided. Sales of natural gas to distribution customers are billed on a monthly

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

cycle basis; however, the billing cycle periods for certain customers do not necessarily coincide with accounting periods used for financial reporting purposes. The Company follows the revenue accrual method of accounting for distribution segment revenue whereby revenues applicable to gas delivered to customers but not yet billed under the cycle billing method are estimated and accrued and the related costs are charged to expense. Revenues from energy marketing activities are recognized when deliveries occur. In accordance with EITF No. 02-3, only revenues associated with energy trading activities that do not result in physical delivery of an energy commodity (i.e. are settled in cash) are recorded using mark-to-market accounting. The revenues associated with the physical delivery of an energy commodity are recognized at contract value when delivered. Revenues associated with the Company’s natural gas advance sales contracts are recognized as natural gas is gathered and delivered. The Company accounts for gas-balancing arrangements under the entitlement method.

Investments: Investments in companies in which the Company has the ability to exert significant influence over operating and financial policies (generally 20% to 50% ownership) are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. These investments are classified as equity in nonconsolidated investments on the Consolidated Balance Sheets.

Other investments in equity securities which are generally under 20% ownership and where the Company does not exert significant influence over operating and financial polices are accounted for as available-for-sale in accordance with SFAS No. 115 and are classified as investments, available-for-sale on the Consolidated Balance Sheets. Available-for-sale securities are required to be carried at fair value, with any unrealized gains and losses reported on the Consolidated Balance Sheets within a separate component of equity, accumulated other comprehensive income (loss). The Company utilizes the specific identification method to determine the cost of the securities sold.

APB No. 18 requires a company to recognize a loss in the value of an equity method investment that is other than a temporary decline. The Company analyzes its equity method investments based on its share of estimated future cash flows from the investment to determine whether the carrying amount will be recoverable. In accordance with SFAS No. 115, the Company continually reviews its available-for-sale investments to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is judged to be other than temporary, the cost basis of the security is written down to fair value and the amount of the write-down is included in the Statements of Consolidated Income. No other than temporary decline in fair value was recorded in 2007, 2006 or 2005.

Income Taxes: The Company files a consolidated Federal income tax return and utilizes the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refunded, for the current year and the change in deferred taxes. Any refinements to prior years’ taxes made due to subsequent information are reflected as adjustments in the current period. Separate income taxes are calculated for income from continuing operations, discontinued operations, and items charged or credited directly to stockholders’ equity.

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

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

measurement of a tax position taken or expected to be taken in a tax return. The recognition threshold is the first step which requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If the first step is satisfied, then the Company must measure the tax position to determine the amount of benefit to recognize in financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense.

Provision for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Company’s accounts receivable, including assessing the probability of collection and the credit-worthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense on the Statements of Consolidated Income. The reserves are based on historical experience, current and expected economic trends and specific information about customer accounts. Accordingly, actual results may differ from these estimates under different assumptions or conditions.

Earnings Per Share (EPS): Basic EPS is computed by dividing net income by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS is computed by dividing net income adjusted for the assumed conversion of debt by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards. See Note 15 for a detailed calculation.

Asset Retirement Obligations: SFAS No. 143 requires that the Company accrue a liability for legal asset retirement obligations based on an estimate of the timing and amount of their settlement. For oil and gas wells, the fair value of the Company’s plugging and abandonment obligations is required to be recorded at the time the obligations are incurred, which is typically at the time the wells are drilled. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion, and amortization, and the initial capitalized costs are depleted over the useful lives of the related assets.

The following table presents a reconciliation of the beginning and ending carrying amounts of the Company’s asset retirement obligations. The Company does not have any assets that are legally restricted for purposes of settling these obligations.

	Year ended December 31, 2007
	(Thousands)
Asset retirement obligation as of beginning of period	$	48,520
Accretion expense	3,430
Liabilities incurred	2,245
Net acquisition/(divestitures)	(1,739		)
Liabilities settled	(1,313		)
Asset retirement obligation as of end of period	$	51,143

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

Self-Insurance: The Company is self-insured for certain losses related to workers’ compensation. The Company maintains stop loss coverage with third-party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers’ compensation. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly and by independent actuaries annually to ensure that they are appropriate. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from estimates.

Recently Issued Accounting Standards:

The Fair Value Option for Financial Assets and Financial Liabilities

In February 2007, the FASB issued SFAS No. 159, which provides entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This Statement is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The Company does not expect that SFAS No. 159 will have a significant impact on its consolidated financial statements.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, which establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company does not expect that SFAS No. 157 will have a significant impact on its consolidated financial statements.

2. Financial Information by Business Segment

Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources.

The Company reports its operations in three segments, which reflect its lines of business. The Equitable Production segment includes the Company’s exploration for, and development and production of, natural gas and a limited amount of crude oil in the Appalachian Basin. Equitable Midstream’s operations include the natural gas gathering, processing, transportation and storage activities of the Company as well as sales of NGLs. Equitable Distribution’s operations primarily comprise the state-regulated distribution activities of the Company.

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. 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.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

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

	Years Ended December 31,
	2007			2006			2005
	(Thousands)
Revenues from external customers:
Equitable Production	$	364,396		$	359,526		$	384,885
Equitable Midstream	591,608			554,071			483,146
Equitable Distribution	624,744			586,194			651,771
Less: intersegment revenues (a)	(219,342		)	(231,881		)	(266, 078)
Total	$	1,361,406		$	1,267,910		$	1,253,724
Total operating expenses:
Equitable Production	$	162,377		$	144,103		$	129,873
Equitable Midstream	121,483			116,215			103,973
Equitable Distribution	126,088			108,890			116,874
Unallocated expenses (b)	65,319			21,850			48,023
Total	$	475,267		$	391,058		$	398,743

Operating income:
Equitable Production	$	202,019		$	215,423		$	255,012
Equitable Midstream	140,432			137,177			87,469
Equitable Distribution	34,541			41,773			49,354
Unallocated expenses (b)	(65,319		)	(21,850		)	(48,023		)
Total operating income	$	311,673		$	372,523		$	343,812

Reconciliation of operating income to net income:

Equity in earnings of nonconsolidated investments:
Equitable Production	$	301		$	129		$	493
Equitable Midstream	2,648			—			—
Unallocated	150			131			269
Total	$	3,099		$	260		$	762
Other income:
Equitable Midstream	$	7,253		$	1,149		$	93
Equitable Distribution	392			293			251
Unallocated (c)	—			—			1,195
Total	$	7,645		$	1,442		$	1,539

Gain on sale of assets, net	126,088			—			—
Gain on sale of available-for-sale securities, net	1,042			—			110,280
Interest expense	47,669			48,494			44,781
Income taxes	144,395			109,706			153,038
Income from continuing operations	257,483			216,025			258,574
Income from discontinued operations	—			4,261			1,481
Net income	$	257,483		$	220,286		$	260,055

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

	As of December 31,
	2007		2006
	(Thousands)
Segment assets:
Equitable Production	$	1,614,787	$	1,459,230
Equitable Midstream	1,232,348		895,703
Equitable Distribution	906,113		886,327
Total operating segments	3,753,248		3,241,260
Headquarters assets, including cash and short-term investments	183,723		40,995
Total assets	$	3,936,971	$	3,282,255

	Years Ended December 31,
	2007		2006		2005
	(Thousands)
Depreciation, depletion and amortization:
Equitable Production	$	62,084	$	53,471	$	49,235
Equitable Midstream	26,333		25,822		24,053
Equitable Distribution	20,021		19,938		19,483
Other	1,364		891		756
Total	$	109,802	$	100,122	$	93,527
Expenditures for segment assets:
Equitable Production (d)	$	328,080	$	205,047	$	183,859
Equitable Midstream (d)	433,719		146,512		93,707
Equitable Distribution	41,684		48,721		47,534
Other	1,276		2,814		7,854
Total	$	804,759	$	403,094	$	332,954

(a)		Intersegment revenues primarily represent natural gas sales from Equitable Production to Equitable Midstream and transportation activities between Equitable Midstream and Equitable Distribution.

(b)		Unallocated expenses consist primarily of incentive compensation and administrative costs that are not allocated to the operating segments.

(c)		Unallocated other income for the year ended December 31, 2005 relates to pre-tax dividend income of $1.2 million for the Kerr-McGee Corporation shares held by the Company during the year.

(d)		Expenditures for segment assets for 2007 include $24.4 million and $3.7 million, in the Equitable Production and Equitable Midstream segments, respectively, for the acquisition of additional working interest and related gathering assets in the Roaring Fork area, and Equitable Production expenditures for segment assets for 2005 include $57.5 million for the acquisition of the 99% limited partnership interest in Eastern Seven Partners, L.P. See Note 5.

3. Derivative Instruments

Derivative Commodity Instruments

The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

counterparties based on the differential between a fixed and variable price for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. Exchange-traded instruments are generally settled with offsetting positions but may be settled by delivery or receipt of commodities. OTC arrangements require settlement in cash.

The fair value of these derivative commodity instruments is presented below:

	As of December 31,
	2007			2006
	(Thousands)
Asset	$	34,921		$	129,675
Liability	(489,227		)	(544,444		)
Net liability	$	(454,306	)	$	(414,769	)

These amounts are included in the Consolidated Balance Sheets as derivative instruments, at fair value. The net amount of derivative instruments, at fair value, changed between years primarily as a result of the increase in natural gas prices and reduced hedged quantities due to derivative settlements. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 287.3 Bcf and 392.6 Bcf as of December 31, 2007 and 2006, respectively, and are primarily related to natural gas swaps. The open positions at December 31, 2007 had maturities extending through December 2013.

The Company had deferred net losses of $286.2 million in accumulated other comprehensive loss, net of tax, as of both December 31, 2007 and 2006 associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $106.1 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of December 31, 2007 will be recognized in earnings during the next twelve months due to the physical settlement of hedged transactions. This recognition occurs through a reduction in the Company’s net operating revenues resulting in the average hedged price becoming the realized sales price.

The net change in accumulated other comprehensive loss related to derivatives is presented below:

	Years Ended December 31,
	2007			2006		2005
	(Thousands)
Net unrealized (loss) gain	$	(42,010	)	$	370,395	$	(690,893	)
Net realized loss	41,990			84,422		147,177
Net (loss) gain	$	(20	)	$	454,817	$	(543,716	)

For the years ended December 31, 2007, 2006 and 2005, ineffectiveness associated with the Company’s derivative instruments designated as cash flow hedges increased (decreased) earnings by approximately $1.4 million, $0.4 million and $(0.1) million, respectively. These amounts are included in operating revenues in the Statements of Consolidated Income.

The Company conducts trading activities through its unregulated Equitable Midstream operations. The function of the Company’s trading business is to contribute to the Company’s earnings by taking market positions within defined limits subject to the Company’s corporate risk management policy. At December 31, 2007, the absolute notional quantities of the futures and swaps held for trading purposes totaled 10.2 Bcf and 18.4 Bcf, respectively.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

Below is a summary of the activity of the fair value of the Company’s derivative commodity contracts with third parties held for trading purposes during the year ended December 31, 2007 (in thousands).

Fair value of contracts outstanding as of December 31, 2006	$	581
Contracts realized or otherwise settled	(779		)
Other changes in fair value	123
Fair value of contracts outstanding as of December 31, 2007	$	(75	)

There were no significant adjustments to the fair value of the Company’s derivative contracts held for trading purposes relating to changes in valuation techniques and assumptions during the years ended December 31, 2007 and 2006.

The following table presents the maturities and the fair valuation source for the Company’s derivative instruments that were held for trading purposes as of December 31, 2007.

Net Fair Value of Third Party Contract (Liabilities) Assets at Period-End

Source of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years		Maturity 4-5 Years		Maturity in Excess of 5 Years		Total Fair Value
	(Thousands)
Prices actively quoted (NYMEX) (1)	$	42		$	—	$	—	$	—	$	42
Prices provided by other external sources (2)	(117		)	—		—		—		(117		)
Net derivative liabilities	$	(75	)	$	—	$	—	$	—	$	(75	)

(1)		Contracts include futures and fixed price swaps

(2)		Contracts include basis swaps

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

In May 2007, the Company sold a portion of its interest in certain gas properties in the Nora area, as discussed in Note 4. As part of this transaction, the Company closed out certain cash flow hedges associated with forecasted production at this location by purchasing offsetting positions. The fair value of these derivative instruments was a $20.6 million liability at December 31, 2007. In addition, the fair value of derivative instruments associated with forecasted production at non-core gas properties sold in May 2005 was a $6.8 million liability at December 31, 2007. The Company does not treat these derivatives as hedging instruments under SFAS No. 133. These amounts are included in the Consolidated Balance Sheet as derivative instruments, at fair value.

When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company recorded $1.6 million and less than $0.1 million of such deposits in its Consolidated Balance Sheet as of December 31, 2007 and 2006, respectively.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

When the Company enters into exchange-traded natural gas contracts, exchanges require the Company, to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. Participants must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on prices, volatility and the time to expiration of the related contract and are subject to change at the exchanges’ discretion. The Company recorded margin deposits in the amount of $4.3 million in its Consolidated Balance Sheet as of December 31, 2007. The Company recorded a liability for deposits in the amount of $7.9 million in its Consolidated Balance Sheet as of December 31, 2006, representing amounts received from brokers as a result of the related contracts having a positive fair value.

Other Derivative Instruments

In July 2004, the Company entered into three 7.5 year secured variable share forward transactions. Each transaction had a different counterparty, covered 2.0 million shares of Kerr-McGee Corporation (Kerr-McGee) common stock, contained a collar and permitted receipt of an amount up to the net present value of the floor price prior to maturity. Upon maturity of each transaction, the Company was obligated to deliver to the applicable counterparty, at the Company’s option, no more than 2.0 million Kerr-McGee shares or cash in an equivalent value. The collars effectively limited the Company’s cash flow exposure upon the forecasted disposal of 6.0 million Kerr-McGee shares. A variable portion of the dividends received on the underlying Kerr-McGee shares was paid to each counterparty depending upon the hedged position of such counterparty.

In May 2005, the Company terminated the three variable share forward transactions. In connection with the termination, the Company incurred a termination cost of $95.8 million and sold 4.3 million Kerr-McGee shares to its three counterparties to cover its counterparties’ respective hedged positions. See Note 9 for further discussion of transactions related to the Kerr-McGee shares.

4. Sale of Properties

On April 13, 2007, the Company and Range Resources Corporation (Range) agreed to a development plan for the Nora area in Southwestern Virginia. The Company entered into a Purchase and Sale Agreement (Purchase Agreement) with Pine Mountain Oil and Gas, Inc. (PMOG), a subsidiary of Range, pursuant to which the Company agreed to sell to PMOG a portion of the Company’s interests in certain gas properties in the Nora area. Additionally, the Company entered into a Contribution Agreement (Contribution Agreement) with PMOG relating to the contribution of certain Nora area gathering facilities and pipelines to Nora Gathering, LLC (Nora LLC), a newly formed entity that is equally owned by the Company and PMOG. This gathering system services production of the Company and Range.

During the remainder of 2007, the Company completed a majority of the transactions contemplated by the Purchase Agreement by selling proved reserves of approximately 74 Bcf, including proved developed reserves of approximately 67 Bcf, to PMOG for proceeds of $193.5 million after purchase price adjustments.

Additionally in 2007, the Company completed a substantial majority of the transactions contemplated by the Contribution Agreement by contributing Nora area gathering property with a net book value of $121.0 million to Nora LLC in exchange for a 50% interest in Nora LLC and cash of $23.6 million. PMOG contributed cash of $94.3 million to Nora LLC in exchange for its 50% interest. The Company and Nora LLC also entered into a demand note agreement whereby Nora LLC loaned to the Company $69.8 million on the initial closing date. The balance of this note as of December 31, 2007 was $29.3 million, and was classified as note payable to Nora Gathering, LLC in the Company’s Consolidated Balance Sheet. The Company is accounting for its interest in Nora LLC under the equity method of accounting, as the Company determined that it has the ability to exert significant influence over the operating and financial policies of Nora LLC through its 50%, non-controlling interest. The Company recorded an equity investment in Nora LLC of $94.3 million in its Consolidated Balance Sheet upon contribution of the Nora area gathering property.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

The Company recorded a gain on these transactions of $154.5 million, net of costs to sell, in accordance with SFAS No. 19. As a result of the working interest sale, the Company reduced its hedge position by approximately 7.3 Bcf, resulting in the Company recording a hedge loss of $28.4 million as of the date of sale. These items are recorded in gain on sale of assets, net in the Company’s Statements of Consolidated Income for 2007.

As a result of these transactions, the Company and Range have equalized their interest in the Nora area, including their interest in the producing wells, undrilled acreage and gathering system.

A final closing covering the remainder of the gas properties and related remaining gathering assets included in the above transactions would reduce the Company’s proved reserves by a maximum of approximately 9 Bcf. The Company is currently working with all parties involved to obtain the remaining required consents.

In May 2005, the Company sold certain non-core gas properties and associated gathering assets for approximately $142 million after purchase price adjustments. In accordance with SFAS No. 19, this sale of only a portion of the Company’s gas properties was treated as a normal retirement with no gain or loss recognized, as doing so did not significantly affect the depletion rate. See Note 24 for further discussion of changes to the Company’s reserves during 2005.

5. Acquisitions

In September 2007, the Company purchased an additional working interest of approximately 13.5% in the Roaring Fork area in Virginia and certain gathering assets from a minority interest holder for $28.5 million subject to post-closing adjustments, which increased the Company’s working interest to approximately 97.0%. The additional working interest of 13.5% represents approximately 12.3 Bcf of reserves, consisting of approximately 10.1 Bcf of proved developed reserves and approximately 2.2 Bcf of proved undeveloped reserves. The purchase price was funded using a portion of the proceeds received from the sale described in Note 4, as this transaction qualified as a like-kind exchange under the deferred exchange agreement.

On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion’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 Peoples and Hope. In light of the continued delay in achieving the final legal approvals for this transaction, the Company and Dominion agreed to terminate the definitive agreement pursuant to a mutual termination agreement entered into on January 15, 2008. As a result of this termination, the Company recognized $9.8 million of deferred acquisition costs and $0.3 million of impairment charges as expense in the 2007 Statements of Consolidated Income.

In January 2005, the Company purchased the limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million. See Note 24 for further discussion of changes to the Company’s reserves during 2005.

6. Income Taxes

In June 2006, the FASB issued FIN 48 which applies to all open tax positions accounted for in accordance with SFAS No. 109. The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized a $4.1 million increase in the liability for unrecognized tax benefits which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. Additionally, as a result of the implementation of FIN 48, the Company recorded $29.7 million of unrecognized tax benefits related to a balance sheet reclassification that did not impact retained earnings. A total of $16.9 million of this reclassification relates to the gross up of certain tax positions that were previously recorded net of tax benefit, tax positions which relate to temporary differences that were previously part of deferred taxes and tax positions that were previously offset against deferred tax assets. The remaining $12.8 million relates to tax positions previously categorized as current liabilities. After the recognition of these items in connection with the implementation of FIN 48, the total liability for unrecognized tax benefits, inclusive of interest and penalties, at January 1, 2007 was $33.8 million.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

A reconciliation of the beginning and ending amount of unrecognized tax benefits (excluding interest and penalties) is as follows:

	(Thousands)
Balance at January 1, 2007	$22,760
Additions based on tax positions related to current year	3,140
Additions for tax positions of prior years	9,676
Reductions for tax positions of prior years	(4,209	)
Settlements	—
Lapse of statute of limitations	—
Balance at December 31, 2007	$31,367

Included in the tabular reconciliation above at December 31, 2007 are $18.1 million for tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense. During the year ended December 31, 2007, the Company recognized approximately $8.5 million in interest. Included in the balance sheet reserve at January 1, 2007 and December 31, 2007 is $11.0 million and $19.5 million of interest, respectively. No amounts were accrued for penalties as of December 31, 2007.

The total amount of unrecognized tax benefits, inclusive of interest and penalties, is $50.8 million as of December 31, 2007. As of December 31, 2007, $11.1 million is the total amount of unrecognized tax benefits (excluding interest and penalties) that, if recognized, would affect the effective tax rate.

As of December 31, 2007, it is reasonably possible that the total amount of unrecognized tax benefits could decrease between $1.0 million and $21.2 million within the next 12 months due to potential settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.

The consolidated Federal income tax liability of the Company has been settled with the IRS through 1997. The IRS has completed its audit and review of the Company’s Federal income tax filings for the 1998 through 2000 years. The audit results for these periods generated a tax refund for the Company that is in excess of $2 million which requires review and approval by the Joint Committee on Taxation (JCT). During the review process, the JCT questioned an issue that the Company had previously agreed upon with the IRS through the Fast Track Appeals process. The Company is currently working with the Settlement Agent and the IRS Manager to try to resolve the questions raised by the JCT.

The IRS has surveyed the 2001 and 2002 Federal income tax filings and is currently reviewing the research and experimentation tax credits claimed for such years. During the second quarter of 2007, the IRS began an examination of the Company’s Federal income tax filings for 2003 through 2005. The Company also is the subject of various routine state income tax examinations. The Company believes that it is appropriately reserved for any uncertain tax positions claimed during these periods.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

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

	December 31,
	2007			2006
	(Thousands)
Deferred income taxes:
Total deferred income tax assets	$	(339,135	)	$	(315,456	)
Total deferred income tax liabilities	699,476			659,575
Total net deferred income tax liabilities	$	360,341		$	344,119

Total deferred income tax (assets)/liabilities
Drilling and development costs expensed for income tax reporting	$	474,882		$	425,039
Other comprehensive loss	(188,593		)	(192,612		)
Tax depreciation in excess of book depreciation	123,633			105,318
Regulatory temporary differences	35,652			29,326
Deferred purchased gas cost	15,428			21,358
Deferred compensation plans	(2,550		)	(2,130		)
Investment tax credit	(2,784		)	(3,654		)
Uncollectible accounts	(6,645		)	(9,210		)
Postretirement benefits	(8,314		)	(9,245		)
Incentive compensation	(43,224		)	(17,758		)
Financial instruments	(26,385		)	(13,767		)
Other, net of valuation allowance of $3,265 and $3,773, respectively	(10,759		)	11,454
Total (including amounts classified as current assets of $32,274 for 2007 and current liabilities of $15,011 for 2006)	$	360,341		$	344,119

The net deferred tax asset relating to the Company’s accumulated other comprehensive loss balance as of December 31, 2007 was comprised of a $173.3 million deferred tax asset related to the Company’s net unrealized loss from hedging transactions, a $7.5 million deferred tax asset related to other post-retirement benefits, a $9.9 million deferred tax asset related to the pension plans, and a $2.1 million deferred tax liability related to the Company’s net unrealized gain on available-for-sale securities. The net deferred tax asset relating to the Company’s other comprehensive loss balance as of December 31, 2006 was comprised of a $173.7 million deferred tax asset related to the Company’s net unrealized loss from hedging transactions, a $9.5 million deferred tax asset related to other post-retirement benefits, an $11.5 million deferred tax asset related to the pension plans, and a $2.1 million deferred tax liability related to the Company’s net unrealized gain on available-for-sale securities.

Income tax expense is summarized as follows:

	Years Ended December 31,
	2007			2006			2005
	(Thousands)

Current:
Federal	$	102,692		$	75,875		$	237,422
State	9,323			2,564			8,528
Subtotal	112,015			78,439			245,950
Deferred:
Federal	23,756			42,122			(91,119		)
State	9,264			(9,797		)	(718		)
Subtotal	33,020			32,325			(91,837		)
Amortization of deferred investment tax credit	(640		)	(1,058		)	(1,075		)
Total	$	144,395		$	109,706		$	153,038

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

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

	Years Ended December 31,
	2007			2006			2005
	(Thousands)

Tax at statutory rate	$	140,657		$	114,006		$	144,064
State income taxes	8,951			(8,130		)	5,076
Federal tax credits and incentives	(5,066		)	(551		)	(2,529		)
Book/Tax basis differences	(931		)	(1,050		)	(4,410		)
Incentive or deferred compensation	76			93			15,300
Other	708			5,338			(4,463		)
Income tax expense	$	144,395		$	109,706		$	153,038
Effective tax rate	35.9		%	33.7		%	37.2		%

During 2007, state income taxes increased as a result of a West Virginia law change enacted on April 4, 2007 that is effective for the Company’s tax year beginning January 1, 2009. This new law mandates unitary combined reporting, changes certain apportionment provisions for tax partnerships, changes certain definitions for financial organizations and makes miscellaneous changes to other corporate net income tax statutes. As a result of this law change, the Company recorded additional tax expense of $3.3 million to reflect an overall increase in the Company’s expected deferred tax liability as of the effective date.

During 2006, state income taxes decreased as a result of a change to state income tax rates as computed in accordance with SFAS No. 109 and the release of a state valuation allowance related to a state net operating loss carryover. During 2006, the Company reduced its valuation allowance for state net operating loss carryovers by $3.1 million as a result of an anticipated increase in prospective realization of those deferred tax assets. The other category does not include any items that are individually significant.

During 2005, following a moratorium imposed on the Company by the IRS for claiming any research and development (R&D) tax credits, the Company completed an analysis of its R&D expenditures for the years 2001 through 2005. This analysis resulted in a research tax credit that generated a tax benefit of $3.8 million for those periods, net of a tax reserve of $1.2 million. The study was extended to 2006 and 2007 with a recorded tax benefit of $0.6 million in each of those years.

During 2005, the Qualified Production Activities Deduction under Section 199 of the IRC, which provides for a phased-in deduction related to qualifying production activities, was provided for the first time under the American Jobs Creation Act of 2004. The Company recorded an income tax benefit for certain qualifying production activities of approximately $4.5 million, $0.6 million and $1.9 million in 2007, 2006 and 2005, respectively.

During 2005, the Company recorded $15.3 million in tax benefit disallowances under Section 162(m) of the IRC, primarily as the result of impairment of previously recorded deferred tax assets related to the employee deferred compensation programs and the 2003 Executive Performance Incentive Program.

During 2003, the Company requested permission to change its method of accounting for inventory and self-constructed property in accordance with IRC Section 263A to use the simplified service cost method and simplified production method of capitalizing costs. During 2005, the IRS and the U.S. Treasury Department issued guidance providing for further clarification indicating that certain self-constructed property does not qualify as eligible property for the simplified methods. In 2006, the Company requested and was granted permission to conform its capitalization method to the facts and circumstances method and believes that it is appropriately reserved for any tax exposures for prior years.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

An income tax benefit of approximately $18 million, $19 million and $18 million for the years ended December 31, 2007, 2006 and 2005, respectively, triggered by the exercise of nonqualified employee stock options and vesting of restricted share awards is reflected as an addition to common stockholders’ equity.

The Company has recorded a deferred tax asset of $10.0 million, net of valuation allowances of $3.3 million, related to tax benefits from state net operating loss carryforwards with various expiration dates ranging from 2009 to 2027.

The net decrease of $0.5 million in the total valuation allowance for the year ended December 31, 2007 was the result of an increase of $0.3 million for state net operating loss carryforwards and a decrease of $0.8 million to account for a reduction in the valuation allowance placed against deferred tax assets related to certain restricted stock grants paid in 2007 that were anticipated to result in non-deductible compensation under 162(m) of the IRC.

7. Discontinued Operations

In the fourth quarter of 2005, the Company sold its NORESCO domestic business for $82 million before customary purchase price adjustments. Income from discontinued operations for the year ended December 31, 2005 included after-tax charges totaling $18.7 million, including $13.7 million which related to the recording of income taxes associated with the difference between the book and tax basis of the NORESCO assets sold, and $5.0 million of after-tax losses on the sale related to other costs incurred as a result of this sale.

In the fourth quarter of 2006, the Company recorded a tax benefit of $3.2 million related to a reduced tax liability on the sale. The Company also reassessed its remaining reserves for costs incurred related to the sale and recorded after-tax income of $1.1 million as a result. These items are included in income from discontinued operations in the Company’s Statement of Consolidated Income for the year ended December 31, 2006.

In 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. The Company did not record a gain or loss on this sale.

Cash flows generated from the discontinued operations and the proceeds received from the sale of the Pan Am investment of $2.6 million and of the NORESCO Domestic operations of $80.0 million are included in the Consolidated Statements of Cash Flows for the years ended December 31, 2006 and 2005, respectively.

Total operating revenues reclassified to discontinued operations for the year ended December 31, 2005 was $143.5 million. Interest expense of discontinued operations allocated based upon a ratio of the net assets of the discontinued operations to the overall net assets of the Company was $1.5 million for the year ended December 31, 2005.

8. Equity in Nonconsolidated Investments

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

		Interest	Ownership as of December	December 31,
Investees	Location	Type	31, 2007	2007		2006
				(Thousands)
Nora Gathering, LLC (Nora LLC)	USA	Joint	50%	$	96,985	$	—
Appalachian Natural Gas Trust (ANGT)	USA	Limited	1%	38,381		35,023
Total equity in nonconsolidated investments				$	135,366	$	35,023

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

The Company’s ownership share of the earnings for 2007, 2006 and 2005 related to the total investments was $3.1 million, $0.3 million and $0.8 million, respectively.

As discussed in Note 4, the Company obtained a 50% ownership interest in Nora LLC through a series of transactions with PMOG by contributing Nora area gathering property in exchange for the ownership interest. As a result of the transaction, the Company recorded an initial equity investment in Nora LLC of $94.3 million.

Equitable Production’s equity investment in ANGT represents an ownership interest in transactions by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. As of December 31, 2007, Equitable Production’s investment in ANGT totaled $25.5 million, while the Company’s total investment was $38.4 million. As of December 31, 2006, Equitable Production’s investment in ANGT totaled $23.3 million, while the Company’s total investment was $35.0 million. The portion of the investment not held by Equitable Production is intended to fund plugging and abandonment and other liabilities for which the Company self-insures. The Company did not make any additional equity investments in nonconsolidated investments during 2006.

The following tables summarize the unaudited condensed financial statements for nonconsolidated investments accounted for under the equity method of accounting for the periods noted:

Summarized Balance Sheets

	As of December 31,
	2007		2006
	(Thousands)
Current assets	$	44,240	$	5,085
Noncurrent assets	337,247		188,742
Total assets	$	381,487	$	193,827

Current liabilities	$	11,068	$	3,194
Stockholders’ equity	370,419		190,633
Total liabilities and stockholders’ equity	$	381,487	$	193,827

Summarized Statements of Income

	Year Ended December 31,
	2007		2006		2005
	(Thousands)
Revenues	$	101,817	$	94,477	$	108,307
Costs and expenses applicable to revenues	—		—		—
Net revenues	101,817		94,477		108,307
Operating expenses	51,345		43,056		39,601
Net income	$	50,472	$	51,421	$	68,706

9. Investments, Available-For-Sale

As of December 31, 2007, the investments classified by the Company as available-for-sale consist of approximately $35.7 million of equity and bond funds intended to fund plugging and abandonment and other liabilities for which the Company self-insures. Any unrealized gains or losses with respect to investments classified as available-for-sale are recognized within the Consolidated Balance Sheets as a component of equity, accumulated other comprehensive loss.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

	December 31, 2007
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(Thousands)
Equity funds	$	24,839	$	5,914	$	—	$	30,753
Bond funds	4,879		43		—		4,922
Total investments	$	29,718	$	5,957	$	—	$	35,675

	December 31, 2006
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(Thousands)
Equity funds	$	25,164	$	6,106	$	—	$	31,270
Total investments	$	25,164	$	6,106	$	—	$	31,270

During the first quarter of 2007, the Company reviewed its investment portfolio including its investment allocation and as a result sold equity funds with a cost basis of $6.3 million for total proceeds of $7.3 million, resulting in the Company recognizing a gain of $1.0 million, which is included in other income in the Statement of Consolidated Income. The Company used the proceeds from these sales and other available cash to purchase other bond and equity funds with a cost basis totaling $9.7 million during the first quarter of 2007. These investments are classified as available-for-sale in the Consolidated Balance Sheet.

In May 2005, the three variable share forward transactions associated with Kerr-McGee shares were terminated as described in Note 3. The Company concurrently sold 4.3 million Kerr-McGee shares to its three counterparties and received $227.4 million in pre-tax net proceeds at an average price of $75.43 per share. In addition, the Company unconditionally tendered 1.7 million Kerr-McGee shares at $85.00 per share to Kerr-McGee in connection with Kerr-McGee’s Dutch auction tender offer to purchase its own shares. Accordingly, as a result of its tender of shares, the Company received approximately $49.0 million in pre-tax proceeds on the sale of approximately 0.6 million shares. These transactions resulted in pre-tax gains to the Company totaling $34.2 million, net of collar termination costs.

In various transactions during 2005, the Company sold its approximately 2.1 million remaining Kerr-McGee shares for total pre-tax proceeds of $184.1 million. The sale of these shares resulted in pre-tax gains to the Company totaling $76.1 million. The Company has no further interest or ownership in any Kerr-McGee shares.

The Company recorded pre-tax dividend income, net of payments to the counterparties for the aforementioned collars, of $1.2 million for the year ended December 31, 2005. This dividend income is recorded in other income on the Statements of Consolidated Income.

The Company utilizes the specific identification method to determine the cost of all investment securities sold.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

10. Regulatory Assets

The following table summarizes the Company’s regulatory assets, net of amortization, as of December 31, 2007 and 2006. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of its regulatory assets.

	December 31,
Description	2007		2006
	(Thousands)
Deferred taxes	$	62,897	$	59,932
Deferred purchased gas costs	39,081		54,062
Other postretirement benefits (SFAS No. 106)	13,010		15,590
Delinquency Reduction Opportunity Program	1,734		3,006
Other	374		761
Total regulatory assets	117,096		133,351
Amounts classified as other current assets	39,081		54,062
Total long-term regulatory assets	$	78,015	$	79,289

The regulatory asset associated with deferred taxes primarily represents deferred income taxes recoverable through future rates once the taxes become current. The Company expects to recover the amortization of this asset through rates. At December 31, 2007, the deferred purchased gas costs regulatory asset was reduced by $3.6 million of unrealized gains on derivative contracts designated as cash flow hedges that would have been classified as other comprehensive income absent the probability of recovery through rates. There were no unrealized gains or losses included in deferred purchased gas costs at December 31, 2006.

Under the Equitrans (a subsidiary of the Company) rate case settlement, the Company began amortization of postretirement benefits other than pensions previously deferred as well as recognizing expenses for on-going postretirement benefits other than pensions, which are now subject to recovery from July 1, 2005 forward in the approved rates. The reduction in the Company’s regulatory asset for amortization of postretirement benefits other than pensions previously deferred was approximately $1.4 million for each of the years ended December 31, 2007 and 2006. In addition, as a part of the rate case settlement, the Company’s regulatory asset was reduced approximately $1.3 million in 2006 for amortization of postretirement benefits other than pensions previously deferred and on-going postretirement benefits other than pensions for the period July 1, 2005 to December 31, 2005.

The Company adopted SFAS No. 158 as of December 31, 2006 and recorded a regulatory asset at that time for Equitrans’ other postretirement benefits. This regulatory asset was $8.8 million at December 31, 2007 and $9.8 million at December 31, 2006. The Company believes the future recovery of the unfunded status of the Equitrans other postretirement benefits is probable in accordance with the requirements of SFAS No. 71.

The regulatory asset associated with a Delinquency Reduction Opportunity Program at Equitable Distribution relates to uncollectible accounts receivable resulting from unusually high natural gas prices and unseasonably cold weather experienced during the winter of 2000-2001. The regulatory asset was initially established based upon the Company’s ability to recover these costs through a surcharge in rates. In 2002, the PA PUC issued an order approving a Delinquency Reduction Opportunity Program that gives incentives to low-income customers to make payments that exceed their current bill amount in order to receive additional credits from the Company intended to speed the reduction of the customer’s delinquent balance. This program is funded through customer contributions and through the existing surcharge in rates.

The following regulatory assets do not earn a return on investment: deferred taxes, other postretirement benefits (SFAS No. 106) and Delinquency Reduction Opportunity Program. The associated remaining recovery period for the regulatory assets established for both the other postretirement benefits and the Delinquency Reduction Opportunity Program is three years at December 31, 2007. The associated remaining recovery period for the regulatory assets associated with deferred taxes is variable depending on the life of the book/tax difference generating the deferred item.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

11. Short-Term Loans

On October 27, 2006, the Company entered into a $1.5 billion, five-year revolving credit agreement, which replaced the Company’s previous $1 billion, five-year revolving credit agreement. On December 15, 2006, the maturity date was extended to October 26, 2011 pursuant to its terms. Additionally, the Company may request two one-year extensions of the stated maturity date. The 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. Subject to certain terms and conditions, the Company may, on a one time basis, request that the lender’s commitments be increased to an aggregate amount of up to $2.0 billion.

The Company is not required to maintain compensating bank balances. The Company’s debt issuer credit ratings, as determined by either Standard & Poor’s or Moody’s on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s debt credit rating, the higher the level of fees and borrowing rate.

Due to the volatility in the short-term debt markets during the second half of 2007, the Company determined that its lowest cost of short term borrowings would be obtained by utilizing its revolving credit facility. As of December 31, 2007, the Company had outstanding short-term loans under the revolving credit facility of $450.0 million and no commercial paper balances. As of December 31, 2006, the Company had no outstanding loans under the revolving credit facility and commercial paper balances of $136.0 million. Commitment fees averaging one-seventeenth of one percent in 2007 and 2006 were paid to maintain credit availability under the revolving credit facility.

The weighted average interest rate for short-term loans outstanding as of December 31, 2007 and 2006 was 5.26% and 5.45%, respectively. The maximum amount of outstanding short-term loans at any time during the year was $450.0 million in 2007 and $467.5 million in 2006. The average daily balance of short-term loans outstanding over the course of the year was approximately $199.5 million and $126.0 million at weighted average annual interest rates of 5.84% and 4.63% during 2007 and 2006, respectively.

12. Long-Term Debt

	December 31,
	2007		2006
	(Thousands)

5.15% notes, due March 1, 2018	$	200,000	$	200,000
5.15% notes, due November 15, 2012	200,000		200,000
5.00% notes, due October 1, 2015	150,000		150,000
7.75% debentures, due July 15, 2026	115,000		115,000
Medium-term notes:
8.5% to 9.0% Series A, due 2009 thru 2021	50,500		50,500
7.3% to 7.6% Series B, due 2013 thru 2023	30,000		30,000
7.6% Series C, due 2018	8,000		18,000
	753,500		763,500
Less debt payable within one year	—		10,000
Total long-term debt	$	753,500	$	753,500

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

Aggregate maturities of long-term debt are $0 in 2008, $4.3 million in 2009, $0 in 2010, $6.0 million in 2011 and $200.0 million in 2012.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

13. Pension and Other Postretirement Benefit 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. The Company adopted SFAS No. 158 as of December 31, 2006.

During the fourth quarter of 2006, the Company recognized a settlement expense of approximately $3.3 million, comprised of $2.7 million for pension benefits and $0.6 million for other postretirement benefits, for an early retirement program. This settlement expense was primarily the result of special termination benefits. Under this settlement, the affected employees were provided the option to either receive the lump-sum value or an insured monthly annuity of their pension benefit or roll over the lump-sum value of their pension benefit to the Company’s defined contribution plan. The $3.3 million settlement expense is recorded as an operation and maintenance expense included within operating expense of the Equitable Midstream business segment (see Note 2). As a result of this settlement, the Company’s projected benefit obligation decreased by approximately $1.4 million. The Company made a cash contribution of $1.3 million to the pension plan in the first quarter of 2007 to fund the early retirement program.

During 2006, the Company made certain retiree medical plan design changes that decreased the Company’s other postretirement benefits plan benefits obligation by approximately $10.2 million. These design changes included a decrease in the Company’s capped contribution per retiree and the elimination of certain retiree benefits.

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. These settlement expenses were primarily the result of accelerated recognition of unrecognized losses. Under these settlements, the affected employees were provided the option to either roll over the lump-sum value of their pension benefit to the Company’s defined contribution plan or to receive an insured monthly annuity benefit at the time they retire. Additionally, $13.1 million and $1.2 million of these pension settlement expenses were recorded as a selling, general and administrative expense within operating expense of the Equitable Distribution and Equitable Midstream business segments, respectively, and $0.2 million was a gathering and compression expense included within operating expense of the Equitable Midstream business segment (see Note 2). As a result of these settlements, the Company’s projected benefit obligation decreased by approximately $13.9 million.

All other non-represented employees are participants in a defined contribution plan.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

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

	Pension Benefits						Other Benefits
	2007			2006			2007			2006
	(Thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	82,122		$	82,153		$	47,144		$	54,257
Service cost	252			430			493			553
Interest cost	4,373			4,389			2,542			2,899
Amendments	—			—			(1,055		)	(10,180		)
Actuarial (gain) loss	(1,985		)	5,325			(3,338		)	5,317
Benefits paid	(7,014		)	(7,637		)	(5,520		)	(6,291		)
Curtailments	—			227			—			410
Settlements	(4,718		)	(4,181		)	—			—
Special termination benefits	198			1,416			—			179
Benefit obligation at end of year	$	73,228		$	82,122		$	40,266		$	47,144

Change in plan assets:
Fair value of plan assets at beginning of year	$	72,616		$	75,079		$	—		$	—
Actual gain on plan assets	4,745			7,593			—			—
Employer contributions	1,339			1,751			—			—
Benefits paid	(7,014		)	(7,637		)	—			—
Settlements	(4,718		)	(4,170		)	—			—
Fair value of plan assets at end of year	$	66,968		$	72,616		$	—		$	—

Funded status at end of year	$	(6,260	)	$	(9,506	)	$	(40,266	)	$	(47,144	)

	Pension Benefits						Other Benefits
	2007			2006			2007			2006
	(Thousands)
Amounts recognized in the statement of financial position consist of:
Current liabilities	$	—		$	—		$	(4,758	)	$	(5,678	)
Noncurrent liabilities	(6,260		)	(9,506		)	(35,508		)	(41,466		)
Net amount recognized	$	(6,260	)	$	(9,506	)	$	(40,266	)	$	(47,144	)
Amounts recognized in accumulated other comprehensive loss consist of, net of tax:
Net loss	$	14,556		$	16,390		$	15,371		$	17,945
Net prior service cost (credit)	305			727			(3,872		)	(3,662		)
Net amount recognized	$	14,861		$	17,117		$	11,499		$	14,283

The accumulated benefit obligation for all defined benefit pension plans was $73.2 million and $82.1 million at December 31, 2007 and 2006, respectively. The Company uses a December 31 measurement date for its defined benefit pension and other postretirement plans.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

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

	Pension Benefits									Other Benefits
	2007			2006			2005			2007			2006			2005
	(Thousands)

Components of net periodic benefit cost:
Service cost	$	252		$	430		$	899		$	493		$	553		$	541
Interest cost	4,373			4,389			5,891			2,542			2,899			3,168
Expected return on plan assets	(5,616		)	(6,132		)	(8,032		)	—			—			—
Amortization of prior service cost	166			370			766			(859		)	(137		)	(42		)
Recognized net actuarial loss	1,453			1,069			867			2,373			2,146			2,299
Settlement loss and special termination benefits (a)	864			2,348			15,713			—			179			—
Curtailment loss	547			602			2,648			—			410			—
Net periodic benefit cost	$	2,039		$	3,076		$	18,752		$	4,549		$	6,050		$	5,966

(a) The 2005 settlement loss and special termination benefits includes $10.4 million of loss recognition for the settlement of the Steelworkers pension benefit obligation and $1.3 million of loss associated with the non-represented employees portion of the pension benefit obligation which was settled during the fourth quarter of 2005.

Under the Equitrans rate case settlement, the Company began amortization of post-retirement benefits other than pensions previously deferred as well as recognizing expenses for on-going post-retirement benefits other than pensions, which are now subject to recovery from July 1, 2005 forward in the approved rates. Expenses recognized by the Company for the year ended December 31, 2007 for amortization of post-retirement benefits other than pensions previously deferred and on-going post-retirement benefits other than pensions were approximately $1.4 million and $1.2 million, respectively. Expenses recognized by the Company for the year ended December 31, 2006 for amortization of post-retirement benefits other than pensions previously deferred and on-going post-retirement benefits other than pensions were approximately $1.4 million and $1.2 million, respectively. In addition, as a part of the rate case settlement, the Company recognized expenses for year ended December 31, 2006 of approximately $1.3 million for amortization of post-retirement benefits other than pensions previously deferred and on-going post-retirement benefits other than pensions for the period July 1, 2005 to December 31, 2005.

	Pension Benefits								Other Benefits
	2007			2006		2005			2007			2006			2005
	(Thousands)

Other changes in plan assets and benefit obligations recognized in other comprehensive loss, net of tax:
Net (gain) loss	$	(1,834	)	$	1,024	$	(4,325	)	$	(2,574	)	$	17,945		$	—
Net prior service (credit) cost	(422		)	727		—			(210		)	(3,662		)	—
Total recognized in other comprehensive income, net of tax	(2,256		)	1,751		(4,325		)	(2,784		)	14,283			—
Total recognized in net periodic benefit cost and other comprehensive income, net of tax	$	(217	)	$	4,827	$	14,427		$	1,765		$	20,333		$	5,966

The estimated net loss and net prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year are $1.2 million and $0.1 million, respectively. The estimated net loss and net prior service credit for the other postretirement benefit plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year are $2.0 million and ($0.9 million).

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

The following weighted average assumptions were used to determine the benefit obligations for the Company’s defined benefit pension and other postretirement benefit plans at December 31:

	Pension Benefits				Other Benefits
	2007		2006		2007		2006

Discount rate	6.25	%	5.75	%	6.25	%	5.75	%
Rate of compensation increase	N/A		N/A		N/A		N/A

The following weighted average assumptions were used to determine the net periodic benefit cost for the Company’s defined benefit pension and other postretirement benefit plans for the years ended December 31:

	Pension Benefits				Other Benefits
	2007		2006		2007		2006

Discount rate	5.75	%	5.75	%	5.75	%	5.75	%
Expected return on plan assets	8.25	%	8.25	%	N/A		N/A
Rate of compensation increase	N/A		N/A		N/A		N/A

The expected rate of return is established at the beginning of the fiscal year that it relates to based upon information available to the Company at that time, including the plans’ investment mix and the forecasted rates of return on these types of securities. The Company considered the historical rates of return earned on plan assets, an expected return percentage by asset class based upon a survey of investment managers and the Company’s actual and targeted investment mix. Any differences between actual experience and assumed experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized into the Company’s net periodic benefit cost. The expected rate of return determined as of January 1, 2008 totaled 8.25%. This assumption will be used to derive the Company’s 2008 net periodic benefit cost. The rate of compensation increase is not applicable in determining future benefit obligations as a result of plan design. Pension expense increases as the expected long-term rate of rate of return decreases or if the discount rate is lowered. Lowering the expected long-term rate of return by 0.5% or lowering the discount rate by 0.5% as of December 31, 2007, would not have a significant impact on pension expense for 2007.

For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2008 is 10.5% for both the Pre-65 and Post-65 medical charges. The rates were assumed to decrease gradually to ultimate rates of 5.5% in 2013.

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

	One-Percentage-Point Increase						One-Percentage-Point Decrease
	(Thousands)						(Thousands)
	2007		2006		2005		2007			2006			2005
Increase (decrease) to total of service and interest cost components	$	55	$	115	$	91	$	(54	)	$	(109	)	$	(90	)
Increase (decrease) to postretirement benefit obligation	$	751	$	1,071	$	2,030	$	(717	)	$	(1,000	)	$	(1,897	)

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

The Company’s pension asset allocation at December 31, 2007 and 2006 and target allocation for 2008 by asset category are as follows:

	Target Allocation 2008		Percentage of Plan Assets at December 31,
Asset Category	Target Allocation 2008		2007		2006

Domestic broadly diversified equity securities	40% - 60	%	46	%	50	%
Fixed income securities and inflation hedge securities	20% - 50	%	40	%	36	%
International broadly diversified equity securities	5% - 15	%	13	%	11	%
Other	0% - 15	%	1	%	3	%
			100	%	100	%

The investment activities of the Company’s pension plan are supervised and monitored by the Company’s Benefits Investment Committee. The Benefits Investment Committee has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Benefits Investment Committee are to minimize high levels of risk at the total pension investment fund level. The Benefits Investment Committee monitors the actual asset allocation on a quarterly basis and adjustments are made, as needed, to rebalance the assets within the prescribed target ranges. Comparative market and peer group benchmarks are utilized to ensure that each of the firm’s investment managers is performing satisfactorily.

The Company made cash contributions of approximately $1.3 million and $1.8 million to its pension plan during 2007 and 2006, respectively, as a result of the previously described settlements. The Company expects to make cash contributions of less than $0.1 million to its pension plan during 2008.

The following pension benefit payments, which reflect expected future service, are expected to be paid during each of the next five years and the five years thereafter: $7.3 million in 2008; $7.4 million in 2009; $6.8 million in 2010; $7.2 million in 2011; $6.8 million in 2012; and $31.9 million in the five years thereafter.

The following benefit payments for post-retirement benefits other than pensions, which reflect expected future service, are expected to be paid during each of the next five years and the five years thereafter: $4.9 million in 2008; $4.7 million in 2009; $4.5 million in 2010; $4.4 million in 2011; $4.1 million in 2012; and $18.1 million in the five years thereafter.

Expense recognized by the Company related to its 401(k) employee savings plans totaled $6.5 million in 2007, $5.2 million in 2006 and $5.1 million in 2005.

14. Interest Expense and Allowance for Funds Used During Construction

Carrying costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. The calculated allowance for funds used during construction includes capitalization of the cost of financing construction of assets subject to regulation by the PA PUC, the WV PSC or the FERC, in accordance with SFAS No. 71. A computed interest cost and a designated cost of equity for financing the construction of these regulated assets are recorded in the Company’s income statement. The debt portion is calculated based on the average cost of debt. Interest costs on debt amounts capitalized are included as a reduction of interest expense in the Statements of Consolidated Income. These interest costs were $6.7 million, $0.6 million and $0.2 million for the years ended December 31, 2007, 2006 and 2005, respectively. The equity portion is calculated using the most recent equity rate of return approved by the applicable regulator. Equity amounts capitalized are included in other income in the Statements of Consolidated Income. The equity amounts capitalized were $7.6 million, $1.4 million and $0.3 million for the years ended December 31, 2007, 2006 and 2005 respectively.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

15. Common Stock and Earnings Per Share

At December 31, 2007, shares of Equitable’s authorized and unissued common stock were reserved as follows:

		(Thousands)

Possible future acquisitions		13,194
Stock compensation plans		10,224
Total		23,418

Earnings Per Share

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

	Years Ended December 31,
	2007		2006		2005
	(Thousands, except per share amounts)

Basic earnings per common share:
Income from continuing operations	$	257,483	$	216,025	$	258,574
Income from discontinued operations, net of tax	—		4,261		1,481
Net income applicable to common stock	$	257,483	$	220,286	$	260,055
Average common shares outstanding	121,381		120,124		121,099
Basic earnings per common share	$	2.12	$	1.83	$	2.15
Diluted earnings per common share:
Income from continuing operations	$	257,483	$	216,025	$	258,574
Income from discontinued operations, net of tax	—		4,261		1,481
Net income applicable to common stock	$	257,483	$	220,286	$	260,055
Average common shares outstanding	121,381		120,124		121,099
Potentially dilutive securities:
Stock options and awards (a)	1,458		1,989		2,616
Total	122,839		122,113		123,715
Diluted earnings per common share	$	2.10	$	1.80	$	2.10

(a) Options to purchase 7,298 and 53,093 shares of common stock were not included in the computation of diluted earnings per common share for 2007 and 2006, respectively, because the options’ exercise prices were greater than the average market prices of the common shares. There were no antidilutive options for 2005.

16. Accumulated Other Comprehensive Loss

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

	2007			2006
	(Thousands)

Net unrealized loss from hedging transactions	$	(286,776	)	$	(286,871	)
Unrealized gain on available-for-sale securities	3,872			3,969
Pension and other post-retirement benefits adjustment	(26,360		)	(31,400		)
Accumulated other comprehensive loss	$	(309,264	)	$	(314,302	)

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

17. Share-Based Compensation Plans

The Company adopted SFAS No. 123R effective January 1, 2006, using the modified prospective method. Under the modified prospective method, compensation cost is recognized beginning with the effective date and prior period results are not restated. As such, compensation cost related to all share-based awards, including non-qualified stock options, was recognized in the Company’s Consolidated Financial Statements for the years ended December 31, 2006 and 2007.

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123R to employee share-based awards for the year ended December 31, 2005.

	Year Ended December 31, 2005
	(Thousands)
Net income, as reported	$	260,055

Add: Gross share-based employee compensation expense included in reported net income	48,363

Deduct: Income tax benefit from share-based employee compensation expense included in reported net income	(16,182		)

Deduct: Total share-based employee compensation expense determined under fair value method for all awards, net of related tax effects	(33,693		)

Pro forma net income	$	258,543

Earnings per share:
Basic, as reported	$	2.15
Basic, pro forma	$	2.13

Diluted, as reported	$	2.10
Diluted, pro forma	$	2.09

Prior to the adoption of SFAS No. 123R, the Company presented all tax benefits for deductions resulting from the exercise of share-based awards as cash flows from operating activities in its Statements of Consolidated Cash Flows. SFAS No. 123R requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a cash flow from financing activities, rather than as a cash flow from operating activities. This requirement reduced cash flows from operating activities and increased cash flows from financing activities by $15.7 million for each of the years ended December 31, 2007 and 2006. Total net cash flows were not impacted by the adoption of SFAS No. 123R.

Cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2007, 2006, and 2005, was $3.2 million, $34.9 million and $25.0 million, respectively. The actual tax benefits realized for tax deductions from share-based payment arrangements for the years ended December 31, 2007, 2006, and 2005, were $19.4 million, $18.9 million and $28.0 million, respectively.

The Company typically funds restricted share obligations from treasury stock at the date of grant and has a policy of issuing shares from treasury stock to satisfy option exercises.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

Share-based compensation expense recorded by the Company was as follows:

	Years Ended December 31,
	2007		2006				2005
	(Thousands)
2005 Executive Performance Incentive Program	$	63,515		$		21,093	$	22,465
2003 Executive Performance Incentive Program	—			—			21,345
2007 Supply Long-Term Incentive Program	780			—			—
Restricted stock awards	2,830			3,450			3,356
Non-qualified stock options	201			976			—
Non-employee directors’ share-based awards	1,801			1,111			1,197
Total share-based compensation expense	$	69,127		$	26,630		$	48,363

Executive Performance Incentive Programs

In February 2005, the Compensation Committee of the Board of Directors adopted the 2005 Executive Performance Incentive Program (2005 Program) under the 1999 Long-Term Incentive Plan. The 2005 Program was established to provide additional incentive benefits to retain executive officers and certain other employees of the Company in order to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. A total of 1,001,600 stock units granted under the 2005 Program are outstanding as of December 31, 2007. No additional units may be granted. The vesting of these stock units will occur on December 31, 2008, contingent upon a combination of the level of total shareholder return relative to the 29 peer companies identified below and the Company’s average absolute return on total capital during the four-year performance period. As a result, zero to 2,504,000 units (250% of the units outstanding) may be distributed upon vesting. Payment of awards is expected to be made in cash and stock based on the price of the Company’s common stock at the end of the performance period, December 31, 2008. The Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. The Company continually monitors its stock price and performance in order to assess the impact on the ultimate payout under the 2005 Program. The Company modified its assumptions during 2007 and increased both the ultimate share price and the payout multiple at the vesting date to $60.00 and 225% of the units awarded, respectively. As a result, the Company recognized an increase in long-term incentive plan expense associated with the 2005 Program of $42.3 million for the year ended December 31, 2007. The 2005 Program expense for the years ended December 31, 2007, 2006 and 2005 was classified as selling, general and administrative expense in the Statements of Consolidated Income. A portion of the 2005 Program expense is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note 2. The Company has recorded a total accrual for the 2005 Program of $107.1 million in other current liabilities in its Consolidated Balance Sheet as of December 31, 2007.

The current peer companies for the 2005 Program are as follows:

AGL Resources Inc.	New Jersey Resources Corp.	Southern Union Co.
Atmos Energy Corp.	NICOR, Inc.	Southwest Gas Corp.
CMS Energy Corp.	NiSource Inc.	Southwestern Energy Co.
Dynegy Inc.	Northwest Natural Gas Co.	UGI Corp.
El Paso Corp.	OGE Energy Corp.	Westar Energy, Inc.
Energen Corp.	ONEOK, Inc.	WGL Holdings, Inc.
The Laclede Group, Inc.	Piedmont Natural Gas Co., Inc.	Williams Companies, Inc.
MDU Resources, Inc.	Questar Corp.
National Fuel Gas Co.	Sempra Energy

During 2007, four members of the peer group originally selected for the 2005 program (Cascade Natural Gas Co., Keyspan Corp., Kinder Morgan Inc., and Peoples Energy Corp.) completed significant transactions which resulted in those companies merging out of existence or going private.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

The vesting of performance-based stock units granted under the 2003 Executive Performance Incentive Program (2003 Program) occurred on December 30, 2005, after the ordinary close of the performance period and resulted in approximately 1.3 million units (167% of the award) being distributed in cash on that date. This payment totaled $51.0 million.

2007 Supply Long-Term Incentive Program

On July 1, 2007, the Company established the 2007 Supply Long-Term Incentive Program (2007 Supply Program) to provide a long-term incentive compensation opportunity to key employees in the Equitable Production and Equitable Midstream segments. Awards granted may be earned by achieving pre-determined total sales volumes targets and by satisfying certain applicable employment requirements. The awards earned may be increased to a maximum of three times the initial award or reduced to zero based upon achievement of the predetermined performance levels. Payment of awards will be made in cash based on the price of the Company’s common stock at the end of the performance period, December 31, 2010. The Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. The Company granted 163,940 awards under this program during 2007. As of December 31, 2007, the Company’s assumptions for the ultimate share price and the payout multiple at the vesting date for the 2007 Supply Program were $72.00 and 100% of the units awarded, respectively. Total compensation cost recorded for the 2007 Supply Program was $1.7 million for the year ended December 31, 2007, which included $0.9 million of cost capitalized as part of oil and gas-producing properties and $0.8 million recorded as expense in the Company’s Consolidated Statement of Income.

Restricted Stock Awards

The Company granted 77,540, 112,700, and 138,400 restricted stock awards during the years ended December 31, 2007, 2006, and 2005, respectively, to key employees of the Company. The shares granted will be fully vested at the end of the three-year period commencing with the date of grant. The weighted average fair value of these restricted stock grants, based on the grant date fair value of the Company’s stock, was $44.11, $36.11, and $33.07, for the years ended December 31, 2007, 2006, and 2005, respectively. The total fair value of restricted stock awards vested during the years ended December 31, 2007, 2006, and 2005 was $6.7 million, $1.5 million and $1.8 million, respectively.

As of December 31, 2007, there was $4.6 million of total unrecognized compensation cost related to nonvested restricted stock awards. That cost is expected to be recognized over a remaining weighted average vesting term of approximately 19 months.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

A summary of restricted stock activity as of December 31, 2007, and changes during the year then ended, is presented below:

Restricted Stock	Non-Vested Shares		Weighted Average Fair Value		Weighted Average Remaining Contractual Term (months)	Aggregate Fair Value
Outstanding at January 1, 2007	543,340		$	25.99		$	14,122,715

Granted	77,540		$	44.11		$	3,419,989

Vested	(332,815	)	$	20.13		$	(6,700,724	)

Forfeited	(12,715	)	$	37.10		$	(471,780	)

Outstanding at December 31, 2007	275,350		$	37.66	19	$	10,370,200

Non-Qualified Stock Options

The fair value of the Company’s option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the years ended December 31, 2007, 2006, and 2005. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the historical dividend yield of the Company’s stock. Expected volatilities are based on historical volatility of the Company’s stock. The expected term of options granted represents the period of time that options granted are expected to be outstanding based on historical option exercise experience.

	Years Ended December 31,
	2007	2006	2005
Risk-free interest rate	3.99% to 4.97%	4.51% to 5.04%	3.74% to 4.34%
Dividend yield	1.77% to 2.29%	2.34% to 2.38%	2.75% to 2.83%
Volatility factor	.148 to .183	.212 to .226	.258 to .262
Expected term	3 - 6 years	7 years	7 years

The Company granted 27,421, 84,935, and 68,898 stock options during the years ended December 31, 2007, 2006, and 2005, respectively, all of which comprised options granted for reload rights associated with previously-awarded options. The weighted average grant date fair value of these reload option grants was $7.33, $9.43, and $7.65 for the years ended December 31, 2007, 2006, and 2005, respectively. The total intrinsic value of options exercised during the years ended December 31, 2007, 2006, and 2005 was $47.6 million, $52.2 million and $48.1 million, respectively.

As of December 31, 2007, there was no unrecognized compensation cost related to outstanding nonvested stock options as all outstanding options were fully vested.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

A summary of option activity as of December 31, 2007, and changes during the year then ended, is presented below:

Non-qualified Stock Options	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1, 2007	2,961,674		$	16.86
Granted	27,421		$	46.19
Exercised	(1,359,173	)	$	17.50
Forfeited	—		$	—
Outstanding at December 31, 2007	1,629,922		$	16.76	3.6 years	$	59,532,571
Exercisable at December 31, 2007	1,629,922		$	16.76	3.6 years	$	59,532,571

Non-employee Directors’ Share-Based Awards

At December 31, 2007, 101,500 options were outstanding under the 1999 Nonemployee Directors’ Stock Incentive Plan at prices ranging from $7.66 to $19.56 per share. The exercise price for each award is equal to the market price of the Company’s common stock on the date of grant. Each option is subject to time-based vesting provisions and expires 5 to 10 years after date of grant.

The Company has also historically granted to non-employee directors share-based awards which vested upon award. The value of the share-based awards will be paid in cash on the earlier of the director’s death or retirement from the Company’s Board of Directors. The Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. A total of 88,530 non-employee director share based awards were outstanding as of December 31, 2007. A total of 15,570, 18,000, and 18,000 share based awards were granted to non-employee directors during the years ended December 31, 2007, 2006, and 2005, respectively. The weighted average fair value of these grants, based on the grant date fair value of the Company’s stock, was $49.88, $35.12, and $28.37 for the years ended December 31, 2007, 2006, and 2005, respectively.

18. Fair Value of Financial Instruments

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

The estimated fair value of long-term debt described in Note 12 at December 31, 2007 and 2006 was $776.5 million and $786.0 million, respectively. The fair value was estimated based on discounted values using a current discount rate reflective of the remaining maturity.

The estimated fair value of liabilities for derivative instruments described in Note 3, excluding trading activities which are marked-to-market, was a $34.9 million asset and a $489.2 million liability at December 31, 2007, and a $129.7 million asset and a $544.4 million liability at December 31, 2006.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

19. Concentrations of Credit Risk

Revenues and related accounts receivable from the Equitable Production segment’s operations are generated primarily from the sale of produced natural gas and limited amounts of crude oil to certain marketers, Equitable Energy, LLC (an affiliate), other Appalachian Basin purchasers and utility and industrial customers located mainly in the Appalachian area; the sale of produced NGLs to a gas processor in Kentucky; and gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.

Equitable Distribution’s operating revenues and related accounts receivable are generated from state-regulated distribution natural gas sales and transportation to approximately 275,000 residential, commercial and industrial customers located in southwestern Pennsylvania, northern West Virginia and eastern Kentucky. The transmission and storage operations of Equitable Midstream include FERC-regulated interstate pipeline transportation and storage service for Equitable Distribution, as well as other utility and end-user customers located in the northeastern United States. These operations also provide commodity procurement and delivery, physical natural gas management operations and control, and customer support services to energy consumers including large industrial, utility, commercial, institutional and certain marketers primarily in the Appalachian and mid-Atlantic regions.

Equitable Distribution continues to aggressively monitor and analyze various customer-related metrics and their impact on accounts receivable. The Company employs a firm collections strategy which is comprised of various collections tactics, including termination of service if necessary, as well as outreach to low income customers to provide information regarding energy assistance programs. The outreach to low income customers includes enrolling customers into the Customer Assistance Program which is an affordable payment plan for low income customers based on a percentage of total household income. This program is subsidized by the Company and recovered through rates charged to other residential customers.

Approximately 65% and 73% of the Company’s accounts receivable balance as of December 31, 2007 and 2006, respectively, represent amounts due from marketers. The Company manages the credit risk of sales to marketers by limiting its dealings to those marketers who meet the Company’s criteria for credit and liquidity strength and by proactively monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in order for that marketer to meet the Company’s credit criteria. As a result, the Company did not experience any significant defaults on sales of natural gas to marketers during the years ended December 31, 2007 and 2006.

The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. NYMEX-traded futures contracts have minimal credit risk because futures exchanges are the counterparties. The Company manages the credit risk of the other derivative contracts by limiting dealings to those counterparties who meet the Company’s criteria for credit and liquidity strength. Some of the Company’s agreements with counterparties contain netting provisions in order to mitigate the Company’s short-term and long-term exposure in the event of default.

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

20. Commitments and Contingencies

The Company has annual commitments of approximately $39.0 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to ten years as of December 31, 2007, which relate to natural gas distribution and production operations. However, the Company believes that approximately $25.5 million of these annual costs are recoverable in customer rates.

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

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.

In June 2006, the West Virginia Supreme Court of Appeals issued a decision involving interpretation of certain types of oil and gas leases of an unrelated party, in a case where a class of royalty owners in the state of West Virginia had filed a lawsuit claiming that the defendant underpaid royalties by deducting certain post-production costs not permitted by such types of leases and not paying a fair value for the gas produced from the royalty owners’ leases. In January 2007, the jury in the aforementioned case returned a verdict in favor of the plaintiff royalty owners, awarding the plaintiffs significant compensatory and punitive damages for the alleged underpayment of royalties. While the defendant has appealed the verdict, this decision may ultimately impact other royalty interest rights in West Virginia. Claims have been brought against others in the oil and gas industry, including the Company. The proceedings against the Company are in the early stages and the plaintiffs have sought class certification. The Company believes that the claims and facts decided in the unrelated lawsuit can be differentiated from those asserted against the Company. Nevertheless, the Company has reviewed its West Virginia royalty agreements and established a reserve it believes to be appropriate.

The Company is subject to various federal, state and local environmental and environmentally related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company’s financial position or results of operations. The Company has identified situations that require remedial action for which approximately $1.9 million is included in other credits in the Consolidated Balance Sheet as of December 31, 2007.

In 2007, the Company entered into an agreement with Highlands Drilling, LLC (Highlands) for Highlands to provide drilling equipment and services to the Company. These obligations totaled approximately $84.4 million as of December 31, 2007. Operating lease rentals for Highlands, office locations and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $12.0 million in 2007, $6.0 million in 2006 and $4.9 million in 2005. Future lease payments under non-cancelable operating leases as of December 31, 2007 totaled $140.8 million (2008 - $38.9 million, 2009 - $37.0 million, 2010 - $28.6 million, 2011 - $3.5 million, 2012 - $2.5 million and thereafter - $30.3 million).

21. Guarantees

NORESCO Guarantees

In connection with the sale of its NORESCO domestic operations in December 2005, the Company agreed to maintain in place guarantees of certain of NORESCO’s obligations previously issued to the purchasers of NORESCO’s receivables. The guaranteed obligations of NORESCO include certain receivable sales and customer contracts, for which the undiscounted maximum aggregate payments that may be due is approximately $341 million as of December 31, 2007, extending at a decreasing amount for approximately 20 years. In addition, the Company agreed to maintain in place certain outstanding payment and performance bonds, letters of credit and other guarantee obligations supporting NORESCO’s obligations under certain customer contracts, existing leases and other items with an undiscounted maximum exposure to the Company as of December 31, 2007 of approximately $47 million, of which approximately $37 million relates to work already completed under the associated contracts. In addition, approximately $41 million of these guarantee obligations will end or be terminated not later than December 30, 2010.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

In exchange for the Company’s agreement to maintain these guarantee obligations, the purchaser of the NORESCO business and NORESCO agreed, among other things, that NORESCO would fully perform its obligations under each underlying agreement and agreed to reimburse the Company for any loss under the guarantee obligations, provided that the purchaser’s reimbursement obligation will not exceed $6 million in the aggregate and will expire on November 18, 2014.

The Company has determined that the likelihood it will be required to perform on these arrangements is remote and has not recorded any liabilities in its Consolidated Balance Sheet related to these guarantees.

Other Guarantees

In December 2000, the Company entered into a transaction with ANGT by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. ANGT manages the assets and produces, markets, and sells the related natural gas from the properties. Appalachian NPI, LLC (ANPI) contributed cash to ANGT. The assets of ANPI, including its interest in ANGT, collateralize ANPI’s debt. The Company provided ANPI with a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT. This guarantee is subject to certain restrictions that limit the amount of the guarantee to the calculated present value of the project’s future cash flows from the preceding year-end until the termination date of the agreement. The agreement also defines events of default, use of proceeds and demand procedures. The Company has received a market-based fee for providing the guarantee. As of December 31, 2007, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $20 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 and the Company determined that the likelihood it will be required to perform on this arrangement is remote.

On January 15, 2008, Standard & Poor’s Rating Services lowered the Company’s corporate credit and senior unsecured rating to ‘BBB.’ As a result of this downgrade, the terms of this guarantee require the Company to provide a letter of credit in favor of ANPI as security for its obligations under the liquidity reserve guarantee. The amount of this letter of credit requirement is approximately $26.4 million and is expected to decline over time under the terms of the liquidity reserve guarantee.

22. Office Consolidation / Impairment Charges

In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh. The relocation resulted in the early termination of several operating leases and the early retirement of assets and leasehold improvements at several locations. In accordance with SFAS No. 146, the Company recognized a loss of $5.3 million on the early termination of operating leases during 2005 for facilities deemed to have no economic benefit to the Company. The Company also recognized a loss on the impairment of assets of $2.5 million during 2005 in accordance with SFAS No. 144 associated with the office consolidations.

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. The Company reversed approximately $2.4 million of the

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

associated early termination liability for these leases during the second quarter of 2006. Additionally, the Company recorded a $0.5 million reduction in the early termination liability during the second quarter of 2006 resulting from a revision of the amount of estimated cash flows for one of its operating leases.

23. Interim Financial Information (Unaudited)

The following quarterly summary of operating results reflects variations due primarily to the seasonal nature of the Company’s distribution and storage businesses and volatility of natural gas and oil commodity prices.

	March 31		June 30(b)		September 30		December 31
	(Thousands, except per share amounts)
2007 (a)
Operating revenues	$	456,546	$	293,240	$	226,806	$	384,814
Net operating revenues	236,534		176,287		158,084		216,035
Operating income	98,854		61,519		57,368		93,932
Net income	56,618		107,343		32,925		60,597
Earnings per share of common stock:
Net income
Basic	$	0.47	$	0.88	$	0.27	$	0.50
Diluted	$	0.46	$	0.87	$	0.27	$	0.49

	March 31		June 30		September 30		December 31
	(Thousands, except per share amounts)
2006 (a)
Operating revenues	$	430,119	$	251,207	$	232,801	$	353,783
Net operating revenues	221,302		165,094		160,646		216,539
Operating income	127,657		74,119		61,135		109,612
Income from continuing operations	72,359		43,909		31,795		67,962
Income from discontinued operations, net of tax	—		—		—		4,261
Net income	72,359		43,909		31,795		72,223
Earnings per share of common stock:
Income from continuing operations
Basic	$	0.61	$	0.37	$	0.26	$	0.56
Diluted	$	0.59	$	0.36	$	0.26	$	0.56
Income from discontinued operations, net of tax
Basic	$	—	$	—	$	—	$	0.04
Diluted	$	—	$	—	$	—	$	0.03
Net income
Basic	$	0.61	$	0.37	$	0.26	$	0.60
Diluted	$	0.59	$	0.36	$	0.26	$	0.59

(a) The sum of the quarterly data in some cases may not equal the yearly total due to rounding.

(b) Amounts for the quarter ended June 30, 2007, include $119.4 million gain on the sale of assets in the Nora area.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

24. Natural Gas Producing Activities (Unaudited)

The supplementary information summarized below presents the results of natural gas and oil activities for the Equitable Production segment in accordance with SFAS No. 69.

Production Costs

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

	2007		2006		2005
	(Thousands)
At December 31:
Capitalized costs	$	2,029,932	$	1,752,222	$	1,551,677
Accumulated depreciation and depletion	621,881		566,118		518,426
Net capitalized costs	$	1,408,051	$	1,186,104	$	1,033,251
Costs incurred for the years ended December 31:
Property acquisition:
Proved properties	$	24,376	$	—	$	57,500
Unproved properties	—		—		—
Land and leasehold maintenance	751		802		768
Development (a)	297,421		192,578		132,317

(a) Amounts include $59.0 million, $57.2 million and $65.2 million of costs incurred during 2007, 2006 and 2005, respectively, to develop the Company’s proved undeveloped reserves. The Company estimates that its future total development costs will be comprised of a similar percentage of costs incurred to develop the Company’s proved undeveloped reserves.

Results of Operations for Producing Activities

The following table presents the results of operations related to natural gas and oil production for the years ended December 31:

	2007		2006		2005
	(Thousands)
Revenues:
Affiliated	$	14,368	$	14,879	$	11,856
Nonaffiliated	350,028		344,647		373,029
Production costs	61,484		62,016		60,715
Exploration costs	862		802		768
Depreciation, depletion and accretion	62,084		53,471		49,235
Income tax expense	91,187		92,430		104,183
Results of operations from producing activities (excluding corporate overhead)	$	148,779	$	150,807	$	169,984

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

Reserve Information

The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers, which were reviewed by the independent consulting firm of Ryder Scott Company L.P. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. There were no differences between the internally prepared and externally reviewed estimates. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. All of the Company’s proved reserves are in the United States.

	Years Ended December 31,
	2007		2006		2005
	(Millions of Cubic Feet)

Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	2,487,545		2,359,200		2,102,539
Revision of previous estimates	5,818		(20,255	)	288,590
Purchase of natural gas in place	12,185		—		19,159
Sale of natural gas in place	(74,253	)	(1,418	)	(57,700	)
Extensions, discoveries and other additions (a)	320,971		230,716		84,717
Production	(82,401	)	(80,698	)	(78,105	)
End of year	2,669,865		2,487,545		2,359,200
Proved developed reserves:
Beginning of year	1,715,775		1,666,990		1,625,295
End of year	1,746,095		1,715,775		1,666,990

	Years Ended December 31,
	2007		2006		2005
	(Thousands of Bbls)
Oil (b)
Proved developed and undeveloped reserves:
Beginning of year	1,635		1,008		1,019
Revision of previous estimates	551		739		112
Purchase of oil in place	24		—		38
Sale of oil in place	—		—		(53	)
Production	(119	)	(112	)	(108	)
End of year	2,091		1,635		1,008
Proved developed reserves:
Beginning of year	1,635		1,008		1,019
End of year	2,091		1,635		1,008

(a) Includes 122,169 MMcf, 59,374 MMcf and 29,995 MMcf of proved developed reserve extensions, discoveries and other additions during 2007, 2006 and 2005, respectively, which were not previously classified as proved undeveloped. The remaining balance represents additional proved undeveloped reserves.

(b) One Bbl equals approximately 6 MMcf.

During 2007, the Company sold to Pine Mountain Oil and Gas, Inc, (PMOG) a portion of the Company’s interests in certain gas properties in the Nora area totaling approximately 74 Bcf of proved reserves. Also during 2007, the Company purchased an additional working interest of approximately 13.5% in certain gas properties in the Roaring Fork area totaling 12.3 Bcf of proved reserves. During 2007, the Company recorded upward revisions of 9.1 Bcfe to the December 31, 2006 estimates of its reserves due to increased prices and other revisions. The reserves were computed using a $93.28 per Bbl price at December 31, 2007, the Columbia Gas Transmission Corp. 2007 year-end price of $7.030 per Dth, and the Dominion Transmission, Inc. 2007 year-end price of $7.200 per Dth. The

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

company’s 2007 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 321.0 Bcfe exceeded the 2007 production of 83.1 Bcfe.

During 2006, the Company recorded downward revisions of 15.8 Bcfe to the December 31, 2005 estimates of its reserves due to decreased prices and other revisions. The reserves were computed using a $58.40 per Bbl price at December 31, 2006 the Columbia Gas Transmission Corp. 2006 year-end price of $5.625 per Dth, and the Dominion Transmission, Inc. 2006 year-end price of $5.765 per Dth. The Company’s 2006 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 230.7 Bcfe exceeded the 2006 production of 81.4 Bcfe.

In January 2005, the Company purchased the limited partnership interest in ESP for cash of $57.5 million totaling approximately 19.4 Bcfe of proved reserves. In May 2005, the Company sold certain non-core gas properties totaling approximately 58.0 Bcfe of proved reserves. During 2005, the Company recorded upward revisions of 289.3 Bcfe to its December 31, 2004 estimates of its reserves due to increased prices and other revisions. The reserves were computed using a $58.35 per Bbl price at December 31, 2005, the Columbia Gas Transmission Corp. 2005 year-end price of $11.650 per Dth, and the Dominion Transmission, Inc. 2005 year-end price of $11.780 per Dth. The Company’s 2005 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 84.7 Bcfe exceeded the 2005 production of 78.8 Bcfe.

Standard Measure of Discounted Future Cash Flow

Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.

Estimated future net cash flows from natural gas and oil reserves based on selling prices and costs at year-end price levels are as follows at December 31:

	2007			2006			2005
	(Thousands)
Future cash inflows (a)	$	17,546,789		$	13,260,521		$	28,122,308
Future production costs	(3,488,772		)	(2,738,366		)	(3,939,210		)
Future development costs	(1,286,924		)	(989,549		)	(791,539		)
Future net cash flow before income taxes	12,771,093			9,532,606			23,391,559
10% annual discount for estimated timing of cash flows	(8,782,137		)	(6,539,463		)	(15,789,506		)
Discounted future net cash flows before income taxes	3,988,956			2,993,143			7,602,053
Future income tax expenses, discounted at 10% annually	(1,515,803		)	(1,137,394		)	(2,609,025		)
Standardized measure of discounted future net cash flows	$	2,473,153		$	1,855,749		$	4,993,028

(a) The majority of the Company’s production is sold through liquid trading points on interstate pipelines. Accordingly, the price of gas on these pipelines was determined using the year-end prices published in the December 31, 2007 edition of Platts Gas Daily (Columbia Gas Transmission Corp. 2007 year-end price was $7.030/Dth; Dominion Transmission, Inc. 2007 year-end price was $7.200/Dth).

A change in price of $1 per dth for natural gas and $10 per barrel for oil would result in a change in the December 31, 2007 present value of estimated future net cash flow of the Company’s proved reserves of approximately $863 million and $7 million, respectively.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2007

Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31:

	2007			2006			2005
	(Thousands)
Sales and transfers of natural gas and oil produced — net	$	(331,448	)	$	(315,132	)	$	(329,575	)
Net changes in prices, production and development costs	356,045			(5,710,391		)	1,434,642
Extensions, discoveries and improved recovery, less related costs	478,232			276,804			272,419
Development costs incurred	129,753			110,023			76,694
Purchase of minerals in place — net	18,370			—			62,341
Sale of minerals in place — net	(89,085		)	(4,560		)	(129,466		)
Revisions of previous quantity estimates	13,507			(18,977		)	911,986
Accretion of discount	289,942			759,813			457,225
Net change in income taxes	(387,409		)	1,471,631			(868,147		)
Other	139,497			293,510			144,525
Net increase (decrease)	617,404			(3,137,279		)	2,032,644
Beginning of year	1,855,749			4,993,028			2,960,384
End of year	$	2,473,153		$	1,855,749		$	4,993,028

PART IV

Item 15. Exhibits, Financial Statement Schedules

EQUITABLE RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS COVERED

BY REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

Item 15 (a)

1. The following Consolidated Financial Statements of Equitable Resources, Inc. and Subsidiaries are included in Item 8:

		Page Reference

Statements of Consolidated Income for each of the three years in the period ended December 31, 2007		45
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2007		46
Consolidated Balance Sheets as of December 31, 2007 and 2006		47
Statements of Common Stockholders’ Equity for each of the three years in the period ended December 31, 2007		49
Notes to Consolidated Financial Statements		50

2. Schedule for the Years Ended December 31, 2007, 2006 and 2005 included in Part IV:
II — Valuation and Qualifying Accounts and Reserves		91

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

FOR THE THREE YEARS ENDED DECEMBER 31, 2007

Column A	Column B		Column C				Column D		Column E
			Additions		Additions
	Balance at		Charged to		Charged to				Balance at
	Beginning		Costs and		Other		Deductions		End of
Description	of Period		Expenses		Accounts (a)		(b)		Period
	(Thousands)
Allowance for doubtful accounts:

2007	$	20,442	$	353	$	7,041	$	8,007	$	19,829

2006	$	23,329	$	4,715	$	4,589	$	12,191	$	20,442

2005	$	29,836	$	8,273	$	5,176	$	19,956	$	23,329

Note:

(a) CAP surcharge included in residential rates.

(b) Customer accounts written off, less recoveries.

EQT (EQT) 8-KOther Events

Forward-Looking Statements

Item 1. Business

Item 2. Properties

Corporate Reorganization to a Holding Company Structure

Critical Accounting Policies Involving Significant Estimates

Net Fair Value of Third Party Contract (Liabilities) Assets at Period-End