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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009

or

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM ___________ TO __________

COMMISSION FILE NUMBER 1-3551

EQT CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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

 Yes    X    No ___

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

Yes  ___   No   X

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes    X    No ___

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

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

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

Yes  ___   No   X

The aggregate market value of voting stock held by non-affiliates of the registrant

as of June 30, 2009:  $4,569,842,302

The number of shares of common stock outstanding

as of January 31, 2010:  130,929,345

DOCUMENTS INCORPORATED BY REFERENCE

The Company’s definitive proxy statement relating to the annual meeting of shareowners (to be held April 21, 2010) will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2009 and is incorporated by reference in Part III to the extent described therein.

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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 in 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.

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

CAP – 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.  The cost of the CAP is spread across non-CAP customers.

cash flow hedge – a derivative instrument that 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 and benefit of fluctuation between the minimum (floor) price and the maximum (ceiling) price.

continuous accumulations – natural gas and oil resources that are pervasive throughout large areas, have ill-defined boundaries, and typically lack or are unaffected by hydrocarbon-water contacts near the base of the accumulation.

development well – a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

exploratory well – a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

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

feet of pay - footage penetrated by the drill bit into the target formation.

futures contract – an exchange-traded 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.

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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 deposits when forward prices move adversely to a derivative holder'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 iso-butane.

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).

pipeline looping – the building of a pipeline parallel to an existing transmission line utilizing existing right-of-way.

proved reserves – quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

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

proved undeveloped reserves (PUDs) – proved reserves that can be estimated with reasonable certainty 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.

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Glossary of Commonly Used Terms, Abbreviations and Measurements

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

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

working gas – the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility.

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

Abbreviations

Dominion – Dominion Resources, Inc.  When used in the context of a discussion relating to the 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.

ASC - Accounting Standards Codification

CBM – Coalbed Methane

FASB – Financial Accounting Standards Board

FERC – Federal Energy Regulatory Commission

Hope - Hope Gas, Inc.

IRS – Internal Revenue Service

LDC – Local Distribution Company

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

WV PSC – West Virginia Public Service Commission

Measurements

Bbl    = barrel

Btu = one British thermal unit

BBtu  = billion British thermal units

Bcf    = billion cubic feet

Bcfe   = billion cubic feet of natural gas equivalents

Dth  =  million British thermal units

Mcf    = thousand cubic feet

Mcfe   = thousand cubic feet of natural gas equivalents

Mgal   = thousand gallons

MBbl   = thousand barrels

MMBtu  = million British thermal units

MMcf   = million cubic feet

MMcfe  = million cubic feet of natural gas equivalents

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Cautionary Statements

The Company’s finding and development costs are calculated from the production cost and reserve information provided in Footnote 22 to the Consolidated Financial Statements as costs of oil and gas producing activities divided by changes in reserves excluding production.  The Company expects that additional costs will be required to bring proved undeveloped reserves to production.  The Company provides an estimate of future development costs under the standard measure of discounted cash flows in Footnote 22.  The Company believes that finding and development costs is an important analytical measure used within the Company’s industry by investors and peers to evaluate, among other things, the profitability of drilling programs.  However, there are limitations as to the usefulness of this measure.  For instance, this measure may not be calculated consistently across the industry.

Total sales volumes per day at period end is an operational estimate of the daily sales volume on a typical day (excluding curtailments) at the end of the applicable period.

Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended.  Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “forecasts,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe,” “will,” “may” 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 (including the Equitrans Marcellus Expansion Project) and technology, production and sales volumes, reserves, finding and development costs, unit costs, capital expenditures, financing requirements, hedging strategy and tax position.  These statements involve risks and uncertainties that could cause actual results to differ materially from projected results.  Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results.  The Company has based these forward-looking statements on current expectations and assumptions about future events.  While the company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control.  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 this Form 10-K.

Any forward-looking statement applies 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

EQT Corporation (EQT or the Company) conducts its business through three business segments: EQT Production, EQT Midstream and Distribution.  EQT Production is one of the largest natural gas producers in the Appalachian Basin with 4.1 trillion cubic feet of proved reserves across 3.4 million acres as of December 31, 2009.  EQT offers energy products (natural gas, NGLs and a limited amount of crude oil) and services to wholesale and retail customers in the United States via EQT Midstream and Distribution. 

Overall, EQT’s increased production, increased reserves, low cost structure and record results for EQT Midstream and Distribution operations resulted in an outstanding 2009.  Some highlights for the year included:

▪              Sales of produced natural gas of 100.1 Bcfe, a 19% increase over 2008;

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Production

EQT Production has 4.1 Tcfe of proved reserves across three major plays: Huron/Berea, Marcellus and CBM, all located in the Appalachian Basin.  The Company’s strategy is to maximize value by profitably developing its extensive acreage position enabled by a low cost structure.  EQT Production is focused on continuing its significant organic reserve and production growth through its drilling program and believes that it is a technological leader in drilling in low pressure shale.  In particular, the use of air in horizontal drilling has proven to be a cost effective technology which the Company has efficiently deployed in its Huron/Berea play.

The Company’s well profile is generally low-risk wells with long lives, low development and production costs, high energy content natural gas and close proximity to natural gas markets.  Many of these wells have been producing for decades, with several in production since early in the 20th century. 

To date, EQT has focused its highly successful horizontal air drilling program in the Huron/Berea play where the Company has approximately 2.7 million acres and 2.8 Tcfe of proved reserves.  This technology has been used in fractured horizontal single lateral wells, non-fractured horizontal multilateral wells, stacked horizontal wells and extended lateral wells.  EQT is also employing horizontal drilling technology to its 450,000 acres and 1.1 Tcfe of proved reserves in the Marcellus play.

Horizontal wells drilled by the Company over the past five years are as follows:

EQT’s proved reserves increased by 31% in 2009 and by 72% over the past five years while the Company’s cost structure remained at an industry leading level.  EQT’s 2009 3-year finding and development costs are among the lowest in the industry at $0.94 per Mcfe with 2009 costs at a low of $0.68 per Mcfe.  As of December 31, 2009, the Company’s proved reserves, including proved developed and proved undeveloped reserves, and the resource plays to which the reserves relate are as follows:

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*  The Company includes the Lower Huron, Cleveland, Berea sandstone and other Devonian shales, except Marcellus, in its Huron/Berea play.  Also included in the Huron/Berea play is 775 Bcfe of reserves from non-shale formations accessed through vertical wells.

Midstream 

EQT Midstream provides gathering, processing, transmission and storage services to EQT Production and to independent third parties in the Appalachian Basin.  The Company has approximately 10,650 miles of gathering lines and 970 miles of transmission lines.  EQT also owns and operates Kentucky Hydrocarbon, a gas processing facility in Langley, Kentucky.  Through Equitrans L.P. (Equitrans, EQT’s interstate pipeline affiliate), EQT’s transmission and storage system interconnects with five major interstate pipelines: Texas Eastern Transmission, Columbia Gas Transmission, National Fuel Gas Supply, Tennessee Gas Pipeline, and Dominion Transmission.  EQT Midstream’s 14 natural gas storage reservoirs provide approximately 500 MMcf per day of peak delivery capability and 63 Bcf of storage capacity, of which 32 Bcf is working gas.  EQT’s storage reservoirs are clustered in two geographic areas, with eight in northern West Virginia and six in southwestern Pennsylvania.  As of December 31, 2009, EQT Midstream, through Equitrans and EQT Energy, LLC (EQT Energy, EQT’s gas marketing affiliate), leased an additional 8.2 Bcf of contractual storage capacity and 118,834 Dth per day of contractual pipeline capacity from third parties.  In addition, in 2008, EQT Energy executed a binding precedent agreement with Tennessee Gas Pipeline Company (TGP), a wholly owned subsidiary of El Paso Corporation, for a 15-year term that awarded the Company capacity in TGP’s 300-Line expansion project.  EQT Energy’s capacity in the project is expected to be 350,000 Dth per day, giving EQT access to consumer markets from the Gulf Coast to the Mid-Atlantic and the Northeast.

Distribution 

EQT’s regulated natural gas distribution subsidiary, Equitable Gas Company, LLC (Equitable Gas, EQT’s local distribution affiliate), distributes and sells natural gas to residential, commercial and industrial customers in southwestern Pennsylvania, West Virginia and eastern Kentucky.  Equitable Gas also operates a small gathering system in Pennsylvania and provides off-system sales activities which include the purchase and delivery of gas to customers at mutually agreed-upon points on facilities not owned by the Company. 

The Distribution segment’s business strategy is to earn an appropriate return on its asset base through operational efficiency and innovative regulatory mechanisms.  Distribution is focused on enhancing the value of its existing assets by establishing a reputation for excellent customer service, effectively managing capital spending, improving the efficiency of its workforce and continuing to leverage technology throughout its operations.  In 2009, Equitable Gas received approval for a base rate increase in Pennsylvania to recover an increased return on assets placed in service since the previous rate case and to fully recover costs associated with customer assistance programs.

Markets and Customers

Natural Gas Sales:  EQT Production’s produced natural gas is sold to marketers (including EQT Energy), utilities and industrial customers located mainly in the Appalachian area.  No individual customers accounted for more than 10% of revenues in 2009 or 2007.  Sales to one marketer accounted for approximately 13% of revenues for EQT Production for the year ended December 31, 2008.  Natural gas is a commodity and therefore the Company receives market-based pricing.  The market price for natural gas can be volatile as evidenced by the high natural gas prices in early through mid 2008 followed by dramatic decreases later in 2008 and in 2009.  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

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to the differential in the cost to transport gas to customers in the northeastern United States.  The Company 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.

Natural Gas Gathering:  EQT Midstream derives gathering revenues from charges to customers for use of its gathering system in the Appalachian Basin.  The gathering system volumes are transported to three major interstate pipelines: Columbia Gas Transmission, East Tennessee Natural Gas Company and Dominion Transmission.  The gathering system also maintains interconnects with Equitrans.  Maintaining these interconnects provides the Company with access to geographically diverse markets.

Gathering system transportation volumes for 2009 totaled 161,480 BBtu, of which approximately 60% related to gathering for EQT Production, 30% related to third party volumes and 3% related to volumes for other affiliates of the Company.  The remainder related to volumes in which interests were sold by the Company but which the Company continued to operate for a fee.  Revenues from affiliates accounted for almost 80% of 2009 gathering revenues.   

Natural Gas Processing:  The Company processes natural gas in order to extract heavier liquid hydrocarbons (propane, iso-butane, normal butane and natural gasoline) from the natural gas stream, primarily from EQT Production’s produced gas.  NGLs are recovered at EQT’s Kentucky Hydrocarbon facility and transported to a fractionation plant owned by a third party for separation into commercial components.  The third party markets these components and in exchange retains an agreed-upon percentage of NGLs delivered by the Company.  The Company also has contractual processing arrangements whereby the Company sells gas to a third party processor at a weighted average liquids component price. 

While natural gas processing produces independent revenues, the Company’s primary reason for these activities is to comply with the product quality specifications of the pipelines on which the Company’s produced natural gas is transported and sold.  As a result, the Company typically engages in gas processing at locations where its produced gas would not satisfy the downstream interstate pipeline’s gas quality specifications.  Without sufficient processing, the Company’s natural gas production could be interrupted as a result of an inability to achieve required interstate pipeline specifications.  Thus, as the Company’s production continues to grow, access to gas processing capacity must also grow.

Natural Gas Transmission and Storage:  Services offered by EQT Energy include commodity procurement, sales, delivery, risk management and other services.  These operations are executed using Company owned and operated or contracted transmission and underground storage facilities as well as other contractual capacity arrangements with major pipeline and storage service providers in the eastern United States.  EQT Energy uses leased storage capacity and firm transportation capacity, including the Company’s Big Sandy Pipeline capacity, to take advantage of price differentials and arbitrage opportunities.  EQT Energy also engages in risk management and energy trading 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. 

Customers of EQT Midstream’s gas transportation, storage, risk management and related services are 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.  EQT Energy’s commodity procurement, sales, delivery, risk management and other services are offered to natural gas producers and energy consumers including large industrial, utility, commercial and institutional end-users. 

Equitrans’ firm transportation contracts expire between 2010 and 2018.  The Company anticipates that the capacity associated with these expiring contracts will be remarketed or used by affiliates such that the capacity will remain fully subscribed.  In 2009, approximately 80% of transportation volumes and approximately 87% of transportation revenues were from affiliates. 

Natural Gas Distribution: The Company’s Distribution segment provides natural gas distribution services to approximately 275,900 customers, consisting of 257,300 residential customers and 18,600 commercial and

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industrial customers in 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 service areas have a rather static population and economy. 

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).  The gas purchase contracts contain various pricing mechanisms, ranging from fixed prices to several different index-related prices.

Because most of its customers use natural gas for heating purposes, Equitable Gas’ revenues are seasonal, with approximately 74% of calendar year 2009 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.  

Competition

Natural gas producers compete in the acquisition of properties, the search for and development of reserves, the production and sale of natural gas and the securing of labor and equipment required to conduct operations.  Competitors include major oil and gas companies, other independent oil and gas companies and individual producers and operators.  Key competitors for new gathering and processing systems include independent gas gatherers and integrated energy companies.  Natural gas marketing activities compete with numerous other companies offering the same services.  Some of these competitors are affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users.  The Company’s distribution operations face competition from other local distribution companies, alternative fuels and reduced usage among customers as a result of conservation.

Regulation

EQT Production’s natural gas operations are subject to various federal, state, and local laws and regulations, including regulations related to the location of wells; drilling, stimulating and casing of wells; water withdrawal and disbursement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the calculation and disbursement of royalty payments and taxes; the plugging and abandoning of wells; and the gathering of production in certain circumstances.  These regulations may increase the costs of drilling.

EQT Production’s operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or field rule units; the number of wells that may be drilled in a unit; and the unitization or pooling of natural gas properties.  EQT Production’s operating states allow in certain circumstances the forced pooling or integration of tracts to facilitate development and exploration, while in other circumstances it is necessary to rely on voluntary pooling of lands and leases which may make it more difficult to develop natural gas properties.  In addition, state conservation laws generally limit the venting or flaring of natural gas.  The effect of these regulations is to limit the amounts of natural gas we produce from our wells and to limit the number of wells or the locations at which we drill.

EQT Midstream has both regulated and non-regulated operations.  The regulated activities consist of 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.  Equitrans’ rates and operations are subject to regulation by the FERC.  The 2006 FERC rate case settlement allowed Equitrans, among other things, 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.  The Company has continued to utilize the surcharge mechanism each year to recover costs incurred in connection with its Pipeline Safety Program.  Under the terms of the 2006 settlement, Equitrans was prohibited from seeking new base

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transmission and storage rates prior to June 1, 2009 and is prohibited from seeking new gathering base rates prior to November 1, 2010.  In 2008, the Big Sandy Pipeline was placed in service in eastern Kentucky. 

Equitable Gas’ distribution rates, terms of service and contracts with affiliates are subject to comprehensive regulation by the PA PUC and the WV PSC.  In addition, the issuance of securities by Equitable Gas is subject to regulation by the PA PUC.  The field line sales rates in Kentucky are subject to rate regulation by the Kentucky Public Service Commission. 

Equitable Gas must usually seek the approval of one or more of its regulators prior to changing its rates.  Currently, Equitable Gas passes through to its regulated customers the cost of its purchased gas and transportation activities.  Equitable Gas is allowed to recover a return in addition to the costs of its distribution and gathering delivery activities.  However, Equitable Gas’ regulators do not guarantee recovery and may require that certain costs of operation be recovered over an extended term.  On February 26, 2009, the PA PUC approved a settlement between Equitable Gas and the active parties to the filing for a base rate case increase in Pennsylvania.  The Company implemented the new base rates upon approval of the settlement.  On October 29, 2009, Equitable Gas filed a request with the WV PSC to increase the rates it charges its customers for delivery of natural gas in West Virginia.  It is the first delivery rate increase that Equitable Gas has requested in West Virginia since 1991.  The rate case proceedings are expected to be resolved no later than the third quarter of 2010. 

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 customer assistance program (CAP).  Effective with the approval of the Pennsylvania rate case settlement, the Company received approval to implement an increased CAP surcharge, for recovery of its costs for assisting low-income customers with paying their gas bills and will receive an annual reconciliation of CAP costs to ensure complete recovery of these costs. 

Equitable Gas 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.

Employees

The Company and its subsidiaries had approximately 1,800 employees at the end of 2009.

Holding Company Reorganization

On June 30, 2008, the former Equitable Resources, Inc. (Old EQT) entered into and completed an Agreement and Plan of Merger (the Plan) under which Old EQT reorganized into a holding company structure such that a newly formed Pennsylvania corporation, also named Equitable Resources, Inc. (New EQT), became the publicly traded holding company of Old EQT and its subsidiaries.  The primary purpose of this reorganization (the Reorganization) was to separate Old EQT’s state-regulated distribution operations into a new subsidiary in order to better segregate its regulated and unregulated businesses and improve overall financing flexibility.  To effect the Reorganization, Old EQT formed New EQT, a wholly-owned subsidiary, and New EQT, in turn, formed EGC Merger Co., a Pennsylvania corporation owned solely by New EQT (MergerSub).  Under the Plan, MergerSub merged with and into Old EQT with Old EQT surviving (the Merger).  The Merger resulted in Old EQT becoming a direct, wholly-owned subsidiary of New EQT.  New EQT changed its name to EQT Corporation effective February 9, 2009.  Throughout this Annual Report, references to EQT, EQT Corporation and the Company refer collectively to New EQT and its consolidated subsidiaries.

Availability of Reports

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 the date they are filed with,

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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.  

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 2009, 2008 and 2007. 

Financial Information About Segments

In January 2008, the Company announced a change in organizational structure 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 segment disclosures and discussions contained in this report have been reclassified to reflect all periods presented under the current organizational structure. 

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

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Item 1A.  Risk Factors

Risks Relating to Our Business

In addition to the other information contained in this Form 10-K, the following risk factors should be considered in evaluating our business and future prospects.  Please note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations.  If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.

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

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

Lower natural gas prices may result in decreases in the revenue, margin and cash flow for each of our businesses, a reduction in the construction of new transportation capacity and downward adjustments to the value of our estimated proved reserves which may cause us to incur non-cash charges to earnings.  A reduction in cash flow will reduce our funds available for capital expenditures and, correspondingly, our opportunities for growth.  We are also exposed to the risk of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in derivative contracts with a positive fair value. 

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

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

Our operations are regulated extensively at the federal, state and local levels.  Laws, regulations and other legal requirements have increased the cost to plan, design, drill, install, operate and abandon wells, gathering systems, pipelines and distribution systems.  Environment, health and safety legal requirements govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, restoration of drilling properties after drilling is completed, pipeline safety and work practices related to employee health and safety.  Compliance with the laws, regulations and other legal requirements applicable to our businesses may be costly. These requirements could subject us to liability for personal injuries, property damage and other damages.  Our failure to comply with the laws, regulations and other legal requirements applicable to our businesses, even if as a result of factors beyond our control, may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.   

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The rates charged to customers by our gathering, transportation, storage and distribution businesses are, in many cases, subject to state or federal regulation.  The agencies that regulate our rates may prohibit us from realizing a level of return which we believe is appropriate.  These restrictions may take the form of imputed revenue credits, cost disallowances (including purchased gas cost recoveries) and/or expense deferrals.  Additionally, we may be required to provide additional assistance to low income residential customers to help pay their bills without the ability to recover some or all of the additional assistance in rates.

Laws, regulations and other legal requirements are constantly changing and implementation of compliant processes in response to such changes could be costly and time consuming.  For instance, the U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of burning natural gas). Such restrictions may result in additional compliance obligations with respect to, or taxes on, and the release, capture and use of greenhouse gases that could have an adverse effect on our operations. Changes to well fracturing or waste water regulations or existing legal requirements could also have a significant effect on our costs of operations and competitive position. 

The rates of federal, state and local taxes applicable to the industries in which we operate, including production taxes paid by EQT Production, which often fluctuate, could be increased by the various taxing authorities.  In addition, the tax laws, rules and regulations that affect our business, such as the imposition of a new severance tax (a tax on the extraction of natural resources) in states in which we produce gas, could change. Any such increase or change could adversely impact our cash flows and profitability.

Strategic determinations regarding the allocation of capital and other resources in the current economic environment are challenging and our failure to appropriately allocate capital and resources among our businesses may adversely affect our financial condition and reduce our growth rate. 

In developing our 2010 business plan, we considered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, midstream infrastructure, distribution infrastructure, corporate items and other alternatives.  We also considered our likely sources of capital.  Notwithstanding the determinations made in the development of our 2010 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we don’t optimize our capital investment and capital raising opportunities and the use of our other resources, our financial condition and growth rate may be adversely affected.

Global financial challenges may adversely affect our business and financial condition in ways that we currently cannot predict.  Downgrades to our credit ratings could increase our costs of borrowing adversely affecting our business, results of operations and liquidity.

We rely upon access to both short-term bank and money markets and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by the cash flow from operations.  Challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition and we may face challenges if conditions in the financial markets do not improve.  Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could adversely affect the collectability of our trade receivables.  Market conditions could cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection.  Continuing challenges in the economy could lead to reduced demand for natural gas which could have a negative impact on our revenues and our credit ratings.  

Any downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to raise capital through the issuance of debt or equity securities or other borrowing arrangements, which could adversely affect our business, results of operations and liquidity.  We cannot be sure that our current ratings will remain in effect for any given period of time or that our rating will not be lowered or withdrawn entirely by a rating agency.  An increase in the level of our indebtedness in the future may result in a downgrade in the ratings that are assigned to our debt.  Any downgrade in our ratings could result in an increase in our borrowing costs, which would diminish financial results.

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

Our delivery of gas depends upon the availability of adequate transportation infrastructure.  The Company’s investment in midstream infrastructure is intended to address a lack of capacity on, and access to, existing gathering and transportation pipelines as well as processing adjacent to and curtailments on such pipelines.  The lack of midstream infrastructure is particularly acute in the geographic area in which the Marcellus shale is being developed.  Our infrastructure development and maintenance programs can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, materials, and qualified contractors and work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology, compliance by third parties with their contractual obligations to us and other factors.  We also deliver to and are served by third party gas gathering, transportation, processing and storage facilities which are limited in number and geographically concentrated.  An extended interruption of access to or service from these facilities could result in adverse consequences to us.  In addition, some of our third party contracts may involve significant financial commitments on our part and may make us dependent upon others to get our produced natural gas to market. 

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

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

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

Our future success depends upon our ability to develop additional gas reserves that are economically recoverable and to optimize existing well production, and our failure to do so may reduce our earnings.  Our drilling and subsequent maintenance of wells can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, leases, rigs and a qualified work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology and other factors.  Drilling for natural gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit.  Additionally, a failure to effectively and efficiently operate existing wells may cause production volumes to fall short of our projections.  Without continued successful development or acquisition activities, together with effective operation of existing wells, our reserves and revenues will decline as a result of our current reserves being depleted by production.

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

Our goal of sustaining long-term growth for our production business is contingent upon our ability to identify production opportunities based on market conditions.  Our decision to drill a prospect is subject to a number of factors which may alter our drilling schedule or our plans to drill at all. We may have difficulty drilling all of the wells before the lease term expires which could result in the loss of certain leasehold rights or we could drill wells in locations where we do not have the necessary infrastructure to deliver the gas to market.  Successfully identifying production opportunities involves a high degree of business experience, knowledge and careful evaluation of potential opportunities, along with subjective judgments and assumptions which may prove to be incorrect.  Our recent addition of exploration projects increases the risks inherent in our natural gas activities.  Specifically, seismic data is subject to interpretation and may not accurately identify the presence of natural gas, which could adversely affect the results of our operations. Because we have a limited operating history in certain exploratory areas, our

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future operating results are difficult to forecast, and our failure to sustain high growth rates in the future could adversely affect the market price of our common stock.

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

Item 1B.     Unresolved Staff Comments

               None.

Item 2.        Properties

Principal facilities are owned by the Company’s business segments, or in the case of certain office locations,  warehouse buildings and equipment, leased.  The majority of the Company’s properties are located on or under (1) 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 or (2) public highways under franchises or permits from various governmental authorities.  The Company’s facilities are generally well maintained and, where appropriate, are replaced or expanded to meet operating requirements.

EQT Production.  EQT Production’s properties are located primarily in Kentucky, West Virginia, Virginia and Pennsylvania.  This segment currently has approximately 3.4 million gross acres (approximately 67% of which are 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, 2009, the Company estimated its total proved reserves to be 4,068 Bcfe, consisting of proved developed producing reserves of 1,912 Bcfe, proved developed non-producing reserves of 161 Bcfe and proved undeveloped reserves of 1,995 Bcfe. All of the Company’s reserves reside in continuous accumulations. The Company’s estimate of proved natural gas and oil reserves are prepared by Company engineers.  The engineer primarily responsible for the technical aspects of the reserves audit has received a bachelor's degree in Engineering from the Pennsylvania State University and has ten years of experience in the oil and gas industry.   To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate, and cost assumptions used in the economic model to determine the reserves.  Additionally, production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems, and the reserve roll forward between prior year reserves and current year reserves is reviewed by senior management.  The estimates of proved natural gas and oil reserves are audited by the independent consulting firm of Ryder Scott Company L.P., who is hired by the Company’s management.  Since 1937, Ryder Scott Company L.P. has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.  Ryder Scott Company L.P.’s audit report has been filed herewith as Exhibit 99.01.  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 22 (unaudited) to the Consolidated Financial Statements.

Natural Gas and Crude Oil Production: 

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Average per unit production cost, including severance taxes, of natural gas and crude oil during 2009, 2008 and 2007 was $0.585, $0.871 and $0.740 per Mcfe, respectively.

Certain lease acquisition agreements require the Company to drill 2 Marcellus or deeper wells and 6 wells drilled to 250’ above the top of the Tully formation or deeper in 2010, 5 wells drilled to 250’ above the top of the Tully formation or deeper plus 4 wells to any depth or formation in 2011, and 5 wells drilled to 250’ above the top of the Tully formation or deeper plus 2 wells to any depth or formation in 2012; each of these wells must be drilled within specified acreage.  The Company intends to satisfy these requirements as part of its Marcellus development program.  As of December 31, 2009, leases associated with 9,975 gross undeveloped acres expire in 2010 if they are not renewed; however, the Company has an active lease renewal program.  

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

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Selected data by state (at December 31, 2009 unless otherwise noted):

During 2009, the Company converted 65 Bcfe of proved undeveloped reserves to proved developed reserves and 315 Bcfe of non-proved undeveloped reserves to proved developed reserves.  The Company anticipates spending $2.9 billion to convert proved undeveloped reserves to proved developed reserves over the next 5 years.  Capital expenditures for drilling and development totaled $717 million during 2009.  Proved reserves increased primarily in the Marcellus and Huron/Berea plays as a result of the Company’s 2009 drilling program.  In addition, the application of new SEC oil and gas reporting rules permitted the booking of PUDs in locations more than one offset location away from existing wells.  Partially offsetting these reserve additions, EQT also reported a reduction of CBM/other reserves as a result of removing previously booked vertical locations.

The Company’s 2009 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 1,159 Bcfe exceeded the 2009 production of 104.9 Bcfe.  Of this increase, approximately 715 Bcfe was attributable to drilling in 2009 that would have qualified as reserve extensions, discoveries and other additions under the previous

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rules, including approximately 400 Bcfe related to offset locations from wells drilled in 2009.  The remaining additions are attributable to the SEC’s expanded definition of proved reserves to include reserves based on reasonable certainty, partially offset by removing reserves that were previously recorded for future vertical wells.

During 2009, the Company recorded downward revisions of 94.8 Bcfe to the December 31, 2008 estimate of proved reserves due to decreased prices and other revisions.  The new SEC oil and gas reporting rules modified the definition of proved reserves as well as the price used in the calculation which resulted in approximately 55 Bcfe of revision of previous estimates.  The reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2009.  Absent the effect of the new SEC oil and gas reporting rule, the price impact would have been minimal as prices as of December 31, 2009 only decreased approximately $0.06 from December 31, 2008.

Wells located in Kentucky are primarily in shale formations with depths ranging from 2,500 feet to 6,000 feet and average spacing of 100 acres.  Wells located in West Virginia are primarily in tight sands and shale 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.  Horizontal wells in both northern and southern West Virginia are drilled on 100 acre spacing.  Wells located in Virginia are primarily in coalbed methane formations with depths ranging from 2,000 feet to 3,000 feet and average spacing of 60 acres and in tight sands and shale formations at depths of 3,000 to 6,500 feet on 100 acre spacing.  Wells located in Pennsylvania are primarily in shale formations with depths ranging from 7,000 feet to 8,000 feet and average spacing of 100 acres.  

During 2008, the Company drilled its first exploratory vertical Utica well.  During 2009, the Company made the decision to plug back the well and to convert the well to a horizontal Marcellus well in 2010. As a result, the Company wrote-off $2.9 million of incremental exploratory costs related to drilling down to the Utica formation. As of December 31, 2009, $5.0 million of well costs remain capitalized for the future horizontal Marcellus well, pending successful completion.

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

EQT Midstream. EQT Midstream owns or operates approximately 10,650 miles of gathering line and 243 compressor units comprising 121 compressor stations with approximately 249,000 horsepower of installed capacity, as well as other general property and equipment. 

Substantially all of the gathering operations’ sales volumes are delivered to several large interstate pipelines on which the Company and other customers lease capacity.  These pipelines are subject to periodic curtailments for maintenance and repairs.

The Midstream business also owns a hydrocarbon processing plant and gas compression facilities located in Langley, Kentucky. 

EQT Midstream also owns and operates regulated underground storage and transmission facilities in Pennsylvania, West Virginia and Kentucky.  These operations consist of approximately 970 miles of regulated transmission and storage lines with approximately 35,000 horsepower of installed capacity and interconnections with five major interstate pipelines.  The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania.  The completion of the Big Sandy Pipeline in 2008 added 68 miles of transmission line and 9,000 horsepower 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 geographically clustered, with eight in northern West Virginia and six in southwestern Pennsylvania.

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

Equitable Distribution.  This segment owns and operates natural gas distribution and gathering facilities as well as other general property and equipment in western Pennsylvania, West Virginia and Kentucky.  The distribution operations consist of approximately 4,000 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.  In 2008, the Company entered into an agreement with Liberty Avenue Holdings, LLC to lease office space in Pittsburgh, Pennsylvania for the Company’s new corporate headquarters. During the third quarter of 2009, the Company completed the relocation of its corporate headquarters and certain other operations to downtown Pittsburgh.

Item 3.       Legal Proceedings

Kay Company, LLC et al v. EQT Production Company et al, U.S. District Court, Southern District of West Virginia

Several West Virginia lessors claimed in a suit filed on July 31, 2006 that EQT Production Company had underpaid royalties on gas produced and marketed from leases. The suit sought compensatory and punitive damages, an accounting and other relief.  The plaintiffs later amended their complaint to name EQT as an additional defendant. The Company has settled the litigation. The settlement covers all of the Company’s lessors in West Virginia who have not opted out of the settlement class.  The Court has entered an order preliminarily approving the settlement.   A Formal Fairness Hearing was held on January 20, 2010.  The Company is waiting for entry of an order giving final approval of the settlement. The Company believes the reserve established for this litigation is sufficient.

In addition to the claim disclosed above, in the ordinary course of business various other legal and regulatory 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 it believes to be appropriate for other pending matters and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any other matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.

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

No matters were submitted to a vote of the Company’s security holders during the last quarter of its fiscal year ended December 31, 2009.

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Executive Officers of the Registrant (as of February 18, 2010)

____________________

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

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As previously announced, Murry S. Gerber, Chairman and Chief Executive Officer, will step aside from his duties as Chief Executive Officer following the Company’s annual meeting of shareholders on April 21, 2010.  David L. Porges, currently EQT’s President and Chief Operating Officer, will become Chief Executive Officer.  To insure a smooth transition, Mr. Gerber will remain with EQT as Executive Chairman through EQT’s 2011 annual meeting of shareholders.

PART II

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

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

As of February 10, 2010, there were 3,519 shareholders of record of the Company’s common stock.

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

The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended December 31, 2009:

(a)          Comprised solely of Company-directed purchases made by the Company’s 401(k) plans.

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Stock Performance Graph

The following graph compares the most recent five-year cumulative total return attained by shareholders on EQT Corporation’s common stock with the cumulative total returns of the S&P 500 index and a customized peer group of twenty companies (the “Self-Constructed Peer Group”) whose individual companies are listed in footnote (1) below.  An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2004 in the Company’s common stock, in the S&P 500 index, and in the peer group.  Relative performance is tracked through December 31, 2009.

(1)          The twenty companies included in the self constructed peer group are: Atlas Energy Resources, LLC, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, CNX Gas Corporation, El Paso Corporation, Enbridge Inc., Energen Corporation, MarkWest Energy Partners, L.P., MDU Resources Group, Inc, National Fuel Gas Company, ONEOK, Inc, Penn Virginia Corporation, Questar Corporation, Range Resources Corporation, Sempra Energy, Southern Union Company, Southwestern Energy Company, Spectra Energy Corp., Transcanada Corp. and The Williams Companies, Inc.  Atlas Energy Resources LLC was acquired during 2009 and is included in the calculation from December 31, 2004 through December 31, 2008, at which time it is removed from the peer group calculation.

See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information relating to compensation plans under which the Company’s securities are authorized for issuance.

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Item 6.    Selected Financial Data

(a)          All 2005 per share amounts have been adjusted for the two-for-one stock split affected on September 1, 2005.

See Item 1A, “Risk Factors” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 5 and 6 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

In 2009 EQT achieved record results.  Highlights for 2009 included:

·      Record annual sales of produced natural gas of 100.1 Bcfe, more than 19 % higher than 2008;

·      Drilled 800th horizontal Huron/Berea well, approximately 27% of sales were from horizontal Huron/Berea wells;

·      Drilled 46 horizontal Marcellus wells;

·      Record EQT Midstream throughput and operating income; and

·      Record Distribution operating income of $78.9 million, 32% higher than 2008.

EQT’s consolidated income from continuing operations for 2009 was $156.9 million, $1.19 per diluted share, compared with $255.6 million, $2.00 per diluted share, for 2008 and $257.5 million, $2.10 per diluted share, for 2007.

The $98.7 million decrease in income from continuing operations from 2008 to 2009 was primarily attributable  to a lower average well-head sales price, increased incentive compensation expense, increased depletion expense, and higher interest expense partially offset by increased gas sales volumes at EQT Production, increased gathering volumes and rate, Big Sandy pipeline activity and NGLs sold at EQT Midstream and an increase in base rates in the Distribution segment.     

Incentive compensation expense increased from 2008 to 2009 as a result of expenses related to the Company’s 2009 Shareholder Value Plan recorded in 2009 and a reversal of previously recorded expense on the Company’s 2005 Executive Performance Incentive Program in 2008 primarily as a result of the decline in the Company’s stock price in 2008.  Incentive compensation is primarily reported in selling, general and administrative expenses in the Statements of Consolidated Income.  A significant portion of the 2009 expense and 2008 reversal are reported as unallocated expenses in the information by business segment in Note 2 of the Company’s Consolidated Financial Statements. 

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Interest expense increased from 2008 to 2009 primarily due to the Company’s continued investment in drilling and midstream infrastructure during 2009.  This investment was partially funded by the issuance of $700 million of 8.125% notes in May 2009. 

The $1.9 million decrease in income from continuing operations from 2007 to 2008 reflects an increase in operating income of $153.1 million which was more than offset by the absence of a 2007 pre-tax gain of $126.1 million on the sale of assets in the Nora area, higher 2008 interest and income taxes and a 2008 other than temporary impairment loss on available for sale securities.      

Operating income for 2008 was impacted by decreased incentive compensation expense, increased production revenues due to higher average well-head sales prices and significantly higher volumes, increased gathering and transmission revenues due to higher rates and volumes, and the absence of 2007 transaction costs associated with the terminated Peoples and Hope acquisition.  The decreased incentive compensation expense was the result of the reversal of previously recorded expense on the Company’s 2005 Executive Performance Incentive Program partially offset by increased short-term incentive compensation.  These items were partially offset by increased depletion, depreciation and amortization, increased operating and administrative expenses and the impact of the May 2007 asset sales.  

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 expenses (income) and administrative expenses totaling $62.2 million, ($17.4) million and $65.3 million in 2009, 2008 and 2007, respectively, were not allocated to business segments.  The unallocated expense in 2009 and 2007 primarily relates to performance-related incentive expenses, while the unallocated income in 2008 primarily relates to the reversal of previously recorded performance-related incentive expenses.

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.  EQT’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 EQT’s segments without being obscured by these items for the other segments or by the effects of corporate allocations.  In addition, management uses these measures for budget planning purposes.

EQT Production

Overview

Driven by aggressive horizontal air drilling in the Huron/Berea play, EQT Production achieved sales of produced natural gas of 100.1 Bcfe in 2009, representing a more than 19% increase.  Also, unit LOE, excluding production taxes, decreased 14% in 2009 to $0.30 per Mcfe.

EQT Production’s strategy is to maximize value by profitably developing the Company’s extensive acreage position through organic growth enabled by a low cost structure.  The Company is focused on continuing its significant organic reserve and production growth through its drilling program and believes that it is a technological leader in drilling in low pressure shale.  In particular, the use of air in horizontal drilling has proven to be a cost effective technology which the Company has efficiently deployed to various geological formations in the

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Appalachian Basin mountain terrain and which may be deployed to other Company assets in the Appalachian Basin to maximize production.  In 2009, extended laterals utilizing this technology produced a 6,700 foot lateral with 6,000 feet of pay, essentially doubling the typical horizontal well which is a 3,700 foot with 3,000 feet of pay.  Based on these favorable preliminary results, the Company is in the process of incorporating extended lateral wells into its preferred standard operating procedures for the Huron/Berea play.  The Company expects to access significantly more reserves through the extended lateral drilling procedures for less than a proportional amount of the development costs.

In 2009, the Company drilled 434 gross wells in the Huron/Berea play.  Total proved reserves in the Huron/Berea play (including vertical non-shale formations) are 2.8 Tcfe.  In the Marcellus play, the Company drilled 50 gross wells during 2009.  Total proved reserves in the Marcellus play increased 1,278% to 1.1 Tcfe.  Proved reserves increased in the Marcellus and Huron/Berea plays as a result of the Company’s 2009 drilling program.  In addition, the application of new SEC oil and gas reporting rules permitted the booking of PUDs in locations more than one offset location away from existing wells.  The Company drilled 218 gross CBM wells in 2009.  The CBM play had total proved reserves of 0.2 Tcfe at December 31, 2009, down 6% from 2008 as a result of the implementation of the new SEC oil and gas reporting rules.  See Item 2 “Properties” for additional discussion of the Company’s proved reserves and the impact of the new SEC oil and gas reporting rules.  Sales of produced natural gas in 2009 from the Huron/Berea, Marcellus and CBM plays were 84.9 Bcfe, 2.9 Bcfe and 12.3 Bcfe, respectively.   

EQT Production’s revenues for 2009 decreased approximately 16% compared to 2008 revenues.  The average well-head sales price decreased approximately 30%, as a result of decreased commodity market prices offset by slightly higher hedge prices year-over-year.  Gas sales volumes increased more than 19% from 2008 primarily as a result of increased production from the 2008 and 2009 drilling programs partially offset by the normal production decline in the Company’s producing wells.   

Operating expenses at EQT Production included an $8.8 million increase in the Company’s exploration program. The increase in exploration expense is primarily a result of the Company’s initiative to explore additional reserve opportunities in various exploration plays on its legacy acreage position with the purchase and interpretation of seismic data for unproved properties.  In addition, in 2009, EQT Production recorded a $2.9 million impairment charge associated with the write-off of the Utica exploratory well when the Company made the decision to abandon the Utica formation and plug back the well to the Marcellus formation. Excluding exploration expenses, 2009 operating expenses increased 10% primarily due to higher depletion resulting from increased drilling investments.

See Investing Activities in Capital Resources and Liquidity for a discussion of capital expenditures.

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Results of Operations