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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, 2011

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, 2011:  $5,389,512,917

The number of shares of common stock outstanding

as of January 31, 2012: 149,490,315

DOCUMENTS INCORPORATED BY REFERENCE

The Company’s definitive proxy statement relating to the annual meeting of shareowners (to be held April 18, 2012) will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2011 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.  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, transportation capacity availability 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 underlying transaction whereby the gains (losses) on the derivative are anticipated to offset the losses (gains) on the forecasted underlying transaction.

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.

margin call – a demand for additional margin deposits when forward prices move adversely to a derivative holder’s position.

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

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).

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

ASC - Accounting Standards Codification

CBM – Coalbed Methane

CFTC – Commodity Futures Trading Commission

FASB – Financial Accounting Standards Board

FERC – Federal Energy Regulatory Commission

IRS – Internal Revenue Service

LDC – Local Distribution Company

NGV – Natural Gas Vehicle

NYMEX – New York Mercantile Exchange

OTC – Over the Counter

PA PUC – Pennsylvania Public Utility Commission

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, with one barrel of oil being equivalent to 6,000 cubic feet of gas

Dth  =  million British thermal units

Mcf    = thousand cubic feet

Mcfe   = thousand cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas

Mgal   = thousand gallons

MBbl   = thousand barrels

MMBtu  = million British thermal units

MMcf   = million cubic feet

MMcfe  = million cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas

Tcfe = trillion cubic feet of natural gas equivalents

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Cautionary Statements

Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended.  Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “could,” “would,” “will,” “may,” “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 the Company’s strategy to develop its Marcellus and other reserves; drilling plans and programs (including the number, type, feet of pay and location of wells to be drilled and the availability of capital to complete these plans and programs); production and sales volumes; gathering and transmission growth and volumes; infrastructure programs (including the Sunrise Pipeline project and the gathering expansion projects); technology (including drilling and fracturing techniques); transactions (including asset sales, joint ventures or other transactions involving the Company’s assets); conversion of its automobile fleet and certain rigs to natural gas; revenue projections; reserves (including estimated reserve life, operating costs; well costs; unit costs; capital expenditures; estimates of cost to develop wells; financing requirements and availability; hedging strategy; the effects of government regulation and tax position.  The forward-looking statements in this Annual Report on Form 10-K 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 Annual Report on Form 10-K.

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.

In reviewing any agreements incorporated by reference in or filed with Annual Report or this Form 10-K, please remember such agreements are included to provide information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about the Company. The agreements may contain representations and warranties by the Company, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties should those statements prove to be inaccurate. The representations and warranties were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments.  Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.

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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 5.4 Tcfe of proved reserves across 3.5 million acres, including approximately 530,000 acres in the Marcellus play, as of December 31, 2011.  EQT Midstream provides gathering, transmission and storage services for the Company’s produced gas and to independent third parties in the Appalachian Basin. Until February 1, 2011 when the company sold the Kentucky Hydrocarbon gas processing facility in Langley, Kentucky (Langley), EQT Midstream also provided processing services. Distribution, through its regulated natural gas distribution subsidiary, Equitable Gas Company, LLC (Equitable Gas), distributes and sells natural gas to residential, commercial and industrial customers in southwestern Pennsylvania, West Virginia and eastern Kentucky, operates a small gathering system in Pennsylvania and provides off-system sales activities which include the purchase and delivery of gas to customers.

EQT has 5.4 Tcfe of proved reserves across three major plays: Marcellus, Huron and CBM, all in the Appalachian Basin, including 3.4 Tcfe in the Marcellus.  The Company’s strategy is to maximize value by profitably developing its undeveloped Marcellus reserves.  EQT believes that it is a technological leader in drilling shale in the Appalachian Basin.

EQT’s proved Marcellus reserves increased by 19% in 2011, while the Company’s cost structure remained at an industry leading level.  As of December 31, 2011, the Company’s proved reserves, including proved developed and proved undeveloped reserves, and the resource plays to which the reserves relate are as follows:

* The Company includes the Lower Huron, Cleveland, Berea sandstone and other Devonian shales, except the Marcellus, in its Huron play. Also included in the Huron play is 713 Bcfe of reserves from non-shale formations accessed through vertical wells.

Assuming that future annual production from these reserves is consistent with 2011, the remaining reserve life of the Company’s total proved reserves as calculated by dividing total proved reserves by current year produced volumes is 27 years.

The Company’s natural gas wells are generally low-risk with long lives and low development and production costs.  The gas produced from many of these wells has a high energy content and is within close proximity to natural gas markets.  Most of the Company’s Huron well production and some of its Marcellus well production is liquids-rich.

In the Marcellus, EQT applies extended lateral horizontal drilling technology to its approximate 530,000 acres and 3.4 Tcfe of proved reserves.  EQT continues to be a leader in the use of new drilling and completion technology which increases lateral length drilled and reserves per foot of pay.  Marcellus wells have target depths ranging from 7,000 to 8,000 feet with an average lateral spacing of 1,000 feet.

In light of lower natural gas prices and the resultant reduction in projected cash flow, the Company decided in January 2012 to suspend development in the Huron  indefinitely in favor of investing in its higher return Marcellus play.  A similar decision was made in December 2010, when the Company suspended the development of its CBM play in Virginia.  Proved reserves from these two plays were 33% and 3%, respectively, of total proved reserves at

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December 31, 2011.  The Company expects to continue to produce from existing wells in the Huron and CBM plays, but their contribution to the Company’s total production sales volumes will gradually decline as the Company focuses all new drilling in the Marcellus.  The Huron and CBM plays accounted for approximately 58% of production sales volumes in 2011 and are expected to account for approximately 40% of production sales volumes in 2012.

The Company invested approximately $938 million on well development (primarily drilling) in 2011. Production sales volumes increased 44% in 2011 over 2010.  Over the past three years, the Company’s wells drilled and related capital expenditures for well development were:

In May 2011, the Company purchased all of the outstanding net profits interest (NPI) from the other investor (ANPI) in a trust in which EQT owned an existing interest (the ANPI transaction).  This transaction resulted in an increase in oil and gas properties of $140.6 million, assumed debt and other liabilities of $92.6 million and a pre-tax gain of $10.1 million, recorded in other income, on the revaluation of the previously existing equity investment in the trust to fair value.

To support the growth of the Marcellus play, the Company is increasing its available gathering and transmission system capacity in the region. During 2011, the Company completed construction of the Callisto compressor station which added 14,205 horsepower of compression and 150 MMcfe per day of delivery capacity to the Equitrans L.P. (Equitrans, EQT’s FERC-regulated transmission, storage and gathering system) gathering system for EQT production in Greene County, Pennsylvania.  The Company has Marcellus gathering capacity of 440 MMcfe per day in Pennsylvania and 85 MMcfe per day in West Virginia.  The Company has approximately 10,450 miles of gathering lines.

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The Company’s transmission and storage system includes a FERC-regulated interstate pipeline system of approximately 700 miles that connects to five interstate pipelines and multiple distribution companies and is supported by 14 associated natural gas storage reservoirs with approximately 400 MMcf per day of peak delivery capability and 32 Bcf of working gas capacity. EQT’s storage reservoirs are clustered in two geographic areas connected to its Equitrans pipeline, with eight in northern West Virginia and six in southwestern Pennsylvania.

Through EQT’s gas marketing subsidiary, EQT Energy, LLC, (EQT Energy), the Company provides optimization of capacity and storage assets, NGL sales and gas sales to commercial and industrial customers within its operational footprint through 6.5 Bcf of leased storage-related assets and approximately 880,000 Dth per day of  third party contractual pipeline capacity.

On February 1, 2011, EQT Midstream sold Langley and the associated NGL pipeline to MarkWest Energy Partners, L.P. (MarkWest) for $230 million subject to customary purchase price adjustments. The Company realized a pre-tax gain of $22.8 million on this sale.  In conjunction with the closing of the sale of the Langley plant, EQT executed a long-term agreement with MarkWest to obtain processing services for its Kentucky Huron gas and extended its existing agreement with MarkWest for NGL transportation, fractionation and marketing services until 2022.  MarkWest has commenced construction of a new cryogenic processing plant to expand the Langley cryogenic processing capacity which is expected to be on-line in 2012.  In addition, MarkWest has agreed to construct a natural gas processing facility in Logansport, WV.  The Logansport facility is expected to be on-line in 2012.  MarkWest will then provide natural gas processing services for EQT’s Marcellus production in north central West Virginia, as well as NGL transportation, fractionation and marketing services.  The Sunrise Pipeline project described below will connect this facility to Equitrans and its interconnects with five major interstate pipelines.

On July 1, 2011, the Company sold the Big Sandy Pipeline (Big Sandy) to Spectra Energy Partners, LP for $390 million.  Big Sandy is a natural gas pipeline regulated by the FERC which transports natural gas from the Langley natural gas processing complex to interconnects with unaffiliated pipelines leading to the mid-Atlantic and Northeast markets. In conjunction with this transaction, the Company realized a pre-tax gain of $180.1 million.

Capital expenditures for well development (primarily drilling) in 2012 are expected to be approximately $1,055 million to support the drilling of approximately 158 gross wells, including 146 gross Marcellus wells and 12 Huron wells which were either spud in January 2012 or are required to maintain lease rights.  In addition, the Company plans to spend $365 million for midstream infrastructure in 2012.  Sales volumes are expected to be between 250 and 255 Bcfe for an anticipated production sales volume growth of approximately 30% in 2012.  The Company currently believes that the 2012 capital expenditure plan will be funded by cash flow generated from operations and cash on hand.

Strategy

EQT’s strategy is to maximize shareholder value by profitably developing the Company’s undeveloped Marcellus reserves by utilizing the Company’s extensive gathering and transmission assets, low cost structure, close proximity to the northeastern United States markets and the high energy content of much of its produced natural gas.

The Company has used technology to increase lateral length and develop multi-well pads. Recoveries from extended laterals have been proportional to the length increase. The Company expects to continue increasing the average lateral lengths over time; however, lateral lengths will be limited by lease boundaries in the Marcellus unless the Company is able to pool acreage with neighboring leaseholders.  Because substantially all of the Company’s acreage is held by production or in fee, EQT Production is able to develop its acreage in the most economic manner by using longer laterals and multi pad drilling rather than focusing on drilling less economic wells in order to retain acreage.  The Company has produced industry leading results in its core development area in Greene County, Pennsylvania.

The Company believes the location of its midstream assets across a wide area of the Marcellus in southwestern Pennsylvania and northern West Virginia uniquely positions it for growth.  In light of the growth of EQT Production and other producers in the Marcellus, EQT Midstream intends to capitalize on the growing need for

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gathering and transmission infrastructure in the region, especially the need for midstream header connectivity to interstate pipelines in Pennsylvania and West Virginia.

EQT plans to continue its investment in gathering and transmission capacity in the Marcellus.  In 2012, the Company intends to add 445 MMcfe per day of incremental gathering capacity, 285 MMcfe per day in Pennsylvania and 160 MMcfe per day in West Virginia.  Equitrans recently received approval from the FERC to proceed with construction of the Sunrise Pipeline project.  The Sunrise Pipeline will provide access to liquids-rich Marcellus acreage and will consist of 41.5 miles of 24-inch diameter pipeline that parallels and interconnects with an existing segment of our transmission and storage system from Wetzel County, West Virginia to Greene County, Pennsylvania.  In addition, the Sunrise Pipeline project will include connecting to a new delivery point with Texas Eastern Transmission in Green County and constructing the Jefferson compressor station, which will provide 314 BBtu, or approximately 300 MMcfe, per day of additional firm capacity to the system.   The Company also intends to add another 400 MMcfe per day of additional transmission capacity in 2012.  The combination of these gathering and transmission investments with existing assets will provide a platform for growth, mitigate curtailments and increase the flexibility and reliability of the Company’s gathering and transmission systems.

            The Company is also helping to build additional demand for natural gas. With the assistance of a $700,000 grant received from the Pennsylvania Department of Environmental Protection, the Company opened a public-access natural gas fueling station in Pittsburgh, PA during 2011.  In conjunction with this project, the Company is promoting the use of NGV fleet vehicles, including its own.  EQT plans to operate 23% of its vehicle fleet, more than 330 vehicles, on natural gas by the end of 2013.  The Company also plans to convert two drilling rigs to utilize natural gas in 2012.

            See “Capital Resources and Liquidity” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K for details regarding the Company’s capital expenditures.

Markets and Customers

No single customer accounted for more than 10% of revenues in 2011, 2010 or 2009.

Natural Gas Sales:  EQT’s produced natural gas is sold to marketers, utilities and industrial customers located mainly in the Appalachian area.  Natural gas is a commodity and therefore the Company receives market-based pricing.  The market price for natural gas can be volatile as demonstrated by significant declines in late 2011 and early 2012.  Changes in the market price for natural gas impact the Company’s revenues, earnings and liquidity.  The Company is unable to predict potential future movements in the market price for natural gas and thus cannot predict the ultimate impact of prices on its operations; however, the Company monitors the market for natural gas and adjusts strategy and operations as deemed appropriate.  In order to protect cash flow from undue exposure to the risk of changing commodity prices, 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.

NGL Sales:  The Company sells NGLs from its own production through the EQT Production segment and from gas marketed for third parties by EQT Midstream.  Until February 2011, the Company processed 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 were recovered at EQT’s Langley facility and transported to a fractionation plant owned by a third-party for separation into commercial components.  The third-party marketed these components for a fee. The Company also had contractual processing arrangements whereby the Company sold gas to a third-party processor at a weighted average liquids component price. Subsequent to the closing of the sale of the Langley facility to MarkWest, the processing of the Company’s produced natural gas has been performed by a third-party vendor.

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The following table presents the wellhead sales price on an average Mcfe basis to EQT Corporation for sales of produced natural gas, NGLs and oil, with and without hedges, for the years ended December 31:

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 2011 totaled 258.2 BBtu, of which approximately 75% related to gathering for EQT Production, 16% related to third-party volumes and 9% related to volumes for other affiliates of the Company.  Revenues from EQT Production and other affiliates accounted for approximately 87% of 2011 gathering revenues.

Natural Gas Transmission, Storage and Marketing: Services offered by EQT include commodity procurement, sales, delivery, risk management and other services.  These operations are executed using Company owned and operated 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 to take advantage of price differentials and arbitrage opportunities when available.  EQT Energy also engages in risk management and energy trading activities, the objective of which 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 2012 and 2023.  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 2011, approximately 84% of transportation volumes and revenues were from affiliates.

Natural Gas Distribution: The Company’s Distribution segment provides natural gas distribution services to approximately 276,500 customers, consisting of 257,700 residential customers and 18,800 commercial and 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.  Distribution’s 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. The cost of purchased gas is Equitable Gas’ largest operating expense and is passed through to customers utilizing mechanisms approved by the PA PUC and WV PSC. Equitable Gas is not permitted to profit from fluctuations in gas costs and does not purchase gas produced by EQT Production.

Because most of its customers use natural gas for heating purposes, Equitable Gas’ revenues are seasonal, with approximately 66% of calendar year 2011 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.

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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 independent oil and gas companies, major oil and gas companies and individual producers and operators.  Key competitors for new gathering 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.  As a regulated utility, the Company’s distribution operation experiences only limited competition with other local distribution companies in its operating area, but experiences usage pressures as a result of alternative fuels and conservation.

Regulation

Regulation of the Company’s Operations

EQT Production’s exploration and production operations are subject to various types of federal, state and local laws and regulations, including regulations related to the location of wells; the method of drilling, well construction and casing design; water withdrawal and procurement 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 plugging and abandoning of wells; the calculation, reporting and disbursement of taxes; and the gathering of production in certain circumstances, such as safety regulations.  These regulations may impact the costs of developing the Company’s natural gas resources.

EQT Production’s operations are also subject to conservation and correlative rights 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 or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of natural gas properties.  Both Kentucky and Virginia allow the statutory pooling or integration of tracts to facilitate development and exploration, while in West Virginia and Pennsylvania it is necessary to rely on voluntary pooling of lands and leases.  In addition, state conservation laws generally limit the venting or flaring of natural gas.

EQT Midstream’s transmission and gathering operations are subject to various types of federal and state environmental laws and local zoning ordinances, including air permitting requirements for compressor station and dehydration units; erosion and sediment control requirements for compressor station and pipeline construction projects; waste management requirements and spill prevention plans for compressor stations;  various recordkeeping and reporting requirements for air permits and waste management practices; compliance with safety regulations; and siting and noise regulations for compressor stations. These regulations may impact the costs of or increase the time of developing new or expanded pipelines and compressor stations.

EQT Midstream has both non-regulated and regulated rate operations.  The interstate natural gas transmission systems and storage operations are regulated by the FERC. For instance, the FERC approves tariffs that establish Equitrans’ rates, cost recovery mechanisms, and other terms and conditions of service to Equitrans’ customers. The fees or rates established under Equitrans’ tariffs are a function of its costs of providing services to customers, including a reasonable return on invested capital. The FERC’s authority also extends to: storage and related services; certification and construction of new facilities; extension or abandonment of services and facilities; maintenance of accounts and records; relationships between pipelines and certain affiliates; terms and conditions of service; depreciation and amortization policies; acquisition and disposition of facilities; the safety of pipelines; and initiation and discontinuation of services.

EQT Production and EQT Midstream each engage in natural gas trading activities which are regulated by, among others, the CFTC.  In July 2010, federal legislation was enacted that, among other things, established federal oversight and regulation of the OTC derivative market and entities that participate in that market.  The legislation requires the SEC and CFTC to promulgate rules and regulations implementing the legislation and, as of the date of

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this report, most of the key implementing regulations have not been adopted.  Accordingly, it is not possible at this time to predict the impact of the legislation on our hedging program.

Equitable Gas’ distribution rates, terms of service and certain contracts with affiliates are subject to comprehensive regulation by the PA PUC and the WV PSC.  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.

As required by Pennsylvania law, Equitable Gas has a customer assistance program that assists low-income customers with paying their gas bills. The cost of this program is recovered through rates charged to other residential customers.

Regulators periodically audit the Company’s compliance with applicable regulatory requirements.  The Company anticipates that compliance with existing laws and regulations governing current operations will not have a material adverse effect upon its capital expenditures, earnings or competitive position.  Additional proposals that affect the oil and gas industry are regularly considered by Congress, the states, regulatory agencies and the courts. The Company cannot predict when or whether any such proposals may become effective.

Environmental, Health and Safety Regulation

The business operations of the Company are also subject to various federal, state and local environmental, health and safety laws and regulations pertaining to, among other things, the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees and the general public, and the pollution, preservation, remediation or protection of human health and safety, natural resources, wildlife or the environment. The Company must take into account environmental, health and safety regulations in, among other things, planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities. In most instances, the regulatory frameworks relate to the handling of drilling and production materials, the disposal of drilling and production wastes, the protection of water and air and the protection of people.

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.  Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material to the Company’s financial position, results of operations or liquidity.

Vast quantities of natural gas deposits exist in shale and other formations. It is customary in the Company’s industry to recover natural gas from these shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into a shale gas formation. These deeper formations are geologically separated and isolated from fresh ground water supplies by protective rock layers. The Company’s well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers. Legislative and regulatory efforts at the federal level and in some states have sought to render more stringent permitting and compliance requirements for hydraulic fracturing. If passed into law, the additional permitting requirements for hydraulic fracturing may increase the cost to or limit the company’s ability to obtain permits to construct wells.

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Climate Change

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Effective January 1, 2011, the EPA began regulating greenhouse gas emissions by subjecting new facilities and major modifications to existing facilities that emit large amounts of greenhouse gases to the permitting requirements of the federal Clean Air Act.  In addition, the U.S. Congress has been considering bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. Legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and greenhouse gas legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat generated than other fuels, such as coal. The effect on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Employees

The Company and its subsidiaries had approximately 1,835 employees at the end of 2011. As of December 31, 2011, approximately 11% of the Company’s workforce was subject to collective bargaining agreements.  The collective bargaining agreement which covers approximately 9% of the Company’s workforce expired on September 25, 2011.  The union agreed to continue working under the terms and conditions of the expired labor agreement while the parties continue negotiations for a new agreement.  The collective bargaining agreement which covers approximately 1% of the Company’s workforce will expire on May 21, 2012.

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, 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.  These filings are also available on the internet at http://www.sec.gov.  The Company’s 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.

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.

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Jurisdiction and Year of Formation

The Company is a Pennsylvania corporation formed in 2008 in connection with a holding company reorganization of the former Equitable Resources, Inc.

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 upon 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 availability, proximity and capacity of pipelines, other transportation facilities, and gathering and processing 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 drilling activity and the construction of new transportation capacity and downward adjustments to the value of oil and gas properties which may cause us to incur non-cash charges to earnings.  Moreover, if we fail to control our operating costs during periods of lower natural gas prices, we could further reduce our margin. A reduction in margin or 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 may subject us to margin calls on our commodity price derivative contracts in an asset position (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.

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 and natural gas liquids, such as well site blowouts, cratering and explosions, pipe and other equipment and system failures, uncontrolled flows of natural gas or well fluids, fires, formations with abnormal pressures, pollution and environmental risks and natural disasters.  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.  Moreover, in the event that one or more of these hazards occur, there can be no assurance that a response will be adequate to limit or reduce damage.  As a result of these risks, we are also 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

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and property damage or that such levels of insurance will be available in the future at economical prices or to cover all risks.

Our failure to develop, obtain or 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, proximity and capacity of pipelines, other transportation facilities, and gathering and processing facilities. In the Marcellus, the capacity of transportation, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells.  Competition for pipeline infrastructure within the region is intense, and many of our competitors have substantially greater financial resources than we do, which could affect our competitive position. 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. 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 transportation, gathering, processing and storage facilities which are limited in number, geographically concentrated and subject to the same risks identified above with respect to our infrastructure development and maintenance programs.  An extended interruption of access to or service from our or third-party facilities could result in adverse consequences to us, such as delays in producing and selling our natural gas.  In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project.  In addition, some of our third-party contracts may involve significant long-term financial commitments on our part.  Moreover, our usage of third parties for transportation, gathering and processing services subjects us to the credit and performance risk of such third parties and may make us dependent upon those third parties to get our produced natural gas to market.

We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.

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 or other sources.  Future challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition.  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. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection.  Future challenges in the economy could also 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.

Strategic determinations, including the allocation of capital and other resources to strategic opportunities are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.

Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our 2012 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

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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 2012 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected.  Moreover economic or other circumstances may change from those contemplated by our 2012 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

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.  Environmental, 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; locations available for drilling and pipeline construction; environmental impact studies and assessments prior to permitting; restoration of drilling properties after drilling is completed; pipeline safety (including replacement requirements); and work practices related to employee health and safety.  Compliance with the laws, regulations and other legal requirements applicable to our businesses may increase our cost of doing business or result in delays due to the need to obtain additional or more detailed governmental approvals and permits.  These requirements could also subject us to claims 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, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.

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, effective January 1, 2011, the EPA began regulating greenhouse gas emission by subjecting new facilities and major modifications to existing facilities that emit large emissions of greenhouse gas emissions to the permitting requirements of the Federal Clean Air Act.

In addition, 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 the release, capture and use of greenhouse gases that could have an adverse effect on our operations.

In July 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAP”) programs.  The EPA’s proposed rules also include NSPS standards for the completions of hydraulically fractured gas wells, applicable to newly drilled and fractured wells as well as existing wells that are refractured.  The proposed regulations under NESHAP include maximum achievable control technology standards for certain equipment not currently subject to such standards.  The final regulations could result in an increase to our costs or require changes that reduce our production.

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In addition, hydraulic fracturing is utilized to complete most of our natural gas wells. Certain environmental and other groups have suggested that additional laws and regulations may be needed to more closely regulate the hydraulic fracturing process, and legislation has been proposed or is under discussion at the federal and state levels.  We cannot predict whether any such federal or state legislation or regulation will be enacted and if enacted how they may impact our operations, but enactment of additional laws or regulations could increase our operating costs.

Recent federal budget proposals have included provisions which could potentially increase and accelerate the payment of federal income taxes of independent producers of natural gas and oil. Proposals that would significantly affect us would repeal the expensing of intangible drilling costs, repeal the percentage depletion allowance and increase the amortization period of geological and geophysical expenses. These changes, if enacted, will make it more costly for us to explore for and develop our natural gas resources.

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.

In July 2010, federal legislation was enacted that, among other things, establishes federal oversight and regulation of the over-the-counter (OTC) derivatives market and entities that participate in that market.  The new legislation requires the SEC and the CFTC to promulgate rules and regulations implementing the new legislation and, as of the date of this report, most of the key implementing regulations have not been adopted.  Accordingly, it is not possible at this time to predict the impact of the new legislation on our hedging program.  It is possible, however, that the legislation will make hedging more expensive, uneconomic or unavailable, which could lead to increased costs or commodity price volatility or a combination of both.

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.  In addition, any exploration projects increase 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 areas, our future operating results may be difficult to forecast, and our failure to sustain high growth rates in the future could adversely affect the market price of our common stock.

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, equipment and a qualified work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology, equipment failure or accidents 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

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existing wells, our reserves and revenues will decline as a result of our current reserves being depleted by production.

We also rely on third parties for certain construction, drilling and completion services, materials and supplies.  Delays or failures to perform by such third parties could adversely impact our operations.

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, the oil spill in the Gulf of Mexico, the explosion of natural gas transmission lines in California and elsewhere and concerns raised by advocacy groups about hydraulic fracturing, may lead to increased regulatory scrutiny which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.  These action may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation.  Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

The loss of key personnel could adversely affect our ability to execute our strategic, operational and financial plans.

Our operations are dependent upon key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, the success of our operations will depend, in part, on our ability to attract, develop and retain experienced personnel. There is competition within our industry for experienced technical personnel and certain other professionals, which could increase the costs associated with attracting and retaining such personnel. If we cannot attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete could be harmed.

The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated natural gas and oil reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves.  In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil and the amount, timing and cost of actual production.  In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas, NGL and oil industry in general.

Our proved reserves are estimates that are based upon many assumptions that may prove to be inaccurate.  Any significant change in these underlying assumptions will greatly affect the quantities and present value of our reserves.

Reserve engineering is a subjective process involving estimates of underground accumulations of natural gas, NGLs and oil and assumptions concerning future prices, production levels and operating and development costs.   These estimates and assumptions are inherently imprecise.  As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.   Any significant variance from our assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, NGLs and oil, the classifications of reserves based on risk of recovery and estimates of the future net cash flows.  Numerous changes over time to the assumptions on which our reserve

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estimates are based, as described above, often result in the actual quantities of natural gas, NGLs and oil we ultimately recover being different from our reserve estimates.

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 or, in the case of certain office locations, warehouse buildings and equipment, leased, by the Company’s business segments.  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 Pennsylvania, West Virginia, Kentucky and Virginia. This segment has approximately 3.5 million gross acres (approximately 63% of which are considered undeveloped), which encompasses substantially all of the Company’s acreage of proved developed and undeveloped natural gas and oil production properties.  Approximately 530,000 of these acres are located in the Marcellus.  Although most of its wells are drilled to relatively shallow depths (2,000 to 8,000 feet below the surface), the Company retains what are normally considered “deep rights” on the majority of its acreage.  As of December 31, 2011, the Company estimated its total proved reserves to be 5,365 Bcfe, consisting of proved developed producing reserves of 2,502 Bcfe, proved developed non-producing reserves of 464 Bcfe and proved undeveloped reserves of 2,399 Bcfe. Substantially 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 preparing the reserve report and the technical aspects of the reserves audit received a bachelor’s degree in Petroleum and Natural Gas Engineering from the Pennsylvania State University and has twenty-three 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 Company’s estimate of proved natural gas and oil reserves is audited by the independent consulting firm of Ryder Scott Company L.P. (Ryder Scott), which is hired by the Company’s management.  Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.  Ryder Scott reviewed 100% of the total net gas and liquid hydrocarbon proved reserves attributable to the Company’s interests as of December 31, 2011. Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties.  This audit covered 80% of the Company’s proved reserves.  Ryder Scott’s audit of the remaining 20% of the Company’s properties consisted of an audit of aggregated groups not exceeding 200 wells per group.  Ryder Scott’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.

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In 2011, the Company commenced drilling operations (“spud” or “drilled”) on 105 gross horizontal wells with an aggregate of approximately 500,000 feet of pay in the Marcellus play. Total proved reserves in the Marcellus play increased 19% to 3.4 Tcfe in 2011 as a result of the Company’s 2011 drilling program. In the Huron play, the Company drilled 115 gross horizontal wells with an aggregate of approximately 550,000 feet of pay during 2011.  Total proved reserves in the Huron play (including vertical non-shale formations) decreased 19% to 1.8 Tcfe, as the Company plans to focus its capital expenditures during the next five years on developing the Marcellus play.  The Company did not drill any gross CBM wells in 2011.  The CBM play had total proved reserves of 0.2 Tcfe at December 31, 2011, slightly up from 2010.  Natural gas production sales volumes in 2011 from the Marcellus, Huron and CBM plays were 81.6 Bcfe, 99.1 Bcfe and 13.7 Bcfe, respectively.  Over the past three years, the Company has experienced a 99% developmental drilling success rate.

Natural gas, NGL and crude oil production and pricing:

The Company’s average per unit production cost, excluding production taxes, of natural gas and crude oil during 2011, 2010 and 2009 was $0.20, $0.24 and $0.30 per Mcfe, respectively.  At December 31, 2011, the Company had approximately 57 multiple completion wells.

As of December 31, 2011, the Company did not have any reserves that have been classified as proved undeveloped reserves for more than five years.

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Certain lease and acquisition agreements require the Company to drill 6 wells in the Marcellus formation in 2012 within specified acreage.  The Company intends to satisfy such requirements to the extent that they fit into its 2012 Marcellus development program, however approximately 200 acres could expire in so much as they currently fall outside of its priority development areas. As of December 31, 2011 and not including the above, leases associated with 8,988 gross undeveloped acres expire in 2012 if they are not renewed; however, the Company has an active lease renewal program in areas targeted for development.

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

Selected data by state (at December 31, 2011 unless otherwise noted):

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Capital expenditures at EQT Production totaled $1,088 million during 2011, including $57.2 million for the acquisition of undeveloped property and $92.6 million of liabilities assumed in the ANPI transaction. During the year, the Company converted 187 Bcfe of proved undeveloped reserves to proved developed reserves and added 452 Bcfe of proved developed reserves which were not previously categorized as proved undeveloped reserves. New proved undeveloped reserves of 822 Bcfe were added during 2011 while 921 Bcfe were reduced in accordance with the Company's decision to focus on Marcellus drilling over the next five years and to comply with the SEC five year guidance. As of December 31, 2011, the Company's proved undeveloped reserves totaled 2.4 Tcfe and all were associated with the development of the Marcellus play. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2016.

The Company’s 2011 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 694 Bcfe exceeded the 2011 production of 199 Bcfe.

Wells located in Kentucky are primarily in Huron formation with depths ranging from 2,500 feet to 6,000 feet.  Wells located in West Virginia are primarily in Huron and Marcellus formations with depths ranging from 2,500 feet to 6,500 feet.  Wells located in Virginia are primarily in CBM formations with depths ranging from 2,000 feet to 3,000 feet.  Wells located in Pennsylvania are primarily in Marcellus formations with depths ranging from 7,000 feet to 8,000 feet.

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

EQT Midstream: EQT Midstream owns or operates approximately 10,450 miles of gathering line and 248 compressor units with approximately 245,000 horsepower of installed capacity, as well as other general property and equipment.

Substantially all of the gathering operation’s 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.

EQT Midstream also owns and operates a FERC-regulated transmission and storage system.  These operations consist of an approximately 700 mile FERC- regulated interstate pipeline system that connects to five interstate pipelines and multiple distribution companies and is supported by 14 associated natural gas storage reservoirs with approximately 400 MMcf per day of peak delivery capability and 32 Bcf of working gas capacity.  The transmission and storage system stretches throughout north central West Virginia and southwestern Pennsylvania.

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.

See “Capital Resources and Liquidity” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of capital expenditures.

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Item 3. Legal Proceedings

In the ordinary course of business, various 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 accrues legal or other direct costs related to loss contingencies when actually incurred.  The Company has established reserves it believes to be appropriate for pending matters 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, results of operations or liquidity of the Company.

Item 4. Mine Safety and Health Administration Data

Not appliable.

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Executive Officers of the Registrant (as of February 16, 2012)

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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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 January 31, 2012, there were 3,249 shareholders of record of the Company’s common stock.

The amount and timing of dividends is subject to the discretion of the Board of Directors and depends on business conditions, such as the Company’s lines of business, result of operations and financial conditions, strategic direction and other factors.

The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Securities Exchange Act of 1934, as amended that have occurred in the three months ended December 31, 2011:

(a)          Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock.

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Stock Performance Graph

The following graph compares the most recent five-year cumulative total return attained by shareholders on the Company’s common stock with the cumulative total returns of the S&P 500 index and two customized peer groups of twenty companies (the “Old Self-Constructed Peer Group”) and twenty-five companies (the “New Self-Constructed Peer Group”), respectively, whose individual companies are listed in footnotes (1) and (2) below, respectively.  An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2006 in the Company’s common stock, in the S&P 500 index, and in each peer group. Relative performance is tracked through December 31, 2011.

(1) The Company’s old self-constructed peer group includes twenty companies, which are: Atlas Energy Resources LLC, Cabot Oil & Gas Corp., Chesapeake Energy Corp., CNX Gas Corporation, El Paso Corp., Enbridge Inc., Energen Corp., Markwest Energy Partners Limited Partner, MDU Resources Group Inc., National Fuel Gas Company, Oneok Inc., Penn Virginia Corp., Questar Corp., Range Resources Corp., Sempra Energy, Southern Union Company, Southwestern Energy Company, Spectra Energy Corp., Transcanada Corp. and

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Williams Companies Inc.  Atlas Energy Resources LLC was acquired during 2009 and is included in the calculation from December 31, 2005 through December 31, 2008, at which time it is removed from the peer group calculation.  CNX Gas Corporation was acquired during 2010 and is included in the calculation from December 31, 2005 through December 31, 2009, at which time it is removed from the peer group calculation.  Questar Corporation was calculated using historical split adjusted pricing data.

(2) The Company’s new self-constructed peer group includes twenty-five companies which are: Cabot Oil & Gas Corp., Chesapeake Energy Corp., Cimarex Energy Company, Consol Energy Inc, Energen Corp., EOG Resources Inc, Exco Resources Inc, Markwest Energy Partners Limited Partner, MDU Resources Group Inc, National Fuel Gas Company, Nstar, Oneok Inc, Penn Virginia Corp., Pioneer Natural Resources Company, Plains Exploration & Production Company, Questar Corp., Quicksilver Resources Inc, Range Resources Corp., Sempra Energy, SM Energy Company, Southwestern Energy Company, Spectra Energy Corp., Ultra Petroleum Corp., Whiting Petroleum Corp. and Williams Companies Inc.  In future years, the Company generally will use this new self-constructed peer group because the businesses operated by this self-constructed peer group more closely reflect the businesses engaged in by the Company and this peer group is the same as the peer group for the Company’s 2012 Executive Performance Incentive Program.

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Item 6.  Selected Financial Data

See Item 1A, “Risk Factors” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 2, 5 and 6 to the Consolidated Financial Statements for a discussion of an adjustment to operating revenues for all periods and 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 2011 EQT achieved record results.  Highlights for 2011 include:

·      Record annual production sales volumes of 194.4 Bcfe, 44% higher than in 2010;

·      Marcellus proved reserves increased by 19%;

·      Unit lease operating expense, excluding production taxes (LOE), decreased 17% in 2011, to $0.20 per Mcfe. Including production taxes, LOE was $0.40 per Mcfe; and

·      Record EQT Midstream throughput and operating income.

EQT’s consolidated net income for 2011 was $479.8 million, $3.19 per diluted share, compared with $227.7 million, $1.57 per diluted share, for 2010 and $156.9 million, $1.19 per diluted share, for 2009.  In 2011, the Company recorded $128.3 million of after-tax gains on dispositions related to the sales of Langley and Big Sandy as described in Item I, “Business.”

Operating income increased to $861.3 million in 2011 from $470.5 million in 2010.  In addition to the $202.9 million pre-tax gain on the dispositions of Big Sandy and Langley and the absence of revenues and expenses associated with these assets, operating income was favorably impacted by increased production sales volumes and higher gathering and transmission revenues which more than offset the increase in operating expenses associated with higher volumes, lower storage and marketing net operating revenues and a lower average wellhead sales price to EQT Corporation.

Production sales volumes increased more than 44% in 2011 from 2010, largely associated with the Marcellus play, as a result of increased production from the 2010 and 2011 drilling programs partially offset by the normal production decline in the Company’s producing wells.  Gathered revenues increased as a result of a 32% increase in gathered volumes primarily related to the Company’s production growth.  Transmission net revenues increased as a result of higher firm transportation activity and capacity from the Equitrans 2010 Marcellus expansion project.  The average wellhead sales price to EQT Corporation including the effect of the Company’s hedging program was $5.37 per Mcfe in 2011 compared to $5.62 per Mcfe in 2010.  Hedging activities resulted in an increase in the average natural gas sales price of $0.55 per Mcf in both 2011 and 2010.

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Operating expenses for 2011 increased $77.6 million compared to 2010 primarily as a result of increased production depletion and expenses on higher produced volumes as well as higher selling, general and administrative expenses consistent with the growth of the business.  These increases were partially offset by the absence of expenses associated with Big Sandy and Langley, primarily operating and maintenance expenses, and favorable adjustments for certain non-income tax matters.

The $70.8 million increase in net income from 2009 to 2010 was primarily attributable to increased production sales volumes, higher gathering revenues, increased net revenues for NGLs, lower long-term incentive compensation expense and lower exploration expense. These favorable variances were partially offset by increased depreciation, depletion and amortization, lower average wellhead sales prices and lower storage and marketing revenues.

EQT revenues for 2010 increased approximately 5% compared to 2009 revenues.  Production sales volumes increased more than 34% from 2009 primarily as a result of increased production from the 2009 and 2010 drilling programs partially offset by the normal production decline in the Company’s producing wells. Gathered volumes increased due to the Company’s production growth and infrastructure expansion. Residential revenues increased as a result of the Company’s base rate increases in February 2009 and August 2010. These increases were partially offset by a 3% decline in the average wellhead sales price to EQT Corporation as a result of lower hedge prices year-over-year which more than offset slightly increased natural gas commodity and NGL prices and a 7% decline in storage and marketing revenues primarily resulting from lower margins on asset optimization activities.

Operating expenses for 2010 decreased approximately 5% compared to 2009. This decline was primarily attributable to a $108.0 million decrease in purchased gas costs due to lower recoverable commodity costs, a $39.3 million decrease in long-term incentive compensation expense and a $12.5 million decrease in the Company’s exploration program. The decrease in exploration expense was primarily a result of a reduction in the level of purchase and interpretation of seismic data for unproved properties.  These decreases were partially offset by higher depletion resulting from increased investment in oil and gas producing properties.

See “Other Income Statement Items” for a discussion of other income, interest expense and income taxes and “Investing Activities” in “Capital Resources and Liquidity” for a discussion of capital expenditures.

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EQT CORPORATION

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. Interest, income taxes and other income 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 totaling $29.3 million, $15.1 million and $62.2 million, respectively, were not allocated to the operating segments for the years ended December 31, 2011, 2010 and 2009.

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The Company has 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 provides useful information to management and investors regarding the financial condition, operations and trends of each of EQT’s segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest, income taxes and other income.  In addition, management uses these measures for budget planning purposes.  The Company’s management reviews and reports Production segment results for operating revenues and purchased gas costs with transportation costs reflected as a deduction from operating revenues as management believes this presentation provides a more useful view of net wellhead price and is consistent with industry practices.  Third party transportation costs are reported as a component of purchased gas costs in the consolidated results.  The Company has reconciled each segment’s operating income to the Company’s consolidated operating income and net income in Note 2 to the Consolidated Financial Statements.

EQT Production

Results of Operations