Edgar Filing: EQT Corp

10-K

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, 2015



[ ]	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)



PENNSYLVANIA (State or other jurisdiction of incorporation or organization)	25-0464690 (IRS Employer Identification No.)
625 Liberty Avenue Pittsburgh, Pennsylvania (Address of principal executive offices)	15222 (Zip Code)

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

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



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

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):



Large accelerated filer X	Accelerated filer ___
Non-accelerated filer ___	Smaller reporting company ___

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, 2015: $10.5 billion

The number of shares (in thousands) of common stock outstanding as of January 31, 2016: 152,568

DOCUMENTS INCORPORATED BY REFERENCE

The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held April 20, 2016) will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2015 and is incorporated by reference in Part III to the extent described therein.

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TABLE OF CONTENTS



	Glossary of Commonly Used Terms, Abbreviations and Measurements	3
	Cautionary Statements	6

PART I

Item 1	Business	7
Item 1A	Risk Factors	18
Item 1B	Unresolved Staff Comments	24
Item 2	Properties	24
Item 3	Legal Proceedings	28
Item 4	Mine Safety Disclosures	28
	Executive Officers of the Registrant	29


PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6	Selected Financial Data	32
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	58
Item 8	Financial Statements and Supplementary Data	61
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	115
Item 9A	Controls and Procedures	115
Item 9B	Other Information	115

PART III

Item 10	Directors, Executive Officers and Corporate Governance	116
Item 11	Executive Compensation	116
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	117
Item 13	Certain Relationships and Related Transactions and Director Independence	118
Item 14	Principal Accounting Fees and Services	118

PART IV

Item 15	Exhibits and Financial Statement Schedules	119
	Index to Financial Statements Covered by Report of Independent Registered Public Accounting Firm	119
	Index to Exhibits	121
	Signatures	128

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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 regulated 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 composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains.

basis – when referring to commodity pricing, 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.

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.

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.

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.

horizontal wells – wells that are drilled 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 derivative contract to guarantee fulfillment of contract obligations.

multiple completion well – a well equipped to produce oil and/or gas separately from more than one reservoir. Such wells contain multiple strings of tubing or other equipment that permit production from the various completions to be measured and accounted for separately.

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Glossary of Commonly Used Terms, Abbreviations and Measurements

NGL – 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 and iso-butane.

net – “net” natural gas and oil wells or “net” acres are determined by adding 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 interests (equal to 100% minus all royalties on a well or property).

play – a proven geological formation that contains commercial amounts of hydrocarbons.

proved reserves – quantities of oil, natural gas, and NGLs which, by analysis of geological 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.

throughput – the volume of natural gas transported or passing through a pipeline, plant, terminal, or other facility during a particular period.

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.

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Glossary of Commonly Used Terms, Abbreviations and Measurements

Abbreviations

ASC – Accounting Standards Codification

CBM – Coalbed Methane

CFTC – Commodity Futures Trading Commission

EPA – U.S. Environmental Protection Agency

FASB – Financial Accounting Standards Board

FERC – Federal Energy Regulatory Commission

GAAP - Generally Accepted Accounting Principles

IPO – initial public offering

IRS – Internal Revenue Service

NYMEX – New York Mercantile Exchange

OTC – over the counter

SEC – Securities and Exchange Commission

WTI – West Texas Intermediate

Measurements

Bbl = barrel

BBtu = billion British thermal units

Bcf = billion cubic feet

Bcfe = billion cubic feet of natural gas

equivalents, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

Btu = one British thermal unit

Dth = million British thermal units

Mcf = thousand cubic feet

Mcfe = thousand cubic feet of natural gas

equivalents, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

Mbbl = thousand barrels

MMBtu = million British thermal units

MMcf = million cubic feet

MMcfe = million cubic feet of natural gas

equivalents, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

TBtu = trillion British thermal units

Tcfe = trillion cubic feet of natural gas

equivalents, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

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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,” “forecast,” “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 Annual Report on Form 10-K include the matters discussed in the section captioned “Strategy” in Item 1, “Business,” the sections captioned “Outlook” and “Impairment of Oil and Gas Properties” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the expectations of plans, strategies, objectives and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s strategy to develop its Marcellus, deep Utica 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 sales volumes (including liquids volumes) and growth rates; gathering and transmission volumes (including the subscription of additional capacity related to the expiration of EQT Midstream Partners, LP (EQM) firm transportation contracts); the weighted average contract life of firm transmission and storage contracts; infrastructure programs (including the timing, cost and capacity of the transmission and gathering expansion projects); the timing, cost, capacity and expected interconnects with facilities and pipelines of the Ohio Valley Connector (OVC) and Mountain Valley Pipeline (MVP) projects; the ultimate terms, partners and structure of the MVP joint venture; technology (including drilling and completion techniques); monetization transactions, including midstream asset sales (dropdowns) to EQM and other asset sales, joint ventures or other transactions involving the Company’s assets; natural gas prices and changes in basis; reserves, including potential future downward adjustments; potential future impairments of the Company's assets; projected capital expenditures; the amount and timing of any repurchases under the Company’s share repurchase authorization; liquidity and financing requirements, including funding sources and availability; hedging strategy; operation of the Company's fleet vehicles on natural gas; the effects of government regulation and litigation; and tax position. The forward-looking statements included 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, many of which are difficult to predict and 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 statement, whether as a result of new information, future events or otherwise.

In reviewing any agreements incorporated by reference in or filed with this Annual Report on 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 to such agreements 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 of the Company or its affiliates 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 two business segments: EQT Production and EQT Midstream. EQT Production is one of the largest natural gas producers in the Appalachian Basin with 10.0 Tcfe of proved natural gas, NGL and crude oil reserves across approximately 3.4 million gross acres, including approximately 630,000 gross acres in the Marcellus play, as of December 31, 2015. EQT Midstream provides gathering, transmission and storage services for the Company’s produced gas, as well as for independent third parties across the Appalachian Basin, primarily through its ownership and control of EQT Midstream Partners, LP (EQM) (NYSE: EQM), a publicly traded limited partnership formed by EQT to own, operate, acquire and develop midstream assets in the Appalachian Basin.

In 2015, the Company formed EQT GP Holdings, LP (EQGP) (NYSE: EQGP), a Delaware limited partnership, to own the Company's partnership interests, including the incentive distribution rights, in EQM. As of December 31, 2015, the Company owned the entire non-economic general partner interest and 239,715,000 common units, which represented a 90.1% limited partner interest, in EQGP. As of December 31, 2015, EQGP owned the following EQM partnership interests, which represent EQGP's only cash-generating assets: 21,811,643 EQM common units, representing a 27.6% limited partner interest in EQM; 1,443,015 EQM general partner units, representing a 1.8% general partner interest in EQM; and all of EQM's incentive distribution rights, or IDRs, which entitle EQGP to receive up to 48.0% of all incremental cash distributed in a quarter after $0.5250 has been distributed in respect of each common unit and general partner unit of EQM for that quarter. The Company is the ultimate parent company of EQGP and EQM.

Key Events in 2015

During 2015, EQT achieved record annual production sales volumes, including a 27% increase in total sales volumes and a 34% increase in Marcellus sales volumes. However, the average realized price to EQT Corporation for production sales volumes decreased 36% from $4.16 per Mcfe in 2014 to $2.67 per Mcfe in 2015. EQT’s midstream business delivered record gathered volumes that were 28% higher than the previous year. During 2015, EQM reported net income of $393.5 million, $127.0 million higher than 2014. The increase was primarily related to higher operating income driven by production development in the Marcellus Shale by EQT and third parties. EQT and its consolidated subsidiaries also completed the following transactions and other events that were instrumental in contributing to a successful 2015:


•	On February 17, 2015, the 17,339,718 subordinated units of EQM issued to the Company in connection with EQM's 2012 IPO converted into common units representing limited partner interests in EQM on a one-for-one basis as a result of satisfaction of the conditions for termination of the subordination period set forth in EQM's partnership agreement.

•

On March 10, 2015, the Company and certain subsidiaries of the Company entered into a contribution and sale agreement (Contribution Agreement) with EQM and EQM Gathering Opco, LLC (EQM Gathering), an indirect wholly owned subsidiary of EQM. Pursuant to the Contribution Agreement, on March 17, 2015, a subsidiary of the Company contributed the Northern West Virginia Marcellus gathering system to EQM Gathering in exchange for total consideration of $925.7 million, consisting of $873.2 million in cash, 511,973 EQM common units and 178,816 EQM general partner units (the NWV Gathering Transaction). EQM Gathering is consolidated by the Company as it is still controlled by the Company. On April 15, 2015, pursuant to the Contribution Agreement, the Company transferred a preferred interest in EQT Energy Supply, LLC, which at the time was an indirect wholly owned subsidiary of the Company, to EQM in exchange for total consideration of $124.3 million. EQT Energy Supply, LLC generates revenue from services provided to a local distribution company.

•

On March 17, 2015, EQM completed an underwritten public offering of 8,250,000 common units. On March 18, 2015, the underwriters exercised their option to purchase 1,237,500 additional common units on the same terms as the offering. EQM received net proceeds of $696.6 million from the offering after deducting the underwriters’ discount and offering expenses of $24.5 million. EQM used the proceeds from the offering to fund a portion of the purchase price for the NWV Gathering Transaction.

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•

On March 30, 2015, the Company assigned 100% of the membership interests in MVP Holdco, LLC (MVP Holdco), an indirect wholly owned subsidiary of the Company that as of February 11, 2016 owned a 45.5% interest (the MVP Interest) in Mountain Valley Pipeline, LLC (MVP Joint Venture), to EQM for $54.2 million, which represented EQM's reimbursement to the Company for 100% of the capital contributions made by the Company to the MVP Joint Venture as of March 30, 2015. The MVP Joint Venture plans to construct the Mountain Valley Pipeline (MVP), an estimated 300-mile natural gas interstate pipeline spanning from northern West Virginia to southern Virginia. The MVP Joint Venture has secured a total of 2.0 Bcf per day of 20-year firm capacity commitments, including a 1.29 Bcf per day firm capacity commitment by the Company. The MVP Joint Venture submitted the MVP certificate application to the FERC in October 2015 and anticipates receiving the certificate in the fourth quarter of 2016. Subject to FERC approval, construction is scheduled to begin shortly thereafter and the pipeline is expected to be in-service during the fourth quarter of 2018.

•

On May 15, 2015, EQGP completed an IPO of 26,450,000 common units, which represented 9.9% of EQGP's outstanding limited partner interests. EQT Gathering Holdings, LLC, an indirect wholly owned subsidiary of the Company, as the selling unitholder, sold all of the EQGP common units in the offering, resulting in net proceeds to the Company of approximately $674.0 million after deducting the underwriters' discount of approximately $37.5 million and structuring fees of approximately $2.7 million.

•

During the second half of 2015, EQM entered into an equity distribution agreement that established an "At the Market" (ATM) common unit offering program, pursuant to which a group of managers, acting as EQM's sales agents, may sell EQM common units having an aggregate offering price of up to $750 million (the $750 million ATM Program). EQM issued 1,162,475 common units at an average price per unit of $74.92 during the six months ended December 31, 2015. EQM received net proceeds of approximately $85.5 million after deducting commissions of approximately $0.9 million and other offering expenses of approximately $0.7 million. EQM used the net proceeds from the sales for general partnership purposes.

•

On November 16, 2015, EQM completed an underwritten public offering of 5,650,000 common units. EQM received net proceeds of $399.9 million from the offering after deducting the underwriters’ discount and offering expenses of $5.7 million. EQM will use the net proceeds from the offering for general partnership purposes, including to fund a portion of EQM's anticipated 2016 capital expenditures related to transmission and gathering expansion projects and to repay amounts outstanding under EQM's credit facility.

EQT Production Business Segment

EQT Production is one of the largest natural gas producers in the Appalachian Basin with 10.0 Tcfe of proved natural gas, NGL and crude oil reserves across approximately 3.4 million gross acres, including approximately 630,000 gross acres in the Marcellus play, as of December 31, 2015. EQT believes that it is a technology leader in extended lateral horizontal and completion drilling in the Appalachian Basin and continues to improve its operations through the use of new technology. EQT Production’s strategy is to maximize shareholder value by maintaining an industry leading cost structure to profitably develop its reserves. EQT’s proved reserves decreased 7% in 2015, primarily as a result of lower natural gas prices. The Company’s Marcellus assets constitute approximately 7.8 Tcfe of the Company's total proved reserves.

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The following illustration depicts EQT’s acreage position within the Marcellus play as of December 31, 2015:

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As of December 31, 2015, the Company’s proved reserves were as follows:



(Bcfe)	Marcellus	Upper Devonian	Other	Total
Proved Developed	4,120	406	1,754	6,280
Proved Undeveloped	3,649	48	—	3,697
Total Proved Reserves	7,769	454	1,754	9,977

The Company’s natural gas wells are generally low-risk, having a long reserve life with relatively low development and production costs on a per unit basis. Assuming that future annual production from these reserves is consistent with 2015, the remaining reserve life of the Company’s total proved reserves, as calculated by dividing total proved reserves by calendar year 2015 produced volumes, is 16 years.

The Company invested approximately $1,670 million on well development during 2015, with total production sales volumes hitting a record high of 603.1 Bcfe, an increase of 27% over the previous year. Capital spending for EQT Production is expected to be approximately $820 million in 2016 (excluding business development and land acquisitions), the majority of which will be used to support the drilling of approximately 77 gross wells, including 72 Marcellus wells and 5 deep Utica wells. During the past three years, the Company’s number of wells drilled (spud) and related capital expenditures for well development were:



	Years Ended December 31,
	2015		2014		2013
Gross wells spud:
Horizontal Marcellus*	157		237		168
Other	4		108		57
Total	161		345		225

Capital expenditures for well development (in millions):
Horizontal Marcellus*	$	1,527	$	1,456	$	1,103
Other	143		261		134
Total	$	1,670	$	1,717	$	1,237

* Includes Upper Devonian formations.

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EQT Midstream Business Segment

The Company believes that the current footprint of its midstream assets, which are primarily owned by EQM and span a wide area of the Marcellus and Utica Shales in southwestern Pennsylvania and northern West Virginia, is a competitive advantage that uniquely positions the Company for growth. EQT Midstream is strategically positioned to capitalize on the increasing need for gathering and transmission infrastructure in the region, such as the need for midstream header connectivity to interstate pipelines in Pennsylvania and West Virginia.

In January 2012, the Company formed EQM, a publicly traded limited partnership, to own, operate, acquire and develop midstream assets in the Appalachian Basin. EQM provides midstream services to the Company and third parties through its two primary assets: EQM’s transmission and storage system and EQM’s gathering system.

Due to the Company's ownership and control of EQGP and EQM, the results of EQGP and EQM are both consolidated in the Company’s financial statements. Unless otherwise noted, discussions of EQT Midstream’s business, operations and results in this Annual Report on Form 10-K include EQGP's and EQM’s business, operations and results. The Company records the noncontrolling interests of the public limited partners of EQGP and EQM in its financial statements.

EQT Midstream’s gathering system includes approximately 8,250 miles of gathering lines, including 1,500 miles of FERC-regulated, low pressure gathering lines owned by EQM and 185 miles of high pressure gathering lines not subject to federal rate regulation owned by EQM. The left-hand map on page 12 depicts the Company’s gathering lines and compressor stations in relationship to the Marcellus Shale formation. As of December 31, 2015, the Company's Marcellus gathering capacity was approximately 2,000 MMcf per day, consisting of approximately 1,405 MMcf per day in Pennsylvania and approximately 595 MMcf per day in West Virginia.

EQT Midstream’s transmission and storage system includes approximately 900 miles of FERC-regulated interstate pipeline that connects to seven interstate pipelines and multiple distribution companies. The interstate pipeline system includes approximately 700 miles of pipe owned by Equitrans, L.P. (Equitrans), an indirect wholly owned subsidiary of EQM. EQT Midstream’s transmission and storage system also includes an approximately 200-mile pipeline referred to as the Allegheny Valley Connector (AVC), which was acquired by the Company in December 2013 in connection with the Equitable Gas Transaction (as described in Note 2 to the Consolidated Financial Statements).

The transmission and storage system is supported by eighteen natural gas storage reservoirs with approximately 660 MMcf per day of peak delivery capability and 47 Bcf of working gas capacity. Fourteen of these reservoirs, representing approximately 400 MMcf per day of peak delivery capability and 32 Bcf of working gas capacity, are owned by EQM. The storage reservoirs are clustered in two geographic areas connected to EQM’s transmission and storage system, with ten in southwestern Pennsylvania and eight in northern West Virginia. The AVC facilities, which include four storage reservoirs, are owned by the Company and operated by EQM under a lease between EQM and an affiliate of the Company.

The right-hand map on page 12 depicts the Company’s transmission lines, storage pools and compressor stations in relationship to the Marcellus Shale formation. EQT Midstream's year-end total transmission capacity was approximately 3,550 MMcf per day. EQT Midstream, primarily through EQM, began several multi-year transmission capacity expansion projects in 2015 to support the continued growth of the Marcellus and the developing deep Utica play, including the OVC which is currently under construction. EQM is also evaluating several projects that could total an additional 1.5 Bcf per day of capacity by year-end 2018. The projects may include additional compression, pipeline looping and new header pipelines.

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EQT Midstream also has a gas marketing affiliate, EQT Energy, LLC (EQT Energy), that provides optimization of capacity and storage assets through its NGL and natural gas sales to marketers, utilities and industrial customers within EQT's operational footprint. EQT Energy also provides marketing services and manages approximately 1,740,000 Dth per day of third-party contractual pipeline capacity for the benefit of EQT Production; and has committed to an additional 520,000 Dth per day of third-party contractual capacity expected to come online in future periods. EQT Energy currently leases 3.7 Bcf of storage-related assets from third parties.

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Strategy

EQT’s strategy is to maximize shareholder value by maintaining an industry leading cost structure, and, despite a reduced capital budget in 2015 that is reflective of the current price environment, profitably developing its undeveloped reserves, and effectively and efficiently utilizing its extensive gathering and transmission assets that are uniquely positioned across the Marcellus and Utica Shales and in close proximity to the northeastern United States markets.

EQT believes that it is a technology leader in extended-lateral horizontal drilling and completion in the Appalachian Basin and continues to improve its operations through the use of new technology. Substantially all of the Company’s acreage is held by production or in fee; therefore, EQT Production is able to develop its acreage in the most economical manner through the use of longer laterals and multi-well pads, as opposed to being required to drill less-economical wells in order to retain acreage. The use of multi-well pads, in conjunction with a completion technique known as reduced cluster spacing, has the additional benefit of reducing the overall environmental surface footprint of the Company’s drilling operations.

EQT also believes that its midstream assets are strategically located in the Marcellus and Utica Shale regions – spanning a large, prolific area of southwestern Pennsylvania and northern West Virginia – providing a competitive advantage that uniquely positions the Company for continued growth. EQT Midstream, primarily through EQM, intends to capitalize on the growing need for gathering and transmission infrastructure in this region, and in particular the need for midstream header connectivity to interstate pipelines in Pennsylvania and West Virginia. In order to meet this growing need, EQM has been focusing on a number of gathering and transmission projects, including the following:

•

The OVC is a 37-mile pipeline that will extend EQM's transmission and storage system from northern West Virginia to Clarington, Ohio, at which point it will interconnect with the Rockies Express Pipeline and may interconnect with other pipelines and liquidity points. The OVC will provide approximately 850 BBtu per day of transmission capacity with an aggregate compression of approximately 38,000 horsepower. The Company has entered into a 20-year precedent agreement for a total of 650 BBtu per day of firm transmission capacity on the OVC. EQM received its FERC certificate to construct and operate the OVC on December 30, 2015 and construction began in January 2016. EQM expects the OVC to be in-service by year-end 2016.

•

As of February 11, 2016, EQM owned a 45.5% interest in the MVP Joint Venture, which was formed to construct the MVP. The proposed pipeline is expected to be approximately 300 miles long, span from EQM's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia and be designed to transport natural gas production from the Marcellus and Utica Shale regions to the growing demand markets in the southeast region of the United States. The MVP Joint Venture submitted the MVP certificate application to the FERC in October 2015 and anticipates receiving the certificate in the fourth quarter of 2016. Subject to FERC approval, construction is scheduled to begin shortly thereafter and the pipeline is expected to be in-service during the fourth quarter of 2018.

The ongoing efforts of EQGP and EQM are an important support mechanism for EQT’s overall business strategy. Through capitalizing on economically attractive organic growth opportunities, attracting additional third-party volumes, and pursuing accretive acquisitions from the Company, EQM is expected to grow profitably and provide an ongoing source of capital to the Company.

See “Capital Resources and Liquidity” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report on Form 10-K for details regarding the Company’s capital expenditures.

Markets and Customers

Natural Gas Sales: The Company’s produced natural gas is sold to marketers, utilities and industrial customers located mainly in the Appalachian Basin and the Northeastern United States. The Company’s current transportation portfolio also enables the Company to reach markets along the Gulf Coast and Midwestern portions of the United States. Natural gas is a commodity and therefore the Company typically receives market-based pricing. The market price for natural gas in the Appalachian Basin continues to be lower relative to the price at Henry Hub located in Louisiana (the location for pricing NYMEX natural gas futures) as a result of the increased supply of natural gas in the Northeast region. 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, most of which is hedged at NYMEX natural gas prices. The Company’s hedging strategy and information regarding its derivative instruments is set forth in “Commodity Risk Management” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” and in Notes 1 and 6 to the Consolidated Financial Statements.

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The Company is also helping to build additional demand for natural gas. In mid-2011, EQT opened a public-access natural gas fueling station in Pittsburgh, Pennsylvania and, with the growing demand for compressed natural gas for numerous fleets throughout the region, the station underwent an expansion in 2013, adding two more dispensers. In conjunction with this project, the Company is promoting the use of natural gas with its own fleet vehicles and plans to operate 14% of its light-duty vehicle fleet, more than 175 vehicles, on natural gas by the end of 2016. In addition, all of the Company's contracted drilling rigs and completion crews utilize natural gas.

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. In its Appalachian operations, the Company contracts with MarkWest Energy Partners, L.P. (MarkWest), a wholly owned subsidiary of MPLX LP, to process natural gas in order to extract heavier liquid hydrocarbons (propane, iso-butane, normal butane and natural gasoline) from the natural gas stream, primarily from EQT Production’s produced gas. NGLs are recovered at the processing plants and transported to a fractionation plant owned by MarkWest for separation into commercial components. MarkWest markets these components for a fee. The Company also has contractual processing arrangements in its Permian Basin operations whereby the Company sells gas to third-party processors at a weighted average liquids component price.

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



	2015		2014		2013
Average sales price per Mcfe sold (excluding cash settled derivatives)	$	1.96	$	4.14	$	3.81
Average sales price per Mcfe sold (including cash settled derivatives)	$	2.67	$	4.16	$	4.20

In addition, price information for all products is included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” under the caption “Consolidated Operational Data,” and incorporated herein by reference.

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 four major interstate pipelines: Columbia Gas Transmission, East Tennessee Natural Gas Company, Dominion Transmission and Tennessee Gas Pipeline Company. The gathering system also maintains interconnections with EQM’s transmission and storage system.

Gathering system transportation volumes for 2015 totaled 754.3 TBtu, of which approximately 89% related to gathering for EQT Production and other affiliates. Revenues from EQT Production and other affiliates accounted for approximately 92% of 2015 gathering revenues.

Natural Gas Transmission and Storage: Natural gas transmission and storage operations are executed using transmission and underground storage facilities owned by the Company. Customers of EQT Midstream’s gas transmission and storage services are affiliates and third parties primarily in the northeastern United States.

As of December 31, 2015, the weighted average remaining contract life based on total projected contracted revenues for EQM’s firm transmission and storage contracts, including contracts on the AVC and contracts associated with expected future capacity from EQM expansion projects that are not yet fully constructed but for which EQM has entered into firm agreements, was approximately 17 years. In 2015, approximately 61% of transportation volumes and 53% of transmission revenues were from affiliates.

Natural Gas Marketing: EQT Energy provides marketing services and third-party contractual pipeline capacity management for the benefit of EQT Production. EQT Energy also engages in risk management and hedging activities on behalf of EQT Production, the objective of which is to limit the Company’s exposure to shifts in market prices. EQT Energy leases third-party storage capacity in order to take advantage of seasonal spreads, where available, through the EQT Midstream segment.

One customer within the EQT Production segment accounted for approximately 10%, 12% and 11% of EQT Production’s total operating revenues in 2015, 2014 and 2013, respectively. The Company does not believe that the loss of this customer would have a material adverse effect on its business because alternative customers for the Company’s natural gas are available.

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Competition

Natural gas producers compete in the acquisition of properties, the search for and development of reserves, the production, transportation 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. Competition for natural gas gathering, transmission and storage volumes is primarily based on rates and other commercial terms, customer commitment levels, timing, performance, reliability, service levels, location, reputation and fuel efficiencies. Key competitors in the natural gas transmission and storage market include companies that own major natural gas pipelines. Key competitors for gathering systems include independent gas gatherers and integrated energy companies. EQT competes with numerous companies when marketing natural gas and NGLs. Some of these competitors are affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users.

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, well stimulation, hydraulic fracturing 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 royalties and taxes; and the gathering of production in certain circumstances. These regulations and any delays in obtaining related authorizations may affect the costs and timing 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; setbacks; 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. Kentucky, Ohio, Virginia and, for Utica or other deep wells, West Virginia allow the statutory pooling or integration of tracts to facilitate development and exploration. In West Virginia, the Company must rely on voluntary pooling of lands and leases for Marcellus and Upper Devonian acreage. In 2013, the Pennsylvania legislature enacted lease integration legislation, which authorizes joint development of existing contiguous leases, and Texas permits similar joint development. In addition, state conservation and oil and gas laws generally limit the venting or flaring of natural gas, and Texas sets production allowances on the amount of annual production permitted from a well.

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 and other permitting requirements; 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 and transmission facilities. These regulations may increase the costs of operating existing pipelines and compressor stations and increase the costs of, and the time to develop, new or expanded pipelines and compressor stations.

The interstate natural gas transmission systems and storage operations of EQT Midstream are regulated by the FERC, and certain gathering lines are also subject to rate regulation by the FERC. For instance, the FERC approves tariffs that establish EQM’s rates, cost recovery mechanisms and other terms and conditions of service to EQM’s customers. The fees or rates established under EQM’s tariffs are a function of its costs of providing services to customers, including a reasonable return on invested capital. The FERC’s authority over transmission operations also extends to: storage and related services; certification and construction of new interstate transmission and storage facilities; extension or abandonment of interstate transmission and storage 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.

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relevant to the Company have yet to be finalized. Because significant CFTC rules relevant to natural gas hedging activities are still at the proposal stage, it is not possible at this time to predict the extent of the impact of the regulations on the Company’s hedging program or regulatory compliance obligations. The Company has experienced increased, and expects additional, compliance costs and changes to current market practices as participants continue to adapt to a changing regulatory environment.

Regulators periodically review or 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 the U.S. Congress, the states, regulatory agencies and the courts. The Company cannot predict when or whether any such proposals may become effective or the effect that such proposals may have on the Company.

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; pollution; site remediation; and preservation or protection of human health and safety, natural resources, wildlife and the environment. The Company must take into account environmental, health and safety regulations in, among other things, planning, designing, constructing (including drilling), operating and abandoning wells, pipelines and related facilities.

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 overlying 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. To assess water sources near our drilling locations, the Company conducts baseline and, as appropriate, post-drilling water testing at all water wells within at least 2,500 feet of our drilling pads. 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.

See Note 19 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.

Climate Change

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. The EPA and various states have issued a number of proposed and final laws and regulations that limit greenhouse gas emissions. 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 fossil 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 1,914 employees at the end of 2015, and none are subject to a collective bargaining agreement.

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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.

Composition of Segment Operating Revenues

Presented below are operating revenues for each class of products and services representing greater than 10% of total operating revenues.



	For the Years Ended December 31,
	2015		2014		2013
	(Thousands)
Operating Revenues:
Sales of natural gas, oil and NGLs (a)	$	1,690,360	$	2,132,409	$	1,710,245
Pipeline and marketing services (b)	263,640		256,359		148,932
Gain on derivatives not designated as hedges (c)	385,762		80,942		2,834
Total operating revenues	$	2,339,762	$	2,469,710	$	1,862,011

(a) Reported in EQT Production segment.

(b) Reported in EQT Midstream segment, with the exception of $28.5 million, $40.8 million and ($2.6) million for the years ended December 31, 2015, 2014 and 2013, respectively, which are reported within the EQT Production segment.

(c) Reported in EQT Production segment, with the exception of $0.7 million, ($2.8) million and $3.1 million for the years ended December 31, 2015, 2014 and 2013, respectively, which are reported within the EQT Midstream segment.

Financial Information about Segments

See Note 5 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.

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.

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Item 1A. Risk Factors

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, NGL and oil price volatility, or a prolonged period of low natural gas, NGL and oil prices, may have an adverse effect upon our revenue, profitability, future rate of growth, liquidity and financial position.

Our revenue, profitability, future rate of growth, liquidity and financial position depend upon the prices for natural gas, NGLs and oil. The prices for natural gas, NGLs and oil have historically been volatile, and we expect this volatility to continue in the future. The prices are affected by a number of factors beyond our control, which include: weather conditions and seasonal trends; the supply of and demand for natural gas, NGLs and oil; regional basis differentials; national and worldwide economic and political conditions; the ability to export liquefied natural gas; the effect of energy conservation efforts; the price and availability of alternative fuels; the availability, proximity and capacity of pipelines, other transportation facilities, and gathering, processing and storage facilities; and government regulations, such as regulation of natural gas transportation and price controls. The market prices for natural gas, NGLs and oil were depressed throughout 2015 and the early part of 2016. The average daily prices for NYMEX Henry Hub natural gas ranged from a high of $3.23 per MMBtu to a low of $1.76 per MMBtu from January 1, 2015 through February 10, 2016, and the average daily prices for NYMEX West Texas Intermediate crude oil ranged from a high of $61.43 per barrel to a low of $26.55 per barrel during the same period. In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Northeast region in recent years. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, including Appalachian basis, NGLs and oil and thus cannot predict the ultimate impact of prices on our operations. However, we do expect natural gas and NGL prices, particularly in the Appalachian Basin, to remain depressed during 2016.

Recent decreases in natural gas, NGL and oil prices have resulted in lower revenues, operating income and cash flows. Prolonged low, and/or significant or extended further declines in, natural gas, NGL and oil prices may result in further decreases in our revenues, operating income and cash flows, which may result in further reductions in drilling activity, delays in the construction of new midstream infrastructure and downgrades or other negative rating actions with respect to our credit ratings. Further declines in prices could also adversely affect the amount of natural gas, NGLs and oil that we can produce economically, which may result in the Company having to make significant downward adjustments to the value of our oil and gas and certain midstream properties and could cause us to incur additional non-cash impairment charges to earnings in future periods. See “Impairment of Oil and Gas Properties” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Recent natural gas, NGL and oil price declines have resulted in impairment of certain of our non-core oil and gas properties. Future declines in commodity prices, increases in operating costs or adverse changes in well performance may result in additional write-downs of the carrying amounts of our assets, which could materially and adversely affect our results of operations in future periods.” below. Moreover, a failure to control our development costs during periods of lower natural gas, NGL and oil prices could have significant adverse effects on our earnings, cash flows and financial position. 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, NGL and oil prices may be accompanied by or result in increased well drilling costs, increased production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels. Significant natural gas price increases may subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including 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 derivative contract. 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 is subject to all of the inherent hazards and risks normally incidental to the operations for drilling, producing, transporting and storing natural gas, NGLs and oil, 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

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environmental risks and natural disasters. We also face various threats to the security of our or third parties’ facilities and infrastructure, such as processing plants, compressor stations and pipelines. 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, pollution or other environmental damage, disruptions to our operations, regulatory investigations and penalties and loss of sensitive confidential information. 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 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, access or maintain the necessary infrastructure to successfully deliver gas, NGLs and oil to market may adversely affect our earnings, cash flows and results of operations.

Our delivery of natural gas, NGLs and oil depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and processing facilities. The capacity of transmission, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our natural gas, NGLs and oil. Competition for pipeline infrastructure within the Appalachian Basin 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, primarily through EQM, is intended to address a lack of capacity on, and access to, existing gathering and transmission pipelines as well as 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, natural gas, NGL and oil price volatility, delays in obtaining permits and other government approvals, title and property access problems, geology, compliance by third parties with their contractual obligations to us and other factors. Moreover, if our infrastructure development and maintenance programs are not successfully developed on time and within budget, we may not be able to profitably fulfill our contractual obligations to third parties, including joint venture partners.

We also deliver to and are served by third-party natural gas, NGL and oil transmission, gathering, processing and storage facilities that are limited in number, geographically concentrated and subject to the same risks identified above with respect to our infrastructure development and maintenance programs. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. An extended interruption of access to or service from our or third-party pipelines and facilities for any reason, including cyber-attacks on such pipelines and facilities or service interruptions due to gas quality, could result in adverse consequences to us, such as delays in producing and selling our natural gas, NGLs and oil. In such an event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at prices lower than market prices or at prices lower than we currently project. In addition, some of our third-party contracts involve significant long-term financial commitments on our part. Moreover, our usage of third parties for transmission, 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, NGLs and oil to market.

Also, our producing properties and operations are primarily in the Appalachian Basin, making us vulnerable to risks associated with operating in limited geographic areas. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of natural gas and NGLs produced from this area.

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 future growth rate.

Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our 2016 business plan, we considered allocating capital and other resources to various aspects of our businesses, including well development, reserve acquisitions, exploratory activities, midstream infrastructure, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 2016 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, including the appropriate rate of reserve development, 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 2016 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

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We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures. These transactions involve various inherent risks, such as our ability to obtain the necessary regulatory approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; and our ability to achieve benefits anticipated to result from the transactions. In addition, various factors including prevailing market conditions could negatively impact the benefits we receive from transactions. Joint venture arrangements may restrict our operational and corporate flexibility. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may have little control over, and our joint venture partners may not satisfy their obligations to the joint venture. Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our earnings, cash flows and financial position.

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 and transmission systems and pipelines. Our 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, well stimulation, hydraulic fracturing 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 royalties and taxes; and the gathering of production in certain circumstances. These regulations and any delays in obtaining related authorizations may affect the costs and timing of developing our natural gas resources.

Our 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; setbacks; 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. Some states allow the statutory pooling or integration of tracts to facilitate development and exploration, as well as joint development of existing contiguous leases. In addition, state conservation and oil and gas laws generally limit the venting or flaring of natural gas, and may set production allowances on the amount of annual production permitted from a well.

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, transmission and storage businesses are, in many cases, subject to federal regulation by the FERC, which may prohibit us from realizing a level of return that we believe is appropriate. These restrictions may take the form of lower overall rates, imputed revenue credits, cost disallowances and/or expense deferrals. Certain natural gas gathering facilities are exempted from regulation by the FERC. We believe that many of our natural gas facilities meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a natural gas company, although the FERC has not made a formal determination with respect to the jurisdictional status of those facilities. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation within the industry, so the classification and regulation of some of our facilities may be subject to change based on future determinations by the FERC, the courts or the U.S. Congress. Failure to comply with applicable provisions of the laws governing the regulation and safety of natural gas gathering, transmission and storage facilities, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to $200,000 per day for each violation up to a maximum penalty of $2,000,000 for a related series of violations.

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. In addition to periodic changes to air, water and waste laws, as well as recent EPA initiatives to impose climate change-based air regulations on the industry, the U.S. Congress and various states have been evaluating and, in certain cases, have enacted climate-related legislation and other regulatory initiatives that would

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further 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.

Another area of regulation is hydraulic fracturing, which we utilize 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 or regulation has been proposed or is under discussion at federal, state and local levels. For instance, legislation or regulation banning hydraulic fracturing has been adopted in a number of jurisdictions in which we do not have drilling operations. We cannot predict whether any other such federal, state or local legislation or regulation will be enacted and, if enacted, how it may affect our operations, but enactment of additional laws or regulations could increase our operating costs, result in delays in production or delivery of natural gas or perhaps even preclude us from drilling wells.

Recent discussions regarding the federal budget have included proposals that could potentially increase and accelerate the payment of federal and collaterally state income taxes of independent producers with the potential repeal of the ability to expense intangible drilling costs having the most significant potential future impact to us. 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 earnings, cash flows and financial position.

In 2010, the U.S. Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivative market and entities, such as the Company, that participate in that market. The legislation, known as the Dodd-Frank Act, required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation. As of the filing date of this Annual Report, the CFTC had adopted and implemented many final rules that impose regulatory obligations on all market participants, including us, such as recordkeeping and certain reporting obligations. Other rules that may be relevant to us or our counterparties have yet to be finalized. Because significant rules relevant to natural gas hedging activities are still at the proposal stage, it is not possible at this time to predict the extent of the impact of the regulations on our hedging program, including available counterparties, or regulatory compliance obligations. We have experienced increased, and anticipate additional, compliance costs and changes to current market practices as participants continue to adapt to a changing regulatory environment.

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

We and EQM 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 flows from operations or other sources. Future challenges in the global financial system, including access to capital markets and changes in the terms of and cost of capital, including increases in interest rates, may adversely affect our or EQM's business and financial condition. Our and EQM's ability to access the capital markets may be restricted at a time when we or EQM desire, or need, to raise capital, which could have an impact on our or EQM's flexibility to react to changing economic and business conditions or our ability to implement our business strategies. 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, NGLs and oil which could have a negative impact on our and EQM's revenues and credit ratings.

As of February 10, 2016, our long-term debt was rated “Baa3” by Moody’s Investors Services (Moody’s), “BBB” by Standard & Poor’s Ratings Service (S&P), and “BBB-” by Fitch Ratings Service (Fitch), and EQM's long-term debt was rated "Ba1" by Moody's, "BBB-" by S&P, and "BBB-" by Fitch. Although we are not aware of any current plans of Moody’s, S&P or Fitch to lower their respective ratings on our or EQM's debt, we cannot be assured that our or EQM's credit ratings will not be downgraded or withdrawn entirely by a rating agency. On December 16, 2015, Moody's announced that it had placed 29 U.S. exploration and production companies, including the Company, under review for a downgrade due to the low commodity price environment. On January 25, 2016, Moody’s also announced that it had placed three midstream partnerships, including EQM, under review for a downgrade primarily due to their affiliations with sponsoring exploration and production companies. Low prices for natural gas, NGLs and oil or an increase in the level of our indebtedness in the future may result in a downgrade in the ratings that are assigned to our or EQM's debt. If Moody’s or another credit rating agency downgrades the ratings, particularly below investment grade, our or EQM’s access to the capital markets may be limited, borrowing costs and margin deposits on our

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derivatives would increase, we may be required to provide additional credit assurances in support of pipeline capacity contracts, the amount of which may be substantial, or we or EQM may be required to provide additional credit assurances related to joint venture arrangements or construction contracts, which could adversely affect our business, results of operations and liquidity. Investment grade refers to the quality of a company’s credit as assessed by one or more credit rating agencies. In order to be considered investment grade, the Company must be rated “BBB-“ or higher by S&P, “Baa3” or higher by Moody’s and “BBB-“ or higher by Fitch.

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.

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, oil spills, the explosion of natural gas transmission and gathering lines and concerns raised by advocacy groups about hydraulic fracturing and pipeline projects, may lead to increased regulatory scrutiny which may, in turn, lead to new local, state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions 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.

Cyber incidents may adversely impact our operations.

Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, to operate our production and midstream businesses, and the maintenance of our financial and other records has long been dependent upon such technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas, NGLs and oil, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

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 well 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 natural gas, NGLs and oil to market. Moreover, an incorrect determination of legal title to our wells could result in liability to the owner of the natural gas or oil rights and an impairment to our assets. Successfully identifying production opportunities involves a high degree of business experience, knowledge and careful evaluation of potential opportunities, along with subjective judgments and assumptions that may prove to be incorrect. For example, seismic data is subject to interpretation and may not accurately identify the presence of natural gas or other hydrocarbons. Certain of our future drilling activities may not be successful and, if unsuccessful, this failure could adversely affect our business, results of operations or liquidity. 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.

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Recent natural gas, NGL and oil price declines have resulted in impairment of certain of our non-core oil and gas properties. Future declines in commodity prices, increases in operating costs or adverse changes in well performance may result in additional write-downs of the carrying amounts of our assets, which could materially and adversely affect our results of operations in future periods.

We review the carrying values of our proved oil and gas properties generally on a field-by-field basis for indications of impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. The estimated future cash flows used to test those properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable reserves, utilizing assumptions generally consistent with the assumptions utilized by the Company’s management for internal planning and budgeting purposes, including, among other things, the use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil, future operating costs and inflation. Commodity pricing is estimated by using a combination of the five-year NYMEX forward strip prices and assumptions related to gas quality, basis and inflation. Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value.

Our estimate of the fair value of our assets depends on the prices of natural gas, NGLs and oil. Primarily as a result of declines in the five-year NYMEX forward strip prices during 2015, we recorded non-cash, pre-tax impairment charges of $94.3 million and $105.2 million to our proved oil and gas properties in the non-core Permian basin during 2015 and 2014, respectively. Further declines in natural gas, NGL or oil prices, increases in operating costs or adverse changes in well performance, among other things, may result in our having to make significant future downward adjustments to our estimated proved reserves and/or could result in additional non-cash impairment charges to write-down the carrying amount of our oil and gas properties, which may have a material adverse effect on our results of operations in future periods. See “Impairment of Oil and Gas Properties” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The amount and timing of actual future natural gas, NGL and oil 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, a qualified work force, and adequate capacity for the treatment and recycling or disposal of waste water generated in our operations, as well as weather conditions, natural gas, NGL and oil price volatility, government approvals, title and property access problems, geology, equipment failure or accidents and other factors. Drilling for natural gas, NGLs and oil can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit. Additionally, a failure to effectively and efficiently operate existing wells may cause production volumes to fall short of our projections. Without continued successful development or acquisition activities, together with effective operation of existing wells, our reserves and revenues will decline as a result of our current reserves being depleted by production.

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 earnings, cash flows and financial position.

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, NGL 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, NGLs and oil reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve 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, the amount, timing and cost of actual production and changes in governmental regulations or taxation. In addition, the 10% discount factor we use when calculating the 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.

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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, some of which are beyond our control. These estimates and assumptions are inherently imprecise, and we may adjust our estimates of proved reserves based on changes in these estimates or assumptions. 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 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 (i) 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 (ii) 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 3.4 million gross acres (approximately 72% of which are considered undeveloped), which encompass substantially all of the Company’s acreage of proved developed and undeveloped natural gas and oil producing properties. Approximately 630,000 of these gross acres are located in the Marcellus play. 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, 2015, the Company estimated its total proved reserves to be 10.0 Tcfe, consisting of proved developed producing reserves of 5.8 Tcfe, proved developed non-producing reserves of 0.5 Tcfe and proved undeveloped reserves of 3.7 Tcfe. Substantially all of the Company’s reserves reside in continuous accumulations.

The Company’s estimate of proved natural gas, NGL and oil reserves is 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 Chemical Engineering from the Pennsylvania State University and has 18 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, division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems, and the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management.

The Company’s estimate of proved natural gas, NGL 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. In the course of its audit, Ryder Scott reviewed 100% of the total net natural gas, NGL and oil proved reserves attributable to the Company’s interests as of December 31, 2015. Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 80% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining approximately 20% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 230 wells per case for non-operated wells. For undeveloped locations, the Company determined, and Ryder Scott reviewed and approved, the areas within the Company’s acreage considered to be proven. For undeveloped locations, reserves were assigned and projected by the Company’s reserves engineers for locations within these proven areas and approved by Ryder Scott based on analogous type curves and offset production information. Ryder Scott’s audit report has been filed herewith as Exhibit 99.

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, NGL 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 2015, the Company commenced drilling operations (spud or drilled) on 157 gross horizontal wells with an aggregate of approximately 868,000 feet of pay in the Marcellus, including Upper Devonian, play. Total proved reserves in the Marcellus play decreased 6% to 7.8 Tcfe in 2015 primarily as a result of the Company’s decision to reduce the scale of its five-year development plan and associated proved undeveloped reserves in response to a reduction in commodity prices. Total proved reserves in the Huron play decreased approximately 10% to 1.1 Tcfe due to the Company's decision to cease development in this play. Production sales volumes in 2015 from the Marcellus, including the Upper Devonian play, was 505.1 Bcfe. Over the past four years, the Company has experienced a 99% developmental drilling success rate.

Natural gas, NGLs and crude oil pricing:



	For the Years Ended December 31,
	2015		2014		2013
Natural Gas:
Average sales price (excluding cash settled derivatives) ($/Mcf)	$	2.54	$	4.51	$	4.18
Average sales price (including cash settled derivatives) ($/Mcf)	$	3.32	$	4.53	$	4.60
Average sales price (including cash settled derivatives and third-party gathering and transmission costs) ($/Mcf)	$	2.79	$	3.98	$	4.00
NGLs:
Average sales price including third-party processing costs ($/Bbl)	$	7.15	$	32.44	$	36.80
Crude Oil:
Average sales price ($/Bbl)	$	38.70	$	78.51	$	85.82

NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods.

For additional information on pricing, see “Consolidated Operational Data” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The Company’s average per unit production cost, excluding production taxes, of natural gas, NGLs and oil during 2015, 2014 and 2013 was $0.12 per Mcfe, $0.14 per Mcfe and $0.15 per Mcfe, respectively. At December 31, 2015, the Company had approximately 50 multiple completion wells.



	Natural Gas	Oil
Total productive wells at December 31, 2015:
Total gross productive wells	13,430	105
Total net productive wells	12,703	101
Total in-process wells at December 31, 2015:	0
Total gross in-process wells	192	—
Total net in-process wells	191	—

Summary of proved natural gas, oil and NGL reserves as of December 31, 2015 based on average fiscal year prices:



	Natural Gas (MMcf)	Oil and NGLs (Bbls)
Developed	5,652,989	104,428
Undeveloped	3,457,322	39,953
Total proved reserves	9,110,311	144,381



Total acreage at December 31, 2015:
Total gross productive acres	957,245
Total net productive acres	921,809
Total gross undeveloped acres	2,455,116
Total net undeveloped acres	2,220,336

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As of December 31, 2015, the Company had no proved undeveloped reserves that remained undeveloped for more than five years.

Certain lease and acquisition agreements require the Company to drill a specific number of wells in 2016. Within the Marcellus formation, the Company is required to drill one well in 2016, which the Company intends to accomplish either directly through its 2016 development program or indirectly by contracting with a third party to do so, including through an assignment of the lease, farmout or other arrangement.

As of December 31, 2015, leases associated with approximately 34,147 gross undeveloped acres expire in 2016 if they are not renewed. This acreage is in addition to the acreage that may be lost if drilling obligations are not met. The Company has an active lease renewal program in areas targeted for development.

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



	For the Years Ended December 31,
	2015	2014	2013
Exploratory wells:
Productive	1	—	—
Dry	1	—	—
Development wells:
Productive	234.5	265.4	138.4
Dry	3	—	2

Selected production, sales and acreage data by state (as of December 31, 2015 unless otherwise noted), which is substantially all from the Appalachian Basin. NGLs and oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods. Refer to table on page 35 for sales volumes by final product.



	Pennsylvania		West Virginia		Kentucky		Other (b)		Total
Natural gas, oil and NGL production (MMcfe) – 2015 (a)	327,616		208,376		65,726		16,968		618,686
Natural gas, oil and NGL production (MMcfe) – 2014 (a)	237,365		164,330		66,775		19,609		488,079
Natural gas, oil and NGL production (MMcfe) – 2013 (a)	196,250		103,861		65,467		22,811		388,389

Natural gas, oil and NGL sales (MMcfe) – 2015	329,626		200,121		57,825		15,510		603,082
Natural gas, oil and NGL sales (MMcfe) – 2014	240,685		158,868		58,790		17,917		476,260
Natural gas, oil and NGL sales (MMcfe) – 2013	201,653		96,710		58,759		21,051		378,173

Average net revenue interest of proved reserves (%)	82.9	%	85.5	%	93.0	%	79.4	%	84.9	%

Total gross productive wells	1,120		5,053		5,702		1,660		13,535
Total net productive wells	1,108		4,814		5,393		1,489		12,804

Total gross productive acreage	110,098		278,629		442,660		125,858		957,245
Total gross undeveloped acreage	297,782		875,496		1,062,317		219,521		2,455,116
Total gross acreage	407,880		1,154,125		1,504,977		345,379		3,412,361

Total net productive acreage	109,210		276,782		436,020		99,797		921,809
Total net undeveloped acreage	276,245		764,496		982,822		196,773		2,220,336
Total net acreage	385,455		1,041,278		1,418,842		296,570		3,142,145

(Amounts in Bcfe)
Proved developed producing reserves	2,612		1,787		1,258		158		5,815
Proved developed non-producing reserves	256		209		—		—		465
Proved undeveloped reserves	2,205		1,492		—		—		3,697
Proved developed and undeveloped reserves	5,073		3,488		1,258		158		9,977

Gross proved undeveloped drilling locations	254		183		—		—		437
Net proved undeveloped drilling locations	244		183		—		—		427

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(a) All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.

(b) Other includes Ohio, Virginia, Maryland and Texas.

The Company sells natural gas primarily within the Appalachian Basin under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves. As of December 31, 2015, the Company’s delivery commitments through 2020 were as follows:



For the Year Ended December 31,		Natural Gas (Bcf)
2016		634
2017		351
2018		230
2019		148
2020		91

Capital expenditures at EQT Production totaled $1,852 million during 2015, including $182 million for the acquisition of properties. The Company invested approximately $1,381 million during 2015 developing proved reserves and approximately $289 million on wells still in progress at year end. During the year ended December 31, 2015, the Company converted 1,527 Bcfe of proved undeveloped reserves to proved developed reserves. The Company had additions to proved developed reserves of 544 Bcfe, the majority of which were from wells spud that had not previously been classified as proved. Proved undeveloped reserves had negative revisions of 2,353 Bcfe in 2015 due primarily to the removal of uneconomic locations and the removal of locations that were no longer expected to be drilled within 5 years. This decrease was partially offset by the addition of 1,665 Bcfe of proved undeveloped reserves. These extensions and discoveries were mainly due to the addition of proved locations in the Company’s Pennsylvania and West Virginia Marcellus play, along with 337 Bcfe attributed to lateral length extensions of proved undeveloped locations booked in 2014. As of December 31, 2015, the Company’s proved undeveloped reserves totaled 3.7 Tcfe, 100% of which is associated with the development of the Marcellus, including Upper Devonian, play. All proved undeveloped drilling locations are expected to be drilled within five years.

The Company’s 2015 extensions, discoveries and other additions totaled 2,051 Bcfe, which exceeded the 2015 production of 619 Bcfe. Of these reserves, 1,328 Bcfe are attributed to the addition of proved undeveloped locations in the Company’s Pennsylvania and West Virginia Marcellus fields, 386 Bcfe are from the development of locations not previously booked as proved, and 337 Bcfe are due to the extension of lateral lengths associated with existing proved undeveloped locations.

Wells located in Pennsylvania are primarily in Marcellus formations with depths ranging from 5,000 feet to 8,000 feet. Wells located in West Virginia are primarily in Marcellus and Huron formations with depths ranging from 2,500 feet to 6,500 feet. Wells located in Kentucky are primarily in Huron formations with depths ranging from 2,500 feet to 6,000 feet. Wells located in other areas are in CBM, Utica and Permian formations with depths ranging from 2,000 feet to 13,500 feet.

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

EQT Midstream: EQT Midstream, which includes EQGP and EQM, owns or operates approximately 8,250 miles of gathering lines and 177 compressor units with approximately 255,000 horsepower of installed capacity, as well as other general property and equipment.



	Kentucky	West Virginia	Virginia	Pennsylvania	Total
Approximate miles of gathering lines	3,515	4,065	400	270	8,250

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.

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EQT Midstream also owns and operates a FERC-regulated transmission and storage system. These operations consist of an approximately 900-mile FERC-regulated interstate pipeline system that connects to seven interstate pipelines and multiple distribution companies. The system is supported by 18 associated natural gas storage reservoirs with approximately 660 MMcf per day of peak delivery capability and 47 Bcf of working gas capacity. The transmission and storage system stretches throughout northern West Virginia and southwestern Pennsylvania.

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

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

See “Capital Resources and Liquidity” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a discussion of capital expenditures.

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 and 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.

Environmental Proceedings

In June and August 2012, the Company received three Notices of Violation (NOVs) from the Pennsylvania Department of Environmental Protection (the PADEP). The NOVs alleged violations of the Pennsylvania Oil and Gas Act and Clean Streams Law in connection with the unintentional release in May 2012, by a Company vendor, of water from an impaired water pit at a Company well location in Tioga County, Pennsylvania. Since confirming a release, the Company has cooperated with the PADEP in remediating the affected areas.

During the second quarter of 2014, the Company received a proposed consent assessment of civil penalty from the PADEP that proposed a civil penalty related to the NOVs. The Company was unable to resolve the PADEP claims due to the agency’s interpretation of the penalty provisions of the Clean Streams Law. Accordingly, on September 19, 2014, the Company filed a declaratory judgment action in the Commonwealth Court of Pennsylvania against the PADEP seeking a court ruling on the legal interpretation. The Commonwealth Court upheld the PADEP’s preliminary objections to the Company’s complaint, and the Company appealed that decision to the Pennsylvania Supreme Court. On October 7, 2014, the PADEP filed a complaint against the Company before the Pennsylvania Environmental Hearing Board seeking $4.53 million in civil penalties. On December 29, 2015, the Pennsylvania Supreme Court reversed the Commonwealth Court and reinstated the Company’s declaratory judgment in the Commonwealth Court. The Company believes the PADEP’s penalty assessment is legally flawed and unsupportable under the Clean Streams Law. While the Company expects the PADEP’s claims to result in penalties that exceed $100,000, the Company expects the resolution of these matters, individually and in the aggregate, will not have a material impact on the financial position, results of operations or liquidity of the Company.

The Company has received a number of other NOVs from environmental agencies in some of the states in which the Company operates alleging various violations of oil and gas, air, water and waste regulations. The Company has responded to these NOVs and has, where applicable, substantially corrected or remediated the areas in question. The Company disputes a number of the alleged NOVs and cannot predict with certainty whether any or all of these NOVs will result in penalties. If penalties are imposed, an individual penalty or the aggregate of these penalties could result in monetary sanctions in excess of $100,000.

Item 4. Mine Safety Disclosures

Not Applicable.

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Executive Officers of the Registrant (as of February 11, 2016)



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

Theresa Z. Bone (52)	Vice President, Finance and Chief Accounting Officer (2007)	Elected to present position October 2013; Vice President and Corporate Controller from July 2007 to October 2013. Ms. Bone is also Vice President, Finance and Chief Accounting Officer of each of EQT Midstream Services, LLC, the general partner of EQM, since October 2013, and EQT GP Services, LLC, the general partner of EQGP, since January 2015. Ms. Bone was Vice President and Principal Accounting Officer of EQT Midstream Services, LLC from January 2012 to October 2013.

Philip P. Conti (56)	Senior Vice President and Chief Financial Officer (2000)	Elected to present position February 2007. Mr. Conti is also Senior Vice President, Chief Financial Officer and a Director of each of EQT Midstream Services, LLC, the general partner of EQM, since January 2012, and EQT GP Services, LLC, the general partner of EQGP, since January 2015. As previously disclosed in a Form 8-K filed with the SEC on August 10, 2015, Mr. Conti has advised the Company that he intends to retire at the end of 2016. The Company has retained an executive search firm to help identify his successor. Following the appointment of his successor, Mr. Conti is expected to continue to serve as an employee of the Company in some capacity through 2016 to ensure a smooth transition.

Randall L. Crawford (53)	Senior Vice President, EQT Corporation and President, Midstream and Commercial (2003)	Elected to present position December 2013; Senior Vice President, EQT Corporation and President, Midstream, Distribution and Commercial from April 2010 to December 2013. Mr. Crawford is also Executive Vice President, Chief Operating Officer and a Director of EQT Midstream Services, LLC, the general partner of EQM, since December 2013. Mr. Crawford was Executive Vice President and a Director of EQT Midstream Services, LLC from January 2012 to December 2013.

Lewis B. Gardner (58)	General Counsel and Vice President, External Affairs (2008)	Elected to present position March 2008. Mr. Gardner is also a Director of each of EQT Midstream Services, LLC, the general partner of EQM, since January 2012, and EQT GP Services, LLC, the general partner of EQGP, since January 2015.

Charlene Petrelli (55)	Vice President and Chief Human Resources Officer (2003)	Elected to present position February 2007.

David L. Porges (58)	Chairman and Chief Executive Officer (1998)	Elected to present position December 2015; Chairman, President, and Chief Executive Officer from May 2011 to December 2015; President, Chief Executive Officer and Director from April 2010 to May 2011. Mr. Porges is also Chairman, President and Chief Executive Officer of each of EQT Midstream Services, LLC, the general partner of EQM, since January 2012, and EQT GP Services, LLC, the general partner of EQGP, since January 2015.

Steven T. Schlotterbeck (50)	President, EQT Corporation and President, Exploration and Production (2008)	Elected to present position December 2015; Executive Vice President, EQT Corporation and President, Exploration and Production from December 2013 to December 2015; Senior Vice President, EQT Corporation and President, Exploration and Production from April 2010 to December 2013. Mr. Schlotterbeck is also a Director of EQT GP Services, LLC, the general partner of EQGP, since January 2015.

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 elected and qualified, or until death, resignation or removal.

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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 for 2015 and 2014 are summarized as follows (in U.S. dollars per share):



	2015						2014
	High		Low		Dividend		High		Low		Dividend
1st Quarter	$	83.46	$	71.33	$	0.03	$	104.72	$	84.25	$	0.03
2nd Quarter	92.79		80.86		0.03		111.47		95.78		0.03
3rd Quarter	81.67		63.09		0.03		107.71		89.77		0.03
4th Quarter	77.58		47.10		0.03		100.65		74.37		0.03

As of January 31, 2016, there were 2,508 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 upon business conditions, such as the Company’s lines of business, results of operations and financial condition, strategic direction and other factors. The Board of Directors has the discretion to change the annual dividend rate at any time for any reason.

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 occurred during the three months ended December 31, 2015:



Period	Total number of shares purchased (a)	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs (b)
October 2015 (October 1 – October 31)	—	$	—	—	700,000
November 2015 (November 1 – November 30)	8,203	63.49		—	700,000
December 2015 (December 1 – December 31)	3	57.35		—	700,000
Total	8,206	$	63.49	—

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

(b) During 2014, the Company’s Board of Directors approved a share repurchase authorization of up to 1,000,000 shares of the Company’s outstanding common stock. The Company may repurchase shares from time to time in open market or in privately negotiated transactions. The share repurchase authorization does not obligate the Company to acquire any specific number of shares, has no pre-established end date and may be discontinued by the Company at any time. As of December 31, 2015, the Company had repurchased 300,000 shares under this authorization since its inception.

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Stock Performance Graph

The following graph compares the most recent five-year cumulative total return attained by holders of the Company’s common stock with the cumulative total returns of the S&P 500 Index and a customized peer group of the 25 companies listed in footnote (a) below (the Self-Constructed Peer Group). An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2010 in the Company’s common stock, in the S&P 500 Index and in the Self-Constructed Peer Group. Relative performance is tracked through December 31, 2015.



	12/10		12/11		12/12		12/13		12/14		12/15
EQT Corporation	$	100.00	$	124.17	$	135.88	$	207.16	$	174.89	$	120.62
S&P 500	100.00		102.11		118.45		156.82		178.29		180.75
Self-Constructed Peer Group (a)	100.00		102.66		104.91		145.99		129.54		85.54

(a) The Self-Constructed Peer Group includes the following 25 companies: Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Co., Concho Resources, Inc., CONSOL Energy Inc., Continental Resources, Inc., Energen Corporation, EOG Resources, Inc., EXCO Resources, Inc., MarkWest Energy Partners, L.P., National Fuel Gas Company, Newfield Exploration Company, Noble Energy, Inc., ONEOK, Inc., Pioneer Natural Resources Company, QEP Resources, Inc., Questar Corporation, Quicksilver Resources Inc., Range Resources Corporation, SM Energy Company, Southwestern Energy Company, Spectra Energy Corp, Ultra Petroleum Corp., Whiting Petroleum Corporation and The Williams Companies, Inc. MarkWest Energy Partners, L.P. was acquired during 2015 and is included in the calculation from December 31, 2010 through December 31, 2014, at which time it was removed from the peer group calculation.

The Self-Constructed Peer Group is the same peer group used for the Company’s 2015 Executive Performance Incentive Program, which utilizes three-year total shareholder return against the peer group as one performance metric.

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

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Item 6. Selected Financial Data



	As of and for the Years Ended December 31,
	2015		2014		2013		2012		2011
	(Thousands, except per share amounts)
Total operating revenues	$	2,339,762	$	2,469,710	$	1,862,011	$	1,377,222	$	1,323,829

Amounts attributable to EQT Corporation:
Income from continuing operations	$	85,171	$	385,594	$	298,729	$	135,902	$	419,582
Net income	$	85,171	$	386,965	$	390,572	$	183,395	$	479,769

Earnings per share of common stock attributable to EQT Corporation:
Basic:
Income from continuing operations	$	0.56	$	2.54	$	1.98	$	0.91	$	2.81
Net income	$	0.56	$	2.55	$	2.59	$	1.23	$	3.21

Diluted:
Income from continuing operations	$	0.56	$	2.53	$	1.97	$	0.90	$	2.79
Net income	$	0.56	$	2.54	$	2.57	$	1.22	$	3.19
Total assets	$	13,976,172	$	12,035,353	$	9,765,907	$	8,819,750	$	8,741,610
Long-term debt	$	2,793,343	$	2,959,353	$	2,475,370	$	2,496,061	$	2,715,833
Cash dividends declared per share of common stock	$	0.12	$	0.12	$	0.12	$	0.88	$	0.88

Refer to Note 2 to the Consolidated Financial Statements for a description of the Equitable Gas Transaction. Equitable Gas Company, LLC (Equitable Gas) and Equitable Homeworks, LLC (Homeworks) comprised substantially all of the Company’s previously reported Distribution segment. The financial information of Equitable Gas and Homeworks is reflected as discontinued operations in this Annual Report on Form 10-K.

The Company adopted Accounting Standards Update (ASU) No. 2015-03, Interest - Imputation of Interest and ASU No. 2015-15, Interest - Imputation of Interest as of December 31, 2015, which requires an entity to present the debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. All prior periods presented in this Annual Report on Form 10-K have been recast to reflect the change in accounting principle retrospectively applied as of December 31, 2015.

See Item 1A, “Risk Factors”, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 1, 2, 8 and 9 to the Consolidated Financial Statements for a discussion of matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.

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

Consolidated Results of Continuing Operations

2015 EQT Overview:

•Annual production sales volumes of 603.1 Bcfe, 27% higher than 2014

•Marcellus sales volumes of 505.1 Bcfe, 34% higher than 2014

•Gathered volumes of 754.3 TBtu, 28% higher than 2014

•The Company completed EQGP's IPO

•EQM completed two underwritten public offerings of common units representing limited partner interests

Income from continuing operations attributable to EQT Corporation for 2015 was $85.2 million, $0.56 per diluted share, compared with $385.6 million, $2.53 per diluted share, in 2014. The $300.4 million decrease in income from continuing operations attributable to EQT Corporation was primarily attributable to a 36% decrease in the average realized price to EQT Corporation for production sales volumes, higher operating expenses and higher net income attributable to noncontrolling interests of EQM and EQGP, partially offset by a 27% increase in production sales volumes, increased gains on derivatives not designated as hedges, increased gathering and transmission revenues and lower income tax expense. Operating expenses for 2015 and 2014 include $122.5 million and $267.3 million, respectively, of pre-tax, non-cash impairment charges related to the Company's oil and gas properties, which are included in the impairment of long-lived assets in the Statements of Consolidated Income.

The average realized price to EQT Corporation for production sales volumes was $2.67 per Mcfe for 2015 compared to $4.16 per Mcfe for 2014. The decrease in the average realized price was driven by lower NYMEX natural gas prices net of cash settled derivatives, lower NGL prices and a lower average differential, which includes Appalachian Basin basis, recoveries and cash settled basis swaps. Recoveries represent differences in natural gas prices between the Appalachian Basin and other markets reached by utilizing transportation capacity, differences in natural gas prices between Appalachian Basin and fixed price sales contracts, term sales with fixed differentials to NYMEX and other marketing activity, including capacity releases.

The Company's volume weighted average NYMEX natural gas index price was $2.66 per MMBtu for 2015, 39% lower than the average index price of $4.38 per MMBtu in 2014. In addition, the average differential decreased by $0.15 per Mcf, primarily due to lower Appalachian Basin basis. The Company's average NGL price was $18.84 per barrel for 2015, compared to $41.94 per barrel for 2014.

Operating income was $563.1 million in 2015 compared to $853.4 million in 2014, a decrease of $290.3 million. EQT Midstream's operating income increased by $89.1 million in 2015, primarily due to increases in gathering and transmission revenues as a result of production development in the Marcellus Shale, which was more than offset by a $401.1 million decrease in EQT Production's operating income in 2015. The average realized price to EQT Production decreased to $1.74 per Mcfe in 2015 compared to $3.23 per Mcfe in 2014. The decrease in the average realized price to EQT Production was offset by an increase in sales volumes of 27% primarily as a result of increased production from the 2014 and 2013 drilling programs in the Marcellus acreage, partially offset by the normal production decline in the Company’s producing wells. EQT Production total operating revenues for the year ended December 31, 2015 also included $385.1 million of derivative gains for derivative instruments not designated as hedging instruments compared to $83.8 million of derivative gains not designated as hedges and $24.8 million of gains for ineffectiveness of financial hedges for the year ended December 31, 2014. The increased derivative gains for the year ended December 31, 2015 primarily related to favorable changes in the fair market value of EQT Production's NYMEX swaps due to decreased forward NYMEX prices during the year ended December 31, 2015. EQT Production received $170.3 million and $36.5 million of net cash settlements for derivatives not designated as hedges for the years ended December 31, 2015 and 2014, respectively. These net cash settlements are included in the average realized price discussion.

Operating expenses for 2015 were $1,776.6 million compared to $1,650.5 million in 2014, an increase of $126.1 million. This increase was primarily attributable to higher depreciation, depletion, and amortization (DD&A) expense, higher transportation and processing expenses and higher exploration costs, partially offset by a favorable depletion rate and a decrease in the impairment of long-lived assets.

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Income from continuing operations attributable to EQT Corporation for 2014 was $385.6 million, $2.53 per diluted share, compared with $298.7 million, $1.97 per diluted share, in 2013. The $86.9 million increase in income from continuing operations attributable to EQT Corporation was primarily attributable to a 26% increase in production sales volumes, favorable gains on derivatives not designated as hedges, increases in contracted transmission capacity and throughput and gathered volumes, favorable changes in hedging ineffectiveness, and lower interest expense. These factors were partially offset by impairments of long-lived assets, higher net income attributable to noncontrolling interests of EQM, higher transportation and processing expenses, higher income tax expense, higher selling, general and administrative (SG&A) expense and higher DD&A expense.

Operating income was $853.4 million in 2014 compared to $654.6 million in 2013, an increase of $198.8 million. EQT Production sales volumes increased 26% primarily as a result of increased production from the 2014 and 2013 drilling programs in the Marcellus acreage partially offset by the normal production decline in the Company’s producing wells. The average realized price to EQT Production for sales volumes was $3.23 per Mcfe in 2014 compared to $3.15 per Mcfe in 2013. EQT Production total operating revenues for the year ended December 31, 2014 included $83.8 million of derivative gains for derivative instruments not designated as hedging instruments compared to $0.3 million of derivative losses for the year ended December 31, 2013. For the year ended December 31, 2014, EQT Production received $36.5 million of net cash settlements for derivatives not designated as hedges which is included in the average realized price to EQT Production of $3.23 per Mcfe in 2014. The year ended December 31, 2014 also included a $24.8 million gain for hedging ineffectiveness of financial hedges compared to a $21.3 million loss for ineffectiveness of financial hedges for the year ended December 31, 2013.

Transmission operating revenues increased in 2014 compared to 2013, reflecting continued production development in the Marcellus Shale by affiliate and third-party producers. The increase primarily resulted from higher firm transmission contracted capacity and throughput for third parties and EQT Production and higher interruptible transmission service. Gathering revenues increased primarily as a result of higher affiliate volumes gathered in 2014 compared to 2013, driven by production development in the Marcellus Shale. EQT Midstream significantly increased firm reservation fee revenues in 2014 compared to 2013 as a result of increased capacity under firm contracts with affiliates. The decrease in usage fees under interruptible contracts was primarily due to affiliates contracting for additional firm capacity.

Operating expenses for 2014 were $1,650.5 million compared to $1,227.0 million in 2013, an increase of $423.5 million. Excluding a $267.3 million impairment charge and $26.2 million increase in depreciation and depletion, operating expenses increased $130.0 million. This increase was primarily attributable to higher transportation and processing expenses and higher SG&A costs, consistent with the growth in the production and midstream businesses.

See “Other Income Statement Items” for a discussion of other income, interest expense, income taxes, income from discontinued operations and net income attributable to noncontrolling interests, and “Investing Activities” under the caption “Capital Resources and Liquidity” for a discussion of capital expenditures.

Consolidated Operational Data

Revenues earned by the Company from the sale of natural gas, NGLs and oil are split between EQT Production and EQT Midstream. The split is reflected in the calculation of EQT Production’s average realized price. The following operational information presents detailed gross liquid and natural gas operational information as well as midstream deductions to assist in the understanding of the Company’s consolidated operations.

The operational information in the table below presents an average realized price ($/Mcfe) to EQT Production and EQT Corporation, which is based on EQT Production adjusted net operating revenues, a non-GAAP supplemental financial measure. EQT Production adjusted net operating revenues is presented because it is an important measure used by the Company’s management to evaluate period-to-period comparisons of earnings trends. EQT Production adjusted net operating revenues should not be considered as an alternative to EQT Corporation total operating revenues as reported in the Statements of Consolidated Income, the most directly comparable GAAP financial measure. See “Reconciliation of Non-GAAP Measures” following that table for a reconciliation of EQT Production adjusted net operating revenues to EQT Corporation total operating revenues.

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EQT Corporation

Price Reconciliation



	Years Ended December 31,
in thousands (unless noted)	2015			2014			2013
LIQUIDS
NGLs:
Sales volume (MMcfe) (a)	51,530			40,587			27,860
Sales volume (Mbbls)	8,588			6,764			4,643
Gross price ($/Bbl)	$	18.84		$	41.94		$	45.58
Gross NGL sales	$	161,775		$	283,728		$	211,626
Third-party processing	(100,329		)	(64,313		)	(40,754		)
Net NGL sales	$	61,446		$	219,415		$	170,872
Oil:
Sales volume (MMcfe) (a)	4,458			2,693			1,620
Sales volume (Mbbls)	743			449			270
Net price ($/Bbl)	$	38.70		$	78.51		$	85.82
Net oil sales	$	28,752		$	35,232		$	23,171

Net liquids sales	$	90,198		$	254,647		$	194,043

NATURAL GAS
Sales volume (MMcf)	547,094			432,980			348,693
NYMEX price ($/MMBtu) (b)	$	2.66		$	4.38		$	3.67
Btu uplift	$	0.25		$	0.38		$	0.30
Gross natural gas price ($/Mcf)	$	2.91		$	4.76		$	3.97

Basis ($/Mcf)	(1.18		)	(1.07		)	(0.16		)
Recoveries ($/Mcf) (c)	0.81			0.82			0.37
Cash settled basis swaps (not designated as hedges) ($/Mcf)	$	0.03		$	0.06		$	—
Average differential ($/Mcf)	$	(0.34	)	$	(0.19	)	$	0.21

Average adjusted price ($/Mcf)	$	2.57		$	4.57		$	4.18
Cash settled derivatives (cash flow hedges) ($/Mcf)	0.47			(0.06		)	0.42
Cash settled derivatives (not designated as hedges) ($/Mcf)	0.28			0.02			—
Average adjusted price, including cash settled derivatives ($/Mcf)	$	3.32		$	4.53		$	4.60

Net natural gas sales, including cash settled derivatives	$	1,810,897		$	1,962,667		$	1,603,891

TOTAL PRODUCTION
Total net natural gas & liquids sales, including cash settled derivatives	$	1,901,095		$	2,217,314		$	1,797,934
Total sales volume (MMcfe)	603,082			476,260			378,173

Net natural gas & liquids price, including cash settled derivatives ($/Mcfe)	$	3.15		$	4.66		$	4.75

Midstream Deductions ($/Mcfe)
Gathering to EQT Midstream	$	(0.74	)	$	(0.73	)	$	(0.82	)
Transmission to EQT Midstream	(0.19		)	(0.20		)	(0.23		)
Third-party gathering and transmission costs	(0.48		)	(0.50		)	(0.55		)
Total midstream deductions	$	(1.41	)	$	(1.43	)	$	(1.60	)
Average realized price to EQT Production ($/Mcfe)	$	1.74		$	3.23		$	3.15
Gathering and transmission to EQT Midstream ($/Mcfe)	$	0.93		$	0.93		$	1.05
Average realized price to EQT Corporation ($/Mcfe)	$	2.67		$	4.16		$	4.20

(a) NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods.

(b) The Company’s volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/MMBtu) was $2.66, $4.41 and $3.65 for the years ended December 31, 2015, 2014 and 2013, respectively).

(c) Recoveries represent differences in natural gas prices between the Appalachian Basin and other markets reached by utilizing transportation capacity, differences in natural gas prices between Appalachian Basin and fixed price sales contracts, term sales with fixed differentials to NYMEX and other marketing activity, including the sale of unused pipeline capacity. Recoveries include approximately $0.21, $0.19 and $0.23 per Mcf for the years ended December 31, 2015, 2014 and 2013, respectively, for the sale of unused pipeline capacity.

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Reconciliation of Non-GAAP Measures

The table below reconciles EQT Production adjusted net operating revenues, a non-GAAP supplemental financial measure, to EQT Corporation total operating revenues as reported in the Statements of Consolidated Income, its most directly comparable financial measure calculated in accordance with GAAP.

The Company reports gain (loss) for hedging ineffectiveness and gain (loss) on derivatives not designated as hedges within total operating revenues in the Statements of Consolidated Income.

EQT Production adjusted net operating revenues is presented because it is an important measure used by the Company’s management to evaluate period-over-period comparisons of earnings trends. EQT Production adjusted net operating revenues as presented excludes the revenue impact of changes in the fair value of derivative instruments prior to settlement and is net of transportation and processing costs. Management utilizes EQT Production adjusted net operating revenues to evaluate earnings trends because the measure reflects only the impact of settled derivative contracts and thus does not burden the revenue from natural gas sales with the often volatile fluctuations in the fair value of derivatives prior to settlement. EQT Production adjusted net operating revenues also reflects transportation and processing costs as deductions from operating revenues because management considers the net price realized for sales of products, after the costs of processing and transporting the product to sales points, to be an indicator of the quality of earnings period-over-period. Management also considers this to be an indicator of how well the Company is utilizing its transportation and processing contracts. The sale price for natural gas is significantly impacted by the market in which the gas is sold and the expense incurred to transport and process the gas is important in evaluating the quality of earnings period-over-period because the cost of reaching a higher priced market may exceed the incremental price benefit of that market as compared to the market where the gas is produced. This is particularly important to natural gas producers in the Appalachian Basin given pipeline constraints and the impact on pricing in the area. Management further believes that EQT Production adjusted net operating revenues as presented provides useful information for investors for evaluating period-over-period earnings and is consistent with industry practices.



Calculation of EQT Production adjusted net operating revenues	Years Ended December 31,
$ in thousands (unless noted)	2015			2014			2013
EQT Production total operating revenues, as reported on segment page	$	1,540,889		$	1,813,292		$	1,310,938
(Deduct) add back:
(Gain) loss for hedging ineffectiveness	—			(24,774		)	21,335
(Gain) loss on derivatives not designated as hedges	(385,055		)	(83,760		)	301
Net cash settlements received on derivatives not designated as hedges	170,314			36,453			728
Premiums paid for derivatives that settled during the year	(364		)	—			—
EQT Production transportation and processing, as reported on segment page	(274,379		)	(200,562		)	(142,281		)
EQT Production adjusted net operating revenues, a non-GAAP measure	$	1,051,405		$	1,540,649		$	1,191,021

Total sales volumes (MMcfe)	603,082			476,260			378,173

Average realized price to EQT Production ($/Mcfe)	$	1.74		$	3.23		$	3.15
Add:
Gathering and Transmission to EQT Midstream ($/Mcfe)	$	0.93		$	0.93		$	1.05
Average realized price to EQT Corporation ($/Mcfe)	$	2.67		$	4.16		$	4.20

EQT Production total operating revenues, as reported on segment page	$	1,540,889		$	1,813,292		$	1,310,938
EQT Midstream total operating revenues, as reported on segment page	807,904			699,083			614,042
Less: intersegment revenues, net	(9,031		)	(42,665		)	(62,969		)
EQT Corporation total operating revenues, as reported in accordance with GAAP	$	2,339,762		$	2,469,710		$	1,862,011

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Business Segment Results of Operations

Business segment operating results from continuing operations 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. Other income, interest and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Unallocated expenses consist primarily of incentive compensation, administrative costs and for 2013, corporate overhead charges previously allocated to the Company’s Distribution segment that were reclassified to headquarters as part of the recast of those periods to reflect the discontinued operations presentation.

The Company has reported the components of each segment’s operating income from continuing operations 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 business segments without being obscured by the financial condition, operations and trends for the other segment or by the effects of corporate allocations of interest, income taxes and other income. In addition, management uses these measures for budget planning purposes. Purchased gas costs at EQT Midstream include natural gas purchases, including natural gas purchases from affiliates, purchased gas costs adjustments and other gas supply expenses. These purchased gas costs are primarily attributable to transactions with affiliates and are eliminated in consolidation. Consistent with the consolidated results, energy trading contracts recorded within storage, marketing and other revenues are reported net within operating revenues, regardless of whether the contracts are physically or financially settled. The Company has reconciled each segment’s operating income to the Company’s consolidated operating income and net income in Note 5 to the Consolidated Financial Statements.

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EQT Production

Results of Operations



	Years Ended December 31,
	2015		2014		% change 2015 - 2014		2013			% change 2014 - 2013
OPERATIONAL DATA

Sales volume detail (MMcfe):
Marcellus (a)	505,102		378,195		33.6		275,029			37.5
Other (b)	97,980		98,065		(0.1	)	103,144			(4.9	)
Total production sales volumes (c)	603,082		476,260		26.6		378,173			25.9

Average daily sales volumes (MMcfe/d)	1,652		1,305		26.6		1,036			26.0

Average realized price to EQT Production ($/Mcfe)	$	1.74	$	3.23	(46.1	)	$	3.15		2.5

Lease operating expenses (LOE), excluding production taxes ($/Mcfe)	$	0.12	$	0.14	(14.3	)	$	0.15		(6.7	)
Production taxes ($/Mcfe)	$	0.09	$	0.14	(35.7	)	$	0.13		7.7
Production depletion ($/Mcfe)	$	1.18	$	1.22	(3.3	)	$	1.50		(18.7	)

DD&A (thousands):
Production depletion	$	713,651	$	582,624	22.5		$	568,990		2.4
Other DD&A	9,797		10,231		(4.2	)	9,651			6.0
Total DD&A	$	723,448	$	592,855	22.0		$	578,641		2.5

Capital expenditures (thousands) (d)	$	1,852,100	$	2,441,486	(24.1	)	$	1,423,185		71.6

FINANCIAL DATA (thousands)

Revenues:
Production sales	$	1,155,834	$	1,704,758	(32.2	)	$	1,332,574		27.9
Gain (loss) for hedging ineffectiveness	—		24,774		(100.0	)	(21,335		)	(216.1	)
Gain (loss) on derivatives not designated as hedges	385,055		83,760		359.7		(301		)	(27,927.2	)
Total operating revenues	1,540,889		1,813,292		(15.0	)	1,310,938			38.3

Operating expenses:
Transportation and processing	274,379		200,562		36.8		142,281			41.0
LOE, excluding production taxes	70,556		65,917		7.0		57,110			15.4
Production taxes	53,109		67,571		(21.4	)	50,981			32.5
Exploration expense	61,970		21,665		186.0		18,483			17.2
SG&A	134,294		118,816		13.0		92,197			28.9
DD&A	723,448		592,855		22.0		578,641			2.5
Impairment of long-lived assets	118,268		267,339		(55.8	)	—			100.0
Total operating expenses	1,436,024		1,334,725		7.6		939,693			42.0
Gain on sale / exchange of assets	—		27,383		(100.0	)	—			100.0
Operating income	$	104,865	$	505,950	(79.3	)	$	371,245		36.3


(a)	Includes Upper Devonian wells.


(b)	Includes 4,173 MMcfe of deep Utica sales volume for the year ended December 31, 2015.


(c)	NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods.

(d)

Includes $167.3 million of cash capital expenditures and $349.2 million of non-cash capital expenditures for the exchange of assets with Range Resources Corporation (Range) during the year ended December 31, 2014 and $114.2 million of cash capital expenditures for the purchase of acreage and Marcellus wells from Chesapeake Energy Corporation and its partners (Chesapeake) during the year ended December 31, 2013.

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Year Ended December 31, 2015 vs. December 31, 2014

EQT Production’s operating income totaled $104.9 million for 2015 compared to $506.0 million for 2014. The $401.1 million decrease in operating income was primarily due to a lower average realized price to EQT Production and increased operating expenses partially offset by increased sales of produced natural gas and increased gains on derivatives not designated as hedges. Operating expenses included non-cash impairment charges of $118.3 million in 2015 and $267.3 million in 2014. The 2015 impairment charge consisted of impairments of proved properties in the Permian Basin of Texas of $94.3 million and impairments of proved properties in the Utica Shale of Ohio of $4.3 million, as well as $19.7 million for unproved property impairments of non-core Marcellus acreage related to lease expirations. The 2014 impairment charge consisted of impairments of proved properties in the Permian Basin of Texas of $105.2 million and impairments of proved properties in the Utica Shale of Ohio of $75.5 million, as well as impairments of $86.6 million associated with undeveloped properties. The proved properties impairments in 2015 and 2014 were a result of continued declines in commodity prices and insufficient recovery of hydrocarbons to support continued development. The 2015 and 2014 impairments related to the unproved properties were due to operational decisions to focus near-term development activities in the Company's core Marcellus and deep Utica acreage.

Total operating revenues were $1,540.9 million for 2015 compared to $1,813.3 million for 2014. The $272.4 million decrease in total operating revenues was primarily due to a 46% decrease in the average realized price to EQT Production and a prior year gain on hedge ineffectiveness, partly offset by a 27% increase in production sales volumes and increased gains on derivatives not designated as hedges in 2015.

The $1.49 per Mcfe decrease in the average realized price to EQT Production for the year ended December 31, 2015 was primarily due to the decrease in the average NYMEX natural gas price net of cash settled derivatives of $1.06 per Mcf, lower NGL prices and a decrease in the average natural gas differential of $0.15 per Mcf. The average differential for 2015 includes lower Appalachian Basin basis of $0.11 per Mcf. Recoveries per Mcf (also included in the average differential) for the year ended December 31, 2015 were consistent with the year ended December 31, 2014. Recoveries represent differences in natural gas prices between the Appalachian Basin and other markets reached by utilizing transportation capacity, differences in natural gas prices between Appalachian Basin and fixed price sales contracts, term sales with fixed differentials to NYMEX and other marketing activity, including capacity releases. Favorable recoveries in 2015 from fixed price sales contracts were offset by reduced differentials between the Appalachian Basin and ultimate sales prices.

The increase in production sales volumes was primarily the result of increased production from the 2013 and 2014 drilling programs in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s producing wells.

EQT Production total operating revenues for the year ended December 31, 2015 included a $385.1 million gain on derivatives not designated as hedges compared to an $83.8 million gain on derivatives not designated as hedges for the year ended December 31, 2014. The increased gains for the year ended December 31, 2015 primarily related to favorable changes in the fair market value of EQT Production’s NYMEX swaps due to a decrease in forward NYMEX prices during the year ended December 31, 2015. EQT Production received $170.3 million and $36.5 million of net cash settlements for derivatives not designated as hedges for the years ended December 31, 2015 and 2014, respectively. These net cash settlements are included in the average realized price discussion. For the year ended December 31, 2014, EQT Production total operating revenues also included a $24.8 million gain for hedging ineffectiveness.

Operating expenses totaled $1,436.0 million for 2015 compared to $1,334.7 million for 2014. The increase in operating expenses was the result of increases in DD&A, transportation and processing, exploration, SG&A, and LOE expenses, partly offset by decreases in non-cash impairments of long-lived assets and production taxes. The increase in DD&A expense was the result of higher produced volumes partly offset by a lower overall depletion rate in 2015. Transportation and processing expenses increased by $73.8 million due to additional contracted capacity to move EQT Production’s natural gas out of the Appalachian Basin and increased liquids processing fees. Transportation and processing expenses are included in the average realized price to EQT Production. Exploration expense increased $40.3 million due to increased lease expirations of non-core acreage totaling $22.8 million and expenses related to exploratory wells. The increase in SG&A expense was primarily due to higher personnel costs of $14.7 million, including incentive compensation expenses, and $11.2 million of drilling program reduction charges, including rig release penalties, partly offset by $4.2 million of higher litigation and environmental remediation costs in the prior year, a $2.6 million decrease in professional services costs and a $2.4 million reduction to the reserve for uncollectible accounts. The increase in LOE was primarily due to increased Marcellus activity, including a $1.4 million increase in salt water disposal costs, and increased Permian maintenance costs. Production taxes decreased primarily due to a $16.7 million decrease in severance taxes due to lower market sales prices, partly offset by higher production sales volumes in certain jurisdictions subject to these taxes and a $3.6 million increase in property taxes. Production taxes also decreased due to a $1.4 million decrease in the Pennsylvania impact fee, primarily as a result of a decrease in the number of wells drilled in Pennsylvania in 2015.

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Year Ended December 31, 2014 vs. December 31, 2013

EQT Production’s operating income totaled $506.0 million for 2014 compared to $371.2 million for 2013. The $134.8 million increase in operating income was primarily due to increased sales of produced natural gas and NGLs and a higher average realized price partially offset by an increase in operating expenses, which included $267.3 million of noncash impairment charges. Impairment charges consisted of $105.2 million associated with proved properties in the Permian Basin of Texas related to the 2014 decline in commodity prices. Impairment charges also included $86.6 million associated with undeveloped properties and $75.5 million associated with proved properties in the Utica Shale of Ohio as a result of insufficient recovery of hydrocarbons to support continued development along with the decline in commodity prices.

Total operating revenues were $1,813.3 million for 2014 compared to $1,310.9 million for 2013. The $502.4 million increase in total operating revenues was primarily due to a 26% increase in production sales volumes, a favorable gain on derivatives not designated as hedges, a favorable change in hedging ineffectiveness and a 3% increase in the average realized price to EQT Production. The increase in production sales volumes was the result of increased production from the 2014 and 2013 drilling programs, primarily in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s producing wells.

Total operating revenues for the year ended December 31, 2014 included a $24.8 million gain for hedging ineffectiveness of financial hedges compared to a $21.3 million loss for ineffectiveness of financial hedges for the year ended December 31, 2013. The year ended December 31, 2014 also included $83.8 million of derivative gains for derivative instruments not designated as hedging instruments compared to $0.3 million of derivative losses for the year ended December 31, 2013. The gains for the year ended December 31, 2014 related to favorable changes in the fair market value of basis swaps and NYMEX collars that were not designated as hedging instruments, due to decreased forward NYMEX and basis prices as of December 31, 2014. EQT Production received $36.5 million of net cash settlements for derivatives not designated as hedges for the year ended December 31, 2014. These net cash settlements are included in the average realized price.

The $0.08 per Mcfe increase in the average realized price to EQT Production was the net result of an increase in the average NYMEX natural gas price net of cash settled derivatives combined with a per unit decrease in midstream revenue deductions, partly offset by a lower average natural gas differential of $0.40 per Mcf. The average differential included lower Appalachian Basin basis of $0.91 per Mcf, favorable recoveries of $0.45 per Mcf and favorable settlements of basis swaps of $0.06 per Mcf. For the year ended December 31, 2014, EQT Production recognized higher recoveries compared to 2013 primarily by using its contracted transportation capacity to sell gas in higher priced markets, particularly during the winter months when market prices in the United States Northeast region were significantly higher than the Appalachian Basin prices. Much of these higher revenues resulted from sales of the Company’s Texas Eastern Transmission (TETCO) and Tennessee Gas Pipeline capacity, including additional TETCO capacity that came online in 2014. Effective February 2014, the Company acquired new TETCO capacity of 245,000 MMBtu per day that enabled the Company to reach markets in eastern Pennsylvania. Effective November 2014, additional TETCO capacity of 300,000 MMBtu per day came online that enabled the Company to reach markets in New Jersey as well as markets along the Gulf coast. Additionally, the Company executed natural gas sales with fixed differentials to NYMEX for the 2014 summer term during the fourth quarter of 2013 and first quarter of 2014 when market prices were favorable compared to actual Appalachian Basin basis during the summer of 2014.

Operating expenses totaled $1,334.7 million for 2014 compared to $939.7 million for 2013. The increase in operating expenses was the result of impairments of long-lived assets of $267.3 million, as previously mentioned, and increases in SG&A, production taxes, DD&A, LOE and exploration expenses. SG&A expense increased in 2014 primarily as a result of higher personnel costs of $12.4 million, including incentive compensation expenses, higher litigation and environmental reserves of $6.2 million, and an increase in professional services of $4.9 million. Production taxes increased due to an $11.6 million increase in severance taxes and property taxes as a result of higher market sales prices and higher production sales volumes in certain jurisdictions subject to these taxes. Production taxes also increased due to a $5.1 million increase in the Pennsylvania impact fee, primarily as a result of an increase in the number of wells drilled in Pennsylvania in 2014. Depletion expense increased as a result of higher production sales volumes in 2014, partially offset by a lower overall depletion rate. The increase in LOE was mainly a result of increased Marcellus activity in 2014, including a $2.8 million increase in salt water disposal expenses and a $2.7 million increase in labor expenses, along with expenses related to the exchange of properties with Range. Exploration expense increased in 2014 primarily as a result of increased geophysical activity compared to 2013.

In connection with an asset exchange with Range in 2014, the Company received acreage and producing wells in the Permian Basin of Texas in exchange for acreage, producing wells, the Company’s 50% ownership interest in a supporting gathering system in the Nora fields of Virginia and cash of $167.3 million. In conjunction with the transaction, EQT Production recognized a pre-tax gain of $27.4 million in 2014, which is included in gain on sale / exchange of assets in the Statements of Consolidated Income.

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The $27.4 million pre-tax gain included a $28.0 million pre-tax gain related to the de-designation of certain derivative instruments that were previously designated as cash flow hedges because it was probable that the forecasted transactions would not occur.

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EQT Midstream

Results of Operations



	Years Ended December 31,
	2015		2014		% change 2015 - 2014		2013		% change 2014 - 2013
OPERATIONAL DATA
Net operating revenues (thousands):
Gathering
Firm reservation fee revenues	$	272,758	$	42,604	540.2		$	5,155	726.5
Volumetric based fee revenues:
Usage fees under firm contracts (a)	33,415		44,654		(25.2	)	—		100.0
Usage fees under interruptible contracts	198,365		310,620		(36.1	)	346,255		(10.3	)
Total volumetric based fee revenues	231,780		355,274		(34.8	)	346,255		2.6
Total gathering revenues