Edgar Filing: EQT Corp

Document

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, 2018



[ ]	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 001-03551

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, Suite 1700 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 every Interactive Data File required to be submitted 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 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. [ ]

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



Large accelerated filer X	Accelerated filer ___
Non-accelerated filer ___ (Do not check if a smaller reporting company)	Smaller reporting company ___
	Emerging growth company ___

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

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, 2018: $14.5 billion

The number of shares (in thousands) of common stock outstanding as of January 31, 2019: 254,762

DOCUMENTS INCORPORATED BY REFERENCE

The Company’s definitive proxy statement relating to the 2019 annual meeting of shareholders will be filed with the Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2018 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	32
Item 2	Properties	33
Item 3	Legal Proceedings	38
Item 4	Mine Safety Disclosures	39
	Executive Officers of the Registrant	40


PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
Item 6	Selected Financial Data	43
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	59
Item 8	Financial Statements and Supplementary Data	62
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	114
Item 9A	Controls and Procedures	114
Item 9B	Other Information	114

PART III

Item 10	Directors, Executive Officers and Corporate Governance	115
Item 11	Executive Compensation	115
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	116
Item 13	Certain Relationships and Related Transactions, and Director Independence	117
Item 14	Principal Accounting Fees and Services	118

PART IV

Item 15	Exhibits and Financial Statement Schedules	118
	Signatures	125

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Glossary of Commonly Used Terms, Abbreviations and Measurements

Commonly Used Terms

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.

extension well – a well drilled to extend the limits of a known reservoir.

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.

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.

multi-well pad – a well pad designed to enable the development of multiple horizontal wells from a single compact surface location.

well pad - an area of land that has been cleared and leveled to enable a drilling rig to operate in the exploration and development of a natural gas or oil well.

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Glossary of Commonly Used Terms, Abbreviations and Measurements

natural gas liquids (NGLs) – those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation or other methods in gas processing plants. Natural gas liquids include primarily ethane, 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).

option – a contract that gives the buyer the right, but not the obligation, to buy or sell a specified quantity of a commodity or other instrument at a specific price within a specified period of time.

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

productive well – a well that is producing oil or gas or that is capable of production.

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.

service well – a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include, among other things, gas injection, water injection and salt-water disposal.

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

CFTC – Commodity Futures Trading Commission

EPA – U.S. Environmental Protection Agency

FASB – Financial Accounting Standards Board

FERC – Federal Energy Regulatory Commission

GAAP – U.S. 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

Measurements

Bbl = barrel

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 = dekatherm or million British thermal units

Mbbl = thousand barrels

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

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

MMDth = million dekatherm

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

This Annual Report on Form 10-K contains 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 sections captioned “Strategy” and "Outlook" in Item 1, “Business,” the section captioned “Impairment of Oil and Gas Properties and Goodwill” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and all discussions of 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, Utica, Upper Devonian and other reserves; drilling plans and programs (including the number, type, depth, spacing, lateral lengths and location of wells to be drilled and the availability of capital to complete these plans and programs); production and sales volumes (including liquids volumes) and growth rates; production of free cash flow and the Company's ability to reduce its drilling costs and capital expenditures; the Company's ability to maximize recoveries per acre; infrastructure programs; the cost, capacity, timing of regulatory approvals; monetization transactions, including asset sales, joint ventures or other transactions involving the Company’s assets; acquisition transactions; the Company’s ability to achieve the anticipated synergies, operational efficiencies and returns from its acquisition of Rice Energy Inc.; the Company's ability to achieve the anticipated operational, financial and strategic benefits of its spin-off of Equitrans Midstream Corporation (Equitrans Midstream); the timing and structure of any dispositions of the Company's approximately 19.9% interest in Equitrans Midstream, and the planned use of the proceeds from any such dispositions; natural gas prices, changes in basis and the impact of commodity prices on the Company's business; reserves, including potential future downward adjustments and reserve life; potential future impairments of the Company's assets; projected capital expenditures and capital contributions; the amount and timing of any repurchases of the Company's common stock including whether the Company will institute a share repurchase program; dividend amounts and rates; liquidity and financing requirements, including funding sources and availability; hedging strategy; 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, taking into account all information currently available to the Company. 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, and the other documents the Company files from time to time with the SEC.

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, except as required by law.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

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 intended to be relied upon solely by the applicable party to such agreement and 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 and should not be relied upon as statements of fact.

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PART I

Item 1. Business

General

EQT Corporation (EQT or the Company) is a natural gas production company with emphasis in the Appalachian Basin and operations throughout Pennsylvania, West Virginia and Ohio. EQT is the largest producer of natural gas in the United States, based on average daily sales volumes, with 21.8 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 1.4 million gross acres, including approximately 1.1 million gross acres in the Marcellus play, many of which have associated deep Utica or Upper Devonian drilling rights, and approximately 0.1 million gross acres in the Ohio Utica play as of December 31, 2018.

Strategy

The Company seeks to be the premier producer of environmentally friendly, reliable, low-cost natural gas, while maximizing the long-term value of its assets through operational efficiency and a culture of sustainability. To accomplish these objectives and deliver value to its stakeholders, the Company's strategic priorities include focusing on reducing costs, improving operational and capital efficiency, consistently delivering volumes and prioritizing the return of capital to shareholders while strengthening the Company's balance sheet. The Company intends to achieve mid-single digit year-over-year production growth combined with substantial and sustainable free cash flow by executing on its plan, with a stable operating cadence which is expected to result in higher capital efficiency.

The Company believes the long-term outlook for its business is favorable due to the Company’s substantial resource base, financial strength, and its commitment to capital discipline and operational efficiencies. The Company believes the combination of these factors provide it with an opportunity to exploit and develop its acreage and reserves and maximize efficiency through economies of scale. The Company has a significant contiguous acreage position in the core of the Marcellus and Utica shales which the Company believes will allow it to realize operational efficiencies and improve overall returns. The Company believes that it is a technology leader in horizontal drilling and completion activities in the Appalachian Basin and continues to improve its operations through the use of new technologies and a company-wide focus on efficiency. Development of multi-well pads in conjunction with longer laterals, optimized well spacing, and completion techniques allow the Company to maximize development efficiencies while reducing the overall environmental surface footprint of its drilling operations.

Key Events in 2018


•	The Company achieved annual sales volumes of 1,488 Bcfe and average daily sales volumes of 4,076 MMcfe/d. Adjusted for the impact of the 2018 Divestitures, as explained below, total annual sales volumes were 1,447 Bcfe or 3,964 MMcfe/d.


•	On June 19, 2018, the Company sold its non-core Permian Basin assets located in Texas for net proceeds of $56.9 million (the Permian Divestiture). The assets sold in the Permian Divestiture included approximately 970 productive wells with net production of approximately 20 MMcfe per day at the time of sale, approximately 350 miles of low-pressure gathering lines and 26 compressors.

•

On July 18, 2018, the Company sold approximately 2.5 million non-core, net acres in the Huron play for net proceeds of $523.6 million (the Huron Divestiture). The assets sold in the Huron Divestiture included approximately 12,000 productive wells with current net production of approximately 200 MMcfe per day, approximately 6,400 miles of low-pressure gathering lines and 59 compressor stations. The Company retained the deep drilling rights across the divested acreage.


•	On November 12, 2018, the Company completed the Separation and Distribution of Equitrans Midstream Corporation (Equitrans Midstream), as explained below under “Separation and Distribution.”

Outlook

In 2019, the Company expects to spend approximately $1.5 billion for reserve development, approximately $0.2 billion for land and lease acquisitions, approximately $0.1 billion for capitalized overhead and approximately $0.1 billion for other production infrastructure. The Company plans to spud approximately 134 gross wells (126 net), including 91 Marcellus wells in Pennsylvania, 15 Marcellus wells in West Virginia and 28 Ohio Utica gross wells (20 net). Estimated sales volumes are expected to be 1,470 to 1,510 Bcfe for 2019. The 2019 drilling program is expected to support a 5% increase in sales volume in 2020 over

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the Company's 2019 expected sales volumes. The 2019 capital investment plan is expected to be funded by cash generated from operations.

The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop its reserves of, natural gas, oil and NGLs. Due to the volatility of commodity prices, the Company is unable to predict future potential movements in the market prices for natural gas, and NGLs at the Company's ultimate sales points and thus cannot predict the ultimate impact of prices on its operations. Changes in natural gas, NGLs and oil prices could affect, among other things, the Company's development plans, which would increase or decrease the pace of the development and the level of the Company's reserves, as well as the Company's revenues, earnings or liquidity. Lower prices could also result in non-cash impairments in the book value of the Company’s oil and gas properties or other long lived intangible assets or downward adjustments to the Company’s estimated proved reserves. Any such impairment and/or downward adjustment to the Company’s estimated reserves could potentially be material to the Company. See "Impairment of Oil and Gas Properties and Goodwill" and “Critical Accounting Policies and Estimates” included in Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of the Company’s accounting policies and significant assumptions related to accounting for oil and gas producing activities and the Company's policies and processes with respect to impairment reviews for proved and unproved property and goodwill.

Separation and Distribution

On November 12, 2018, EQT completed the previously announced separation of its midstream business, which was composed of the separately operated natural gas gathering, transmission and storage, and water services businesses of EQT, from its upstream business, which is composed of the natural gas, oil and natural gas liquids development, production and sales and commercial operations of the Company (the Separation). The Separation was effected by the transfer of the midstream business from EQT to Equitrans Midstream and the distribution of 80.1% of the outstanding shares of Equitrans Midstream common stock to EQT's shareholders (the Distribution). EQT's shareholders of record as of the close of business on November 1, 2018 (the Record Date) received 0.80 shares of Equitrans Midstream common stock for every one share of EQT common stock held as of the close of business on the Record Date. EQT retained 19.9% of the outstanding shares of Equitrans Midstream common stock.

As a result of the Distribution, Equitrans Midstream is now an independent public company listed under the ticker symbol “ETRN” on the New York Stock Exchange (NYSE). The Company’s common stock is listed under the symbol “EQT” on the NYSE.

The Company plans to dispose of all of its retained Equitrans Midstream common stock, which may include dispositions through one or more subsequent exchanges for debt or a sale of its shares for cash. The Company expects to use the proceeds from any dispositions of its retained Equitrans Midstream common stock to reduce the Company's debt.

Segment and Geographical Information

The Company's operations consist of one reportable segment. The Company has a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments. The Company measures financial performance as a single enterprise and not on an area-by-area basis. Substantially all of the Company’s assets and operations are located in the Appalachian Basin.

Proved Reserves

The Company’s proved reserves increased 2% in 2018, or 11% when adjusted for the impact of the Huron Divestiture and Permian Divestiture (collectively, the 2018 Divestitures). The Company's Marcellus assets constituted approximately 19.1 Tcfe of the Company's total proved reserves as of December 31, 2018 and increased 13% as compared to December 31, 2017. The Company’s Marcellus assets constituted approximately 87% of the Company's total proved reserves by volume as of December 31, 2018. As of December 31, 2018, the Company’s proved reserves were as follows:



(Bcfe)	Marcellus	Upper Devonian	Ohio Utica	Other	Total
Proved Developed	9,625	915	898	112	11,550
Proved Undeveloped	9,464	92	711	—	10,267
Total Proved Reserves	19,089	1,007	1,609	112	21,817

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The Company’s natural gas wells generally have long reserve lives. Assuming that future annual production from these reserves is consistent with 2019 production guidance, the remaining reserve life of the Company’s total proved reserves, as calculated by dividing total proved reserves by 2019 production volumes guidance, is approximately 15 years.

The Company invested approximately $2,255.0 million on reserve development during 2018, with total sales volumes of 1,488 Bcfe, an increase of 68% over the previous year. The Company drilled approximately 153 gross wells (133 net), including 105 Marcellus gross wells in Pennsylvania (99 net), 5 Upper Devonian wells in Pennsylvania, 12 Marcellus wells in West Virginia and 31 Ohio Utica gross wells (17 net). During the past three years, the Company’s capital expenditures for reserve development were:



	Years Ended December 31,
	2018		2017		2016
	(Millions)
Horizontal Marcellus*	$	1,895	$	1,137	$	559
Ohio Utica	360		50		58
Other	—		21		6
Total	$	2,255	$	1,208	$	623

* Includes Upper Devonian formations.

The Company sells natural gas and NGLs to marketers, utilities and industrial customers within its operational footprint and in markets that are accessible through the Company's current transportation portfolio. The Company has access to approximately 2.9 Bcf per day of firm contractual pipeline takeaway capacity and 0.6 Bcf per day of firm processing capacity. The Company has also committed to an initial 1.29 Bcf per day of firm capacity on the Mountain Valley Pipeline (MVP) which is expected to be placed in-service in the fourth quarter of 2019.

Markets and Customers

No single customer accounted for more than 10% of EQT's total operating revenues for 2018, 2017 and 2016.

Natural Gas Sales: The Company’s produced natural gas is sold to marketers, utilities and industrial customers located in the Appalachian Basin and in the markets that are accessible through the Company's current transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States as well as Canada. Natural gas is a commodity and therefore the Company typically receives market-based pricing. The market price for natural gas in the Appalachian Basin is lower relative to the price at Henry Hub, Louisiana (the location for pricing NYMEX natural gas futures) as a result of the increased supply of natural gas in the Appalachian Basin. 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 under the heading “Commodity Risk Management” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” and in Notes 1 and 5 to the Consolidated Financial Statements.

NGLs Sales: The Company primarily sells NGLs processed from its own gas production. In its Appalachian operations, the Company primarily contracts with MarkWest Energy Partners, L.P. (MarkWest) to process natural gas in order to extract the heavier hydrocarbon stream (consisting predominately of ethane, propane, iso-butane, normal butane and natural gasoline) primarily from the Company’s produced gas. The Company also contracts with MarkWest to market a portion of the Company's NGLs. The Company also has contractual arrangements with Williams Ohio Valley Midstream LLC to process natural gas and market a portion of its NGLs on behalf of the Company in its Appalachian operations.

The following table presents the average sales price on a per Mcfe basis to EQT for sales of produced natural gas, NGLs and oil, with and without cash settled derivatives.



	For the Years Ended December 31,
	2018		2017		2016
Average sales price per Mcfe sold (excluding cash settled derivatives)	$	3.15	$	2.98	$	1.99
Average sales price per Mcfe sold (including cash settled derivatives)	$	3.01	$	3.04	$	2.47

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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 “Average Realized Price Reconciliation,” and incorporated herein by reference.

Natural Gas Marketing: EQT Energy, LLC (EQT Energy), the Company's indirect wholly owned marketing subsidiary, provides marketing services and contractual pipeline capacity management primarily for the benefit of the Company. EQT Energy also engages in risk management and hedging activities on behalf of the Company, the objective of which is to limit the Company’s exposure to shifts in market prices.

Competition

Other natural gas producers compete with the Company in the acquisition of properties, the search for and development of reserves, the production and sale of natural gas and NGLs and the securing of services, labor, equipment and transportation required to conduct operations. The Company's competitors include independent oil and gas companies, major oil and gas companies and individual producers, operators and marketing companies.

Regulation

Regulation of the Company’s Operations

The Company’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.

The Company’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 unitization 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. In addition, state conservation and oil and gas laws generally limit the venting or flaring of natural gas. Various states also impose certain regulatory requirements to transfer wells to third parties or discontinue operations in the event of divestitures by the Company.

The Company's 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. 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.

In 2010, Congress adopted comprehensive financial reform legislation that established 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 Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing this legislation. As of the filing date of this Annual Report on Form 10-K, the CFTC had adopted and implemented many final rules that impose regulatory obligations on all market participants, including the Company, such as recordkeeping and certain reporting obligations. Other CFTC rules that may be relevant to the Company have yet to be finalized. Because significant CFTC rules relevant to natural gas hedging activities have not been adopted or implemented, 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 anticipates additional, compliance costs and changes to current market practices as participants continue to adapt to a changing regulatory environment.

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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 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.

The following is a summary of some of the existing laws, rules and regulations to which the Company's business operations are subject.

Natural Gas Sales and Transportation

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Historically, federal legislation and regulatory controls have affected the price of the natural gas the Company produces and the manner in which the Company markets its production. The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of the Company's sales of its own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties of over $1 million per day for each violation and disgorgement of profits associated with any violation. While the Company's production activities have not been regulated by the FERC as a natural gas company under the NGA, the Company is required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation or the FERC may adopt regulations that may subject certain of the Company's otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject the Company to civil penalty liability.

The CFTC also holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.

The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the Company may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that the Company produces, as well as the revenues the Company receives for sales of natural gas and release of its natural gas pipeline capacity. Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. The FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, the Company cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can the Company determine what effect, if any, future regulatory changes might have on the Company’s natural gas related activities.

Under the FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that the FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and, depending on the scope of that decision, the Company's costs of transporting gas to point of sale locations may increase. The Company believes that the third-party natural gas pipelines on which its gas is gathered meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas

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company. However, the distinction between the FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of those gathering facilities are subject to change based on future determinations by the FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Oil and NGLs Price Controls and Transportation Rates

Sales prices of oil and NGLs are not currently regulated and are made at market prices. The Company's sales of these commodities are, however, subject to laws and to regulations issued by the Federal Trade Commission (FTC) prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of over $1 million per day per violation. The Company's sales of these commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.

The price the Company receives from the sale of these products may be affected by the cost of transporting the products to market. Some of the Company's transportation of oil, natural gas and NGLs is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC’s regulation of crude oil and NGLs transportation rates may tend to increase the cost of transporting crude oil and NGLs by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The Company is not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crude oil production from the Company's crude oil producing operations.

Environmental, Health and Safety Regulation

The business operations of the Company are also subject to numerous stringent 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, operating and abandoning wells and related facilities. Violations of these laws can result in substantial administrative, civil and criminal penalties. These laws and regulations may require the acquisition of permits before drilling or other regulated activity commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas or areas with endangered or threatened species restrictions, require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits, establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations. In addition, these laws and regulations may restrict the rate of production.

Moreover, the trend has been for stricter regulation of activities that have the potential to affect the environment. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, the states, local governments, and the courts. The Company cannot predict when or whether any such proposals may become effective. Therefore, the Company is unable to predict the future costs or impact of compliance. The regulatory burden on the industry increases the cost of doing business and affects profitability. The Company has established procedures, however, for the ongoing evaluation of its operations to identify potential environmental exposures and to track compliance with regulatory policies and procedures.

The following is a summary of the more significant existing environmental and occupational health and workplace safety laws and regulations, as amended from time to time, to which the Company's business operations are subject and for which compliance may have a material adverse impact on the Company's financial condition, earnings or cash flows.

Hazardous Substances and Waste Handling. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous

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substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, the Company generates materials in the course of its operations that may be regulated as hazardous substances based on their characteristics; however, the Company is unaware of any liabilities arising under CERCLA for which the Company may be held responsible that would materially and adversely affect the Company.

The Resource Conservation and Recovery Act (RCRA) and analogous state laws establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA, or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, or under state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019, for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. The EPA would be required to complete any rulemaking revising the Subtitle D criteria by 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the Company's costs to manage and dispose of generated wastes, which could have a material adverse effect on the Company's results of operations and financial condition.

The Company currently owns, leases, or operates numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although the Company believes that it has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by the Company, or on, under or from other locations, including offsite locations, where such substances have been taken for recycling or disposal. In addition, some of the Company's properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under the Company's control. The Company is able to control directly the operation of only those wells with respect to which the Company acts or has acted as operator. The failure of a prior owner or operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to the Company as current owner or operator under CERCLA. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to undertake response or corrective measures, regardless of fault, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or waste pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act (CWA), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state equivalent agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (Corps). In September 2015, the EPA and the Corps issued a final rule defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the United States (WOTUS), but several legal challenges to the rule followed, and the WOTUS rule was stayed nationwide in October 2015 pending resolution of the court challenges. The EPA and the Corps proposed a rule in June 2017 to repeal the WOTUS rule and announced their intent to issue a new rule defining the CWA’s jurisdiction. In January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction to hear challenges to the WOTUS rule resides with the federal district courts; consequently, the previously filed district court cases were allowed to proceed, resulting in a patchwork of implementation in some states and stays in others. Following the U.S. Supreme Court’s decision, the EPA and the Corps issued a final rule in January 2018 staying implementation of the WOTUS rule for two years while the agencies reconsider the rule, but a federal judge barred the agencies’ suspension of the rule in August 2018. Subsequently, various district court decisions revived the WOTUS rule in 22 states, the District of Columbia, and the U.S. territories, and have enjoined implementation of the rule in 28 states. In December 2018, the EPA and the Corps released a proposal to redefine the definition of WOTUS. The new proposed definition narrows the scope of waters that are covered as jurisdictional under the WOTUS rule. This proposed definition may be subject to an expanded comment period and future litigation. As a result, future implementation of the WOTUS rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of the Company's natural gas

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and oil projects. Also, pursuant to these laws and regulations, the Company may be required to obtain and maintain approvals or permits for the discharge of wastewater or stormwater and to develop and implement spill prevention, control and countermeasure (SPCC) plans in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Air Emissions. The federal Clean Air Act (CAA) and comparable state laws regulate the emission of air pollutants from many sources, such as, for example, tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require the Company to obtain pre‑approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants, the costs of which could be significant. The need to obtain permits has the potential to delay the development of the Company's oil and natural gas projects. Over the next several years, the Company may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (NAAQS) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards and completed attainment/non-attainment designations in July 2018. States are expected to implement more stringent permitting requirements as a result of the final rule, which could apply to the Company's operations. While the EPA has determined that all counties in which the Company operates are in attainment with the new ozone standards, these determinations may be revised in the future. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new facilities or modify existing facilities in these newly designated non-attainment areas. Compliance with these more stringent standards and other environmental regulations could delay or prohibit the Company's ability to obtain permits for its operations or require the Company's to install additional pollution control equipment, the costs of which could be significant.

Climate Change and Regulation of “Greenhouse Gas” Emissions. In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (GHG) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (PSD) construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis. These EPA rulemakings could adversely affect our operations and restrict or delay the Company's ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of the Company's operations. For example, in December 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. These changes to the EPA’s GHG emissions reporting rule could result in increased compliance costs.

In June 2016, the EPA finalized new regulations that establish New Source Performance Standards (NSPS), known as Subpart OOOOa, for methane and volatile organic compounds (VOC) from new and modified oil and natural gas production and natural gas processing and transmission facilities. While the EPA has taken several steps to delay implementation of its methane standards, to date the courts have generally ruled that such attempts have been unlawful. In September 2018, the EPA proposed amendments to the 2016 Subpart OOOOa standards that would reduce the 2016 rule’s fugitive emissions monitoring requirements and expand exceptions to pneumatic pump requirements, among other changes. Various industry and environmental groups have separately challenged both the methane requirements and the EPA’s attempts to delay the implementation of the rule. In addition, in April 2018, several states filed a lawsuit seeking to compel the EPA to issue methane performance standards for existing sources in the oil and natural gas source category. As a result of the actions described above, the Company cannot predict with certainty the scope of any final methane regulations or the costs for complying with federal methane regulations.

At the state level, several states have proceeded with regulation targeting GHG emissions. For example, in June 2018, the Pennsylvania Department of Environmental Protection (PADEP) released revised versions of GP-5 and GP-5A, Pennsylvania’s general air permits applicable to processing plants and well site operations, among other facilities. These permits apply to new or modified sources constructed on or after August 8, 2018, with emissions below certain specified thresholds. GP-5 and GP-5A impose “best available technology” (BAT) standards, which are in addition to, and in many cases more stringent than, the federal NSPS. These BAT standards include a 200 ton per year limit on methane emissions, above which a BAT requirement for methane emissions control applies. Moreover, in December 2018, the PADEP released a draft proposed rulemaking for emissions of VOCs and other pollutants for existing sources. State regulations such as these could impose increased compliance costs on the Company's operations.

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While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of federal legislation in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. While Pennsylvania is not currently a member of the Regional Greenhouse Gas Initiative (RGGI), a multi-state regional cap and trade program comprised of several Eastern U.S. states, it is possible that it may join RGGI in the future. This could result in increased operating costs if the Company's operations are required to purchase emission allowances.

On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets (Paris Agreement). The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does not impose any binding obligations on its participants. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact the Company's business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, the Company's equipment and operations could require the Company to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas the Company produces and lower the value of its reserves.

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of finding for the energy sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While the Company cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to the Company's assets or affect the availability of water and thus could have an adverse effect on the Company's exploration and production operations.

Hydraulic Fracturing Activities. 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 the Company's drilling locations, the Company conducts baseline and, as appropriate, post-drilling water testing at all water wells within at least 2,500 feet of the Company's drilling pads.

Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (SDWA) over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities. The EPA also finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

Certain governmental reviews have been conducted or are underway that focus on the environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water

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withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Because the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, in January 2016, the PADEP issued new rules establishing stricter disposal requirements for wastes associated with hydraulic fracturing activities, which include, among other things, a prohibition on the use of centralized impoundments for the storage of drill cuttings and waste fluids. Further, these rules include requirements relating to storage tank security, secondary containment for storage vessels, construction rules for gathering lines and horizontal drilling under streams, and temporary transport lines for freshwater and wastewater. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Company operates, the Company could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from constructing wells.

Occupational Safety and Health Act. The Company is also subject to the requirements of the federal Occupational Safety and Health Act (OSHA), as amended, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in the Company's operations and that this information be provided to employees, state and local government authorities, and citizens.

Endangered Species Act. The federal Endangered Species Act (ESA) provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service (FWS), may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas and oil development. Further, the designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause the Company to incur increased costs arising from species protection measures or could result in limitations on the Company's exploration and production activities that could have an adverse impact on the Company's ability to develop and produce reserves.

See Note 15 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.

Employees

The Company and its subsidiaries had 863 employees as of January 31, 2019; none are subject to a collective bargaining agreement.

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 they are filed with, or furnished to, the SEC. The filings are also available by accessing the SEC's website at http://www.sec.gov.

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Composition of Operating Revenues

Presented below are operating revenues for each class of products and services.



	For the Years Ended December 31,
	2018			2017		2016
	(Thousands)
Operating revenues:
Sales of natural gas, oil and NGLs	$	4,695,519		$	2,651,318	$	1,594,997
Net marketing services and other	40,940			49,681		41,048
(Loss) gain on derivatives not designated as hedges	(178,591		)	390,021		(248,991		)
Total operating revenues	$	4,557,868		$	3,091,020	$	1,387,054

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.

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Item 1A. Risk Factors

In addition to the other information contained in this Annual Report on 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, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs 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 domestic and foreign supply of and demand for natural gas, NGLs and oil;


•	prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;


•	national and worldwide economic and political conditions;


•	new and competing exploratory finds of natural gas, NGLs and oil;


•	changes in U.S. exports of natural gas, NGLs and/or oil;


•	the effect of energy conservation efforts;


•	the price, availability and acceptance of alternative fuels;


•	the availability, proximity, capacity and cost of pipelines, other transportation facilities, and gathering, processing and storage facilities and other factors that result in differentials to benchmark prices;


•	technological advances affecting energy consumption and production;


•	the actions of the Organization of Petroleum Exporting Countries;


•	the level and effect of trading in commodity futures markets, including commodity price speculators and others;


•	the cost of exploring for, developing, producing and transporting natural gas, NGLs and oil;


•	the level of global inventories;


•	risks associated with drilling, completion and production operations; and


•	domestic, local and foreign governmental regulations, tariffs and taxes, including environmental and climate change regulation.

The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $6.88 per MMBtu to a low of $2.48 per MMBtu from January 1, 2018 through December 31, 2018, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $77.41 per barrel to a low of $44.48 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. Because our production and reserves predominantly consist of natural gas (approximately 94% of equivalent proved developed reserves), changes in natural gas prices have significantly greater impact on our financial results than oil prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, oil and NGLs at the Company's ultimate sales points and thus cannot predict the ultimate impact of prices on our operations.

Prolonged low, and/or significant or extended declines in, natural gas, NGLs and oil prices may adversely affect our revenues, operating income, cash flows and financial position, particularly if we are unable to control our development costs during periods of lower natural gas, NGLs and oil prices. Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings in future periods. Reductions in cash flows from lower commodity prices may require us to incur additional borrowings or to reduce our capital spending, which could reduce our production and our reserves, negatively affecting our future rate of growth. Lower prices for natural gas, NGLs and oil may also adversely affect our credit ratings and result in a reduction in our borrowing capacity and access to other capital. See “Impairment of Oil and Gas Properties and Goodwill” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Natural gas, NGLs and oil price declines have resulted in impairment of certain of our non-core assets. 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, including long lived intangible assets, which could materially and adversely affect our results of operations in future periods.” We are also exposed to the risk

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of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in our derivative contracts having a positive fair value in our favor. Further, adverse economic and market conditions could negatively affect the collectability of our trade receivables and cause our hedge counterparties to be unable to perform their obligations or to seek bankruptcy protection.

Increases in natural gas, NGLs 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 provided to our hedge counterparties, which is interest-bearing, 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.

Drilling for and producing natural gas and oil are high-risk and costly activities with many uncertainties. Our future financial position, cash flows and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas or oil production or that we will not recover all or any portion of our investment in such wells.

Our decisions to purchase, explore or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “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.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:


•	delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from permitting, wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;


•	shortages of or delays in obtaining equipment, rigs, materials and qualified personnel or in obtaining water for hydraulic fracturing activities;


•	equipment failures, accidents or other unexpected operational events;


•	lack of available gathering facilities or delays in construction of gathering facilities;


•	lack of available capacity on interconnecting transmission pipelines;


•	adverse weather conditions, such as flooding, droughts, freeze-offs, slips, blizzards and ice storms;


•	issues related to compliance with environmental regulations;


•	environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;


•	declines in natural gas, NGLs and oil market prices;


•	limited availability of financing at acceptable terms;


•	ongoing litigation or adverse court rulings;


•	public opposition to our operations;


•	title, surface access, coal mining and right of way problems; and


•	limitations in the market for natural gas, NGLs and oil.

Any of these risks can cause a delay in our development program or result in substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

Our drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our drilling locations.

Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our business strategy. Our

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ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, topography, gathering system and pipeline transportation costs and constraints, access to and availability of water sourcing and distribution systems, coordination with coal mining, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce natural gas, NGLs or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Further, certain of the horizontal wells we intend to drill in the future may require pooling or unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to pool or unitize such leaseholds with ours, the total locations we can drill may be limited. As such, our actual drilling activities may materially differ from those presently identified.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful, may not increase our overall production levels and proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our drilling locations, see “Item 2. Properties.”

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

Because the rate of production from natural gas and oil wells, and associated NGLs, generally declines as reserves are depleted, our future success depends upon our ability to develop additional oil and gas reserves that are economically recoverable and to optimize existing well production, and our failure to do so may reduce our earnings. Additionally, a failure to effectively and efficiently operate existing wells may cause production volumes to fall short of our projections. 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, NGLs and oil price volatility, government approvals, title and property access problems, geology, equipment failure or accidents and other factors. Drilling for natural gas and oil can be unprofitable, not only from dry wells, but from productive wells that perform below expectations or do not produce sufficient revenues to return a profit. Low natural gas, NGLs and oil prices may further limit the types of reserves that we can develop and produce economically.

Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Future natural gas, NGLs and oil production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot be certain that we will be able to find or acquire and develop additional reserves at an acceptable cost. Without continued successful development or acquisition activities, together with efficient operation of existing wells, our reserves and production, together with associated revenues, will decline as a result of our current reserves being depleted by production.

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

Reserve engineering is a subjective process involving estimates of underground accumulations of natural gas, NGLs and oil and assumptions concerning future prices, production levels and operating and development costs, 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. To the extent we experience a sustained period of reduced commodity prices, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved. Although we believe our estimates are reasonable, actual production, revenues and costs to develop reserves will likely vary from estimates and these variances could be material. 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.

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The standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated natural gas, NGLs 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. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. 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, NGLs and oil industry in general.

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 position 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 business plan, we considered allocating capital and other resources to various aspects of our business, including well development, reserve acquisitions, exploratory activities, corporate items, leasehold maintenance and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify and execute optimal business strategies, including the appropriate corporate structure and 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 position and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

Our exploration and production operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms.

Our business is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas, NGLs and oil reserves. We typically fund our capital expenditures with existing cash and cash generated by operations and, to the extent our capital expenditures exceed our cash resources, from borrowings under our revolving credit facility and other external sources of capital. If we do not have sufficient borrowing availability under our revolving credit facility due to the current commodity price environment or otherwise, we may seek alternate debt or equity financing, sell assets or reduce our capital expenditures. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

Our cash flow from operations and access to capital are subject to a number of variables, including:

•our level of proved reserves and production;

•the level of hydrocarbons we are able to produce from existing wells;

•our access to, and the cost of accessing, end markets for our production;

•the prices at which our production is sold;

•our ability to acquire, locate and produce new reserves;

•the levels of our operating expenses; and

•our ability to access the public or private capital markets or borrow under our revolving credit facility.

If our cash flows from operations or the borrowing capacity under our revolving credit facility are insufficient to fund our capital expenditures and we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.

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As of December 31, 2018, our Senior Notes were rated “Baa3” by Moody’s Investors Services (Moody’s) with a "stable" outlook, “BBB-” by Standard & Poor’s Ratings Service (S&P) with a "stable" outlook, and “BBB-” by Fitch Ratings Service (Fitch) with a "stable" outlook. Although we are not aware of any current plans of Moody’s, S&P or Fitch to lower their respective ratings on our Senior Notes, we cannot be assured that our credit rating will not be downgraded or withdrawn entirely by a rating agency. 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 Senior Notes. If any credit rating agency downgrades our ratings, particularly below investment grade, our access to the capital markets may be limited, borrowing costs and margin deposits on our 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 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, a company must be rated “BBB-” or higher by S&P, “Baa3” or higher by Moody’s and “BBB-” or higher by Fitch.

Risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.

As of December 31, 2018, we had approximately $5,497.4 million of debt outstanding and we may incur additional indebtedness in the future. Increases in our level of indebtedness may:


•	require us to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities;


•	limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making certain investments, and paying dividends;


•	place us at a competitive disadvantage compared to our competitors with lower debt service obligations;


•	depending on the levels of our outstanding debt, limit our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes; and


•	increase our vulnerability to downturns in our business or the economy, including declines in prices for natural gas, NGLs and oil.

Our debt agreements also require compliance with certain covenants. If the price that we receive for our natural gas, NGLs and oil production deteriorates from current levels or continues for an extended period, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default due to lack of covenant compliance. For more information about our debt agreements, please read “Capital Resources and Liquidity” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

We are subject to financing and interest rate exposure risks.

Our business and operating results can be adversely affected by increases in interest rates or other increases in the cost of capital resulting from a reduction in our credit rating or otherwise. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for operating and capital expenditures and place us at a competitive disadvantage.

Disruptions or volatility in the financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in the availability of credit could materially and adversely affect our ability to implement our business strategy and achieve favorable operating results. In addition, we are exposed to credit risk related to our revolving credit facility to the extent that one or more of our lenders may be unable to provide necessary funding to us under our existing revolving line of credit if it experiences liquidity problems.

Derivative transactions may limit our potential gains and involve other risks.

To manage our exposure to price risk, we currently and may in the future enter into derivative arrangements, utilizing commodity derivatives with respect to a portion of our future production. Such hedges are designed to lock in prices so as to limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge. In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•our production is less than expected;

•the counterparties to our derivatives contracts fail to perform on their contract obligations; or

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•an event materially impacts natural gas, NGLs or oil prices or the relationship between the hedged price index and the natural gas, NGLs or oil sales price.

We cannot be certain that any derivative transaction we may enter into will adequately protect us from declines in the prices of natural gas, NGLs or oil. Furthermore, where we choose not to engage in derivative transactions in the future, we may be more adversely affected by changes in natural gas, NGLs or oil prices than our competitors who engage in derivative transactions. Lower natural gas, NGLs and oil prices may also negatively impact our ability to enter into derivative contracts at favorable prices.

Derivative transactions also expose us to a risk of financial loss if a counterparty fails to perform under a derivative contract or enters bankruptcy or encounters some other similar proceeding or liquidity constraint. In this case, we may not be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

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

Our business is subject to all of the inherent hazards and risks normally incidental to drilling for, producing, transporting and storing natural gas, NGLs and oil, such as fires, explosions, slips, landslides, blowouts, and well cratering; pipe and other equipment and system failures; delays imposed by, or resulting from, compliance with regulatory requirements; formations with abnormal or unexpected pressures; shortages of, or delays in, obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities; adverse weather conditions, such as freeze offs of wells and pipelines due to cold weather; issues related to compliance with environmental regulations; environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized releases of brine, well stimulation and completion fluids, toxic gases or other pollutants into the environment, especially those that reach surface water or groundwater; inadvertent third party damage to our assets, and natural disasters. We also face various risks or threats to the operation and security of our or third parties’ facilities and infrastructure, such as processing plants, compressor stations and pipelines. Any of these risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, equipment and natural resources, pollution or other environmental damage, loss of hydrocarbons, disruptions to our operations, regulatory investigations and penalties, suspension of our operations, repair and remediation costs, 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. In addition, pollution and environmental risks generally are not fully insurable, and, we may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event that is not fully covered by insurance could materially adversely affect our business, results of operations, cash flows and financial position.

Cyber incidents targeting our systems or natural gas and oil industry systems and infrastructure may adversely impact our operations.

Our business and the natural gas and oil industry in general have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, and the maintenance of our financial and other records has long been dependent upon such technologies. We depend on this technology to record and store data, estimate quantities of natural gas, NGLs and crude oil reserves, analyze and share operating data and communicate internally and externally. Computers control nearly all of the natural gas, NGLs and oil distribution systems in the U.S., which are necessary to transport our products to market.

The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. We can provide no assurance that we will not suffer such attacks in the future. 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 and cyber-attackers become more sophisticated, 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. The cost to remedy an unintended dissemination of sensitive information or data may be significant. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

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Failure to timely develop our leased real property could result in increased capital expenditures and/or impairment of our leases.

Mineral rights are typically owned by individuals who may enter into property leases with us to allow for the development of natural gas. Such leases expire after an initial term, typically five years, unless certain actions are taken to preserve the lease. If we cannot preserve a lease, the lease terminates. 26% of our net undeveloped acres are subject to leases that could expire over the next three years. Lack of access to capital, changes in government regulations, changes in future development plans, reduced drilling activity, or the reduction in the fair value of undeveloped properties in the areas in which we operate could impact our ability to preserve, trade, or sell our leases prior to their expiration resulting in the termination and impairment of leases for properties which we have not developed.

Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis. Indicators of potential impairment include changes brought about by economic factors, potential shifts in business strategy employed by management and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. For the years ended December 31, 2018, 2017 and 2016, we recorded lease impairments and expirations of $279.7 million, $7.6 million and $15.7 million, respectively. Refer to Note 1 to the Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K.

We may incur losses as a result of title defects in the properties in which we invest.

Our inability to cure any title defects in our leases in a timely and cost efficient manner may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial position.

Substantially all of our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating primarily in one major geographic area.

Substantially all of our producing properties are geographically concentrated in the Appalachian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by, and costs associated with, governmental regulation, state and local political activities, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other weather related conditions, interruption of the processing or transportation of oil, natural gas or NGLs and changes in state and local laws, judicial precedents, political regimes and regulations. Such conditions could materially adversely affect our results of operations and financial position.

In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations. For example, third-parties may engage in subsurface coal and other mining operations near or under our properties, which could cause subsidence or other damage to our properties, adversely impact our drilling operations or adversely impact third-party midstream activities on which we rely. In such event, our operations may be impaired or interrupted, and we may not be able to recover the costs incurred as a result of temporary shut-ins or the plugging and abandonment of any of our wells. Furthermore, the existence of mining operations near our properties could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. These restrictions on our operations, and any similar restrictions, could cause delays or interruptions or prevent us from executing our business strategy, which could materially adversely affect our results of operations and financial position.

Further, insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices. The Appalachian Basin has recently experienced periods in which production has surpassed local takeaway capacity, resulting in substantial discounts in the price received by producers such as us and others at times being possibly shut in. Although additional Appalachian Basin takeaway capacity has been added in recent years, the existing and expected capacity may not be sufficient to keep pace with the increased production caused by accelerated drilling in the area in the short term.

Due to the concentrated nature of our portfolio of natural gas properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

Natural gas, NGLs and oil price declines have resulted in impairment of certain of our non-core assets. 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, including long lived intangible assets, which could materially and adversely affect our results of operations in future periods.

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We review the carrying values of our proved oil and gas properties and goodwill for indications of impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. In addition, we evaluate goodwill for impairment at least annually. A significant amount of judgment is involved in performing these evaluations because the results are based on estimated future events and estimated future cash flows. The estimated future cash flows used to test our proved oil and gas 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 our management for internal planning and budgeting purposes. Key assumptions used in our analyses, include, among other things, the intended use of the asset, the anticipated production from reserves, future market prices for natural gas, NGLs and oil, future operating costs, inflation and the anticipated proceeds which may be received upon divestiture if there is a possibility that the asset will be divested prior to the end of its useful life. Commodity pricing is estimated by using a combination of the five-year NYMEX forward strip prices and assumptions related to gas quality, locational basis adjustments 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. When testing goodwill for impairment, we also consider the market value of our common stock and other valuation techniques when determining the fair value of our single reporting unit.

Future declines in natural gas, NGLs 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 assets, including other long lived intangible assets, which may have a material adverse effect on our results of operations in future periods.

Any impairment of our assets, including other long lived intangible assets, would require us to take an immediate charge to earnings. Such charges could be material to our results of operations and could adversely affect our results of operations and financial position. See “Impairment of Oil and Gas Properties and Goodwill” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The unavailability or high cost of additional drilling rigs, completion services, equipment, supplies, personnel, and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages or higher costs. Historically, there have been shortages of personnel and equipment as demand for personnel and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could materially adversely affect our business, results of operations, cash flows and financial position.

Our ability to drill for and produce natural gas and oil is dependent on the availability of adequate supplies of water for drilling and completion operations and access to water and waste disposal or recycling services at a reasonable cost and in accordance with applicable environmental rules. Restrictions on our ability to obtain water or dispose of produced water and other waste may adversely affect our results of operations, cash flows and financial position.

The hydraulic fracture stimulation process on which we depend to drill and complete natural gas and oil wells requires the use and disposal of significant quantities of water. Our ability to access sources of water and the availability of disposal alternatives to receive all of the water produced from our wells and used in hydraulic fracturing may affect our drilling and completion operations. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, or to timely obtain water sourcing permits or other rights, could adversely affect our operations. Additionally, the imposition of new environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste, which would adversely affect our business and results of operations, which could result in decreased cash flows.

In addition, federal and state regulatory agencies recently have focused on a possible connection between the operation of injection wells used for natural gas and oil waste disposal and increased seismic activity in certain areas. In some cases, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Increased regulation and attention given to induced seismicity in the states where we operate could lead to restrictions on our disposal well injection volumes and increased scrutiny of and delay in obtaining new disposal well permits, which could result in increased operating costs, which could be material, or a curtailment of our operations.

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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 identify, 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 identifying, attracting and retaining such personnel. If we cannot identify, attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete in our industry could be harmed.

Competition in our industry is intense, and many of our competitors have substantially greater financial resources than we do, which could adversely affect our competitive position.

Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable oil and gas properties, as well as for the capital, equipment and labor required to operate and develop these properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on existing and changing processes and may also have a greater ability to continue drilling activities during periods of low natural gas and oil prices and to absorb the burden of current and future governmental regulations and taxation.

We depend upon Equitrans Midstream, a third-party midstream provider, for a significant portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure to successfully deliver natural 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 primarily owned by third-parties, and our ability to contract with these third-parties. 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 or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Competition for access to pipeline infrastructure within the Appalachian Basin is intense, and our ability to secure access to pipeline infrastructure on favorable economic terms could affect our competitive position.

Historically our ownership interest in and control of EQM Midstream Partners, LP (EQM) and Rice Midstream Partners LP (RMP) allowed us to exercise greater control over the development of midstream infrastructure to service our operations. However, as a result of the Separation, we no longer control those operations and facilities and will be dependent on Equitrans Midstream and other third-party providers of these services. Access to midstream assets may be unavailable due to market conditions or mechanical or other reasons. In addition, at current commodity prices, construction of new pipelines and building of such infrastructure may occur more slowly. A lack of access to needed infrastructure, or an extended interruption of access to or service from our or third-party pipelines and facilities for any reason, including vandalism, sabotage or 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 addition, some of our third-party contracts involve significant long-term financial commitments on our part and could reduce our cash flow during periods of low prices for natural gas, NGLs and oil. Our usage of third parties for transmission, gathering and processing services subjects us to the 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. To the extent these services are delayed or unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Our failure to obtain these services on acceptable terms could materially harm our business.

Finally, in order to ensure access to certain midstream facilities, we have entered into agreements that obligate us to pay demand charges to various pipeline operators. We also have commitments with third parties for processing capacity. We may be obligated to make payments under these agreements even if we do not fully utilize the capacity we have reserved, and these payments may be significant.

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

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Negative public perception regarding us and/or our industry resulting from, among other things, the explosion of natural gas transmission and gathering lines, oil spills, and concerns raised by advocacy groups or the media about hydraulic fracturing, greenhouse gas or methane emissions or fossil fuels in general, or about royalty payment and surface use issues, may lead to increased litigation and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new local, state and federal laws, regulations, guidelines and enforcement interpretations in safety, environmental, royalty and surface use areas. 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, challenged or burdened by requirements that restrict our ability to profitably conduct our business.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

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 and related infrastructure. 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 water and other fluids and materials, including solid and hazardous wastes, incidental to natural gas and oil 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.

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 properties. Some states allow the statutory pooling and unitization of tracts to facilitate development and exploration, as well as joint development of existing contiguous leases. In addition, state conservation and natural gas and oil 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, ground 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; environmental impact studies and assessments prior to permitting; restoration of drilling properties after drilling is completed; and work practices related to employee health and safety.

To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Maintaining compliance with the laws, regulations and other legal requirements applicable to our business and any delays in obtaining related authorizations may affect the costs and timing of developing our natural gas, NGLs and oil resources. These requirements could also subject us to claims for personal injuries, property damage and other damages. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could materially adversely affect our results of operations, cash flows and financial position. Our failure to comply with the laws, regulations and other legal requirements applicable to our business, 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 as well as corrective action costs.

In December 2018, changes to certain federal income tax laws were signed into law which impact us, including but not limited to: changes to the regular income tax rate; the elimination of the alternative minimum tax; full expensing of capital equipment; limited deductibility of interest expense; and increased limitations on deductible executive compensation. The current administration continues to debate further changes to federal income tax laws that could be enacted which could have a material impact on us. The most significant potential tax law changes include further changes to the regular income tax rate, the expensing of intangible drilling costs or percentage depletion, and further limited deductibility of interest expense, any of which could adversely impact our current and deferred federal and state income tax liabilities. State and local taxing authorities in jurisdictions in which we operate or own assets may enact new taxes, such as the imposition of a severance tax on the extraction of natural resources in states in which we produce natural gas, NGLs and oil, or change the rates of existing taxes, which could adversely impact our earnings, cash flows and financial position.

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In 2010, Congress adopted the Dodd-Frank Act, which established federal oversight and regulation of the over-the-counter derivative market and entities, such as us, that participate in that market. 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 on Form 10-K, 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 have not been adopted or implemented, 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.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing and governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of natural gas and oil wells, which could adversely affect our production.

We utilize hydraulic fracturing in the completion of our natural gas and oil wells. Hydraulic fracturing typically is regulated by state natural gas and oil commissions, but the EPA has asserted federal regulatory authority. For example, the EPA also finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

Certain governmental reviews have been conducted or are underway that focus on the environmental aspects of hydraulic fracturing practices. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from constructing wells. See "Business-Regulation-Environmental, Health and Safety Regulation” for more information.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment and occupational health and workplace safety, including regulations and enforcement policies that have tended to become increasingly strict over time resulting in longer waiting periods to receive permits and other regulatory approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and occupational health and workplace safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters.

In addition, new or additional laws and regulations, new interpretations of existing requirements or changes in enforcement policies could impose unforeseen liabilities, significantly increase compliance costs or result in delays of, or denial of rights to conduct, our development programs. For example, in September 2015, the EPA and the Corps issued a final rule under the CWA defining the scope of the EPA’s and the Corps’ jurisdiction over WOTUS, but several legal challenges to the rule followed, and the WOTUS rule was stayed nationwide in October 2015 pending resolution of the court challenges. The EPA and the Corps proposed a rule in June 2017 to repeal the WOTUS rule, and announced their intent to issue a new rule defining the CWA’s jurisdiction. In January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction to hear challenges to the WOTUS rule resides with the federal district courts; consequently, the previously filed district court cases were allowed to proceed, resulting in a patchwork of implementation in some states and stays in others. Following the U.S. Supreme Court’s decision, the EPA and the Corps issued a final rule in January 2018 staying implementation of the WOTUS rule for two years while the agencies reconsider the rule, but a federal judge barred the agencies’ suspension of the rule in August 2018. Subsequently, various district court decisions

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revived the WOTUS rule in 22 states, the District of Columbia, and the U.S. territories and enjoined implementation of the rule in 28 states. In December 2018, the EPA and the Corps released a proposal to redefine the definition of WOTUS. The new proposed definition narrows the scope of waters that are covered as jurisdictional under the WOTUS rule. The proposed definition may be subject to an expanded comment period and future litigation. As a result, future implementation of the WOTUS rule is uncertain at this time. To the extent the WOTUS rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Such potential regulations or litigation could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which in turn could materially adversely affect our results of operations and financial position. Further, the discharges of natural gas, NGLs, oil, and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties.

Regulations related to the protection of wildlife could adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Our operations can be adversely affected by regulations designed to protect various wildlife. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in constraints on our exploration and production activities. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Conservation measures and technological advances could reduce demand for natural gas and oil.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas and oil. The impact of the changing demand for natural gas and oil could adversely impact our earnings, cash flows and financial position.

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the natural gas, NGLs and oil that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore natural gas and oil production sources in the United States on an annual basis, which include certain of our operations. At the state level, several states including Pennsylvania have proceeded with regulation targeting GHG emissions. Such state regulations could impose increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of federal legislation in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. While Pennsylvania is not currently a member of the RGGI, a multi-state regional cap and trade program comprised of several Eastern U.S. states, it is possible that it may join RGGI in the future. This could result in increased operating costs if our operations are required to purchase emission allowances.

On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement which calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does not impose any binding obligations on its participants. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

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Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the natural gas, NGLs and oil we produce and lower the value of our reserves.

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of finding for the energy sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations. See “Business-Regulation-Environmental, Health and Safety Regulation” for more information.

The growth of our business through strategic transactions may expose us to various risks.

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 and third party approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; the assumption of potential environmental or other liabilities; and our ability to realize the benefits expected from the transactions. In addition, various factors, including prevailing market conditions, could negatively impact the benefits we receive from transactions. Competition for transaction opportunities in our industry is intense and may increase the cost of, or cause us to refrain from, completing 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 or partial 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.

Acquisitions may disrupt our current plans or operations and may not be worth what we pay due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities. We may not achieve the intended benefits of our acquisition of Rice Energy Inc.

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration potential, future natural gas, NGLs and oil prices, operating costs, production taxes and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well or lease that we acquire, and even when we inspect a well or lease we may not discover structural, subsurface, or environmental problems that may exist or arise.

There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an “as is” basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.

On November 13, 2017, we completed the acquisition of Rice Energy Inc. (Rice). There can be no assurance that we will be able to successfully integrate Rice’s assets or otherwise realize the expected benefits of the acquisition of Rice. In addition, our business may be negatively impacted if we are unable to effectively manage our expanded operations going forward. The integration has required and will continue to require significant time and focus from management and could disrupt current plans and operations, which could delay the achievement of our strategic objectives.

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Changes in our business following the completion of recent significant transactions, including the acquisition of Rice and the Separation and Distribution, may result in disruptions to our business and negatively impact our operations and our relationships with our customers and business partners.

Over the last two years we have completed multiple significant transactions, including the acquisition of Rice and the Separation and Distribution, with material work to be completed to achieve synergies and rationalize operations. As a result of these transactions, our company and employees have experienced significant changes, including the departure of members of senior management, new leadership in significant roles, and employee re-assignments necessary in connection with the Separation as well as a reduction in our workforce. The combination of these factors may materially adversely affect our operations. Further, uncertainty related to our business following the Separation may lead customers and other parties to terminate or attempt to negotiate changes in existing business relationships, or consider entering into business relationships with parties other than us. These disruptions could materially adversely affect our results of operations, financial position and prospects.

The Separation and Distribution may subject us to future liabilities.

In November 2018, we completed the Separation and Distribution, resulting in the spin-off of Equitrans Midstream, a stand-alone publicly traded corporation which holds our former midstream business.

Pursuant to agreements we entered into with Equitrans Midstream in connection with the Separation, we and Equitrans Midstream are each generally responsible for the obligations and liabilities related to our respective businesses. Pursuant to those agreements, we and Equitrans Midstream each agreed to cross-indemnities principally designed to allocate financial responsibility for the obligations and liabilities of our business to us and those of Equitrans Midstream’s business to it. However, third parties, including governmental agencies, could seek to hold us responsible for obligations and liabilities that Equitrans Midstream agreed to retain or assume, and there can be no assurance that the indemnification from Equitrans Midstream will be sufficient to protect us against the full amount of such obligations and liabilities, or that Equitrans Midstream will be able to fully satisfy its indemnification obligations. Additionally, if a court were to determine that the Separation or related transactions were consummated with the actual intent to hinder, delay or defraud current or future creditors or resulted in Equitrans Midstream receiving less than reasonably equivalent value when it was insolvent, or that it was rendered insolvent, inadequately capitalized or unable to pay its debts as they become due, then it is possible that the court could disregard the allocation of obligations and liabilities agreed to between us and Equitrans Midstream, impose substantial obligations and liabilities on us and void some or all of the Separation-related transactions. Any of the foregoing could adversely affect our results of operations and financial position.

If there is a later determination that the Distribution or certain related transactions are taxable for U.S. federal income tax purposes because the facts, assumptions, representations or undertakings underlying the IRS private letter ruling and/or opinion of counsel are incorrect or for any other reason, we could incur significant liabilities.

In connection with the Separation and Distribution, we obtained a private letter ruling from the IRS and an opinion of outside counsel regarding the qualification of the Distribution, together with certain related transactions, as a transaction that is generally tax-free, for U.S. federal income tax purposes, under Sections 355 and 368(a)(1)(D) of the U.S. Internal Revenue Code (the Code) and certain other U.S. federal income tax matters relating to the Distribution and certain related transactions. The IRS private letter ruling and the opinion of counsel are based upon and rely on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of us and Equitrans Midstream, including those relating to the past and future conduct of us and Equitrans Midstream. If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if we or Equitrans Midstream breach any representations or covenants contained in any of the Separation-related agreements and documents or in any documents relating to the IRS private letter ruling and/or the opinion of counsel, we and our shareholders may not be able to rely on the IRS private letter ruling or the opinion of counsel.

Notwithstanding receipt of the IRS private letter ruling and the opinion of counsel, the IRS could determine on audit that the Distribution and/or certain related transactions should be treated as taxable transactions for U.S. federal income tax purposes if it determines that any of the representations, assumptions or undertakings upon which the IRS private letter ruling was based are false or have been violated or if it disagrees with the conclusions in the opinion of counsel that are not covered by the ruling or for other reasons, including as as result of certain significant changes in the stock ownership of the Company or Equitrans Midstream after the Distribution further described below. An opinion of counsel represents the judgment of such counsel and is not binding on the IRS or any court, and the IRS or a court may disagree with the conclusions in such opinion of counsel. Accordingly, notwithstanding receipt of the IRS private letter ruling and the opinion of counsel, there can be no assurance that the IRS will not assert that the Distribution and/or certain related transactions should be treated as taxable transactions or that a court would not sustain such a challenge. In the event the IRS were to prevail with such challenge, we, Equitrans Midstream and our shareholders could be subject to material U.S. federal and state income tax liabilities. In connection with the Separation, we

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and Equitrans Midstream entered into a tax matters agreement, which described the sharing of any such liabilities between us and Equitrans Midstream.

Even if the Distribution otherwise qualifies as generally tax-free under Section 355 and Section 368(a)(1)(D) of the Code, the Company (but not shareholders) would be subject to material U.S. federal and state income tax liability under Section 355(e) of the Code if one or more persons acquire, directly or indirectly, a 50-percent or greater interest (measured by either vote or value) in our stock or in the stock of Equitrans Midstream (excluding, for this purpose, the acquisition of stock of Equitrans Midstream by holders of our stock in the Distribution) as part of a plan or series of related transactions that includes the Distribution. Any acquisition of our stock or stock of Equitrans Midstream (or any predecessor or successor corporation) within two years before or after the Distribution generally would be presumed to be part of a plan that includes the Distribution, although the parties may be able to rebut that presumption under certain circumstances. Additionally, Equitrans Midstream is subject to certain agreements entered into with us that restrict, within two years of the Distribution, the ability of Equitrans Midstream to engage in certain corporate transactions without obtaining an advance ruling from the IRS and our prior consent. The process for determining whether an acquisition is part of a plan under these rules is complex, inherently factual in nature and subject to a comprehensive analysis of the facts and circumstances of the particular case. Notwithstanding the IRS private letter ruling or any opinion of counsel described above, we or Equitrans Midstream may cause or permit a change in ownership of our stock or stock of Equitrans Midstream sufficient to result in a material tax liability to us.

The Separation may not achieve some or all of the anticipated benefits.

We may not realize some or all of the anticipated strategic, financial, operational or other benefits from the Separation. As independent publicly-traded companies, we and Equitrans Midstream are smaller, less diversified companies with a narrower business focus and may be more vulnerable to changing market conditions, which could materially adversely affect our and its results of operations, cash flows and financial position. Further, we may be required to expend additional resources to consolidate and/or upgrade our information technology processes and systems to achieve our strategic goals.

We are a significant shareholder of Equitrans Midstream and the value of our investment in Equitrans Midstream may fluctuate substantially.

We own approximately 19.9% of the outstanding shares of common stock of Equitrans Midstream. The value of our investment in Equitrans Midstream may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the midstream industry, including loss of gathering and transportation volumes, the effect of laws and regulations on the operation of its business and development of its assets, increased competition, loss of contracted volumes, adverse rate-making decisions, policies and rulings by the FERC, delays in the timing of or the failure to complete expansion projects, lack of access to capital and operating risks and hazards.

We intend to dispose of our interest in Equitrans Midstream through one or more exchanges of our shares of Equitrans Midstream common stock for our debt or one or more sales of such shares for cash. However, we can offer no assurance that we will be able to complete such disposition or as to the value we will realize. The occurrence of any of these and other risks faced by Equitrans Midstream could adversely affect the value of our investment in Equitrans Midstream.

Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

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

Item 1B. Unresolved Staff Comments

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None.

Item 2. Properties

Principal facilities are owned or, in the case of certain office locations, warehouse buildings and equipment, leased, by the Company and its subsidiaries. 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.

The Company’s properties are located primarily in Pennsylvania, West Virginia and Ohio. The Company has approximately 1.4 million gross acres (approximately 74% 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. Of these gross acres, approximately 1.1 million are in the Marcellus play, much of which has associated deep Utica or Upper Devonian drilling rights, and approximately 0.1 million are in the Ohio Utica play. Although most of the Company's wells are drilled to relatively shallow depths (5,000 to 8,500 feet below the surface), the Company retains what are normally considered “deep rights” on the majority of its acreage. As of December 31, 2018, the Company estimated its total proved reserves to be 21.8 Tcfe, consisting of proved developed producing reserves of 11.3 Tcfe, proved developed non-producing reserves of 0.2 Tcfe and proved undeveloped reserves of 10.3 Tcfe. Substantially all of the Company’s reserves reside in continuous accumulations.

The Company’s estimate of proved natural gas, NGLs 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 21 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, NGLs 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, NGLs and oil proved reserves attributable to the Company’s interests as of December 31, 2018. Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 81% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining approximately 19% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 115 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. 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, NGLs and crude oil reserves and future net cash flows is provided in Note 18 (unaudited) to the Consolidated Financial Statements.

In 2018, the Company commenced drilling operations (spud or drilled) on 117 gross horizontal Marcellus wells, 5 gross horizontal Upper Devonian wells and 31 gross horizontal Ohio Utica wells. Sales volumes in 2018 from the Marcellus play, including the Upper Devonian play, was 1,230 Bcfe. Over the past five years, the Company has experienced a 97% developmental drilling success rate.

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Natural gas, NGLs and crude oil pricing:



	For the Years Ended December 31,
	2018		2017		2016
Natural Gas:
Average sales price (excluding cash settled derivatives) ($/Mcf)	$	3.04	$	2.82	$	1.88
Average sales price (including cash settled derivatives) ($/Mcf)	$	2.89	$	2.89	$	2.41
NGLs (excluding ethane):
Average sales price (excluding cash settled derivatives) ($/Bbl)	$	37.63	$	31.59	$	19.43
Average sales price (including cash settled derivatives) ($/Bbl)	$	36.56	$	30.90	$	19.43
Ethane:
Average sales price ($/Bbl)	$	8.09	$	6.32	$	5.08
Crude Oil:
Average sales price ($/Bbl)	$	52.70	$	40.70	$	34.73

For additional information on pricing, see “Average Realized Price Reconciliation” 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 2018, 2017 and 2016 was $0.07 per Mcfe, $0.13 per Mcfe and $0.15 per Mcfe, respectively.

Summary of productive and in process natural gas and oil wells at December 31, 2018:



	Natural Gas	Oil
Total productive wells at December 31, 2018:
Total gross productive wells	3,258	—
Total net productive wells	3,050	—
Total in-process wells at December 31, 2018:	0
Total gross in-process wells	310	—
Total net in-process wells	278	—

Summary of proved natural gas, oil and NGLs reserves as of December 31, 2018 based on average fiscal year prices:



	Natural Gas (MMcf)	Oil and NGLs (Bbls)
Developed	10,887,953	110,368
Undeveloped	9,917,499	58,186
Total proved reserves	20,805,452	168,554



Total acreage at December 31, 2018:
Total gross productive acres	367,378
Total net productive acres	354,817
Total gross undeveloped acres	1,021,615
Total net undeveloped acres	866,395

As of December 31, 2018, the Company had no proved undeveloped reserves that had remained undeveloped for more than five years.

The Company has an active lease renewal program in areas targeted for development. In the event that production is not established or the Company takes no action to extend or renew the terms of its leases, the Company's net undeveloped acreage that will expire over the next three years as of December 31, 2018 is 90,543, 79,107 and 54,373 for the years ended December 31, 2019, 2020 and 2021, respectively.

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



	For the Years Ended December 31,
	2018	2017	2016
Exploratory wells:
Productive	—	—	—
Dry	—	1.0	—
Development wells:
Productive	210.2	149.2	140.9
Dry	4.6	4.9	15.0

The dry developmental wells in 2018 and 2017 are primarily related to non-core wells no longer planned to be drilled to depth or completed and acquired wells with mechanical integrity issues. The number of dry developmental wells drilled in 2016 were primarily related to vertical wells that are no longer planned to be drilled horizontally due to the uncertainty of identifying a near-term pipeline solution.

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The table below provides select production, sales and acreage data by state (as of December 31, 2018 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 the "Average Realized Price Reconciliation" table in Item 7 of this Annual Report on Form 10-K for sales volumes by final product.



	Pennsylvania		West Virginia (d)		Ohio		Other (b)		Total
Natural gas, oil and NGLs production (MMcfe) – 2018 (a) (c)	918,156		330,504		208,197		37,806		1,494,663
Natural gas, oil and NGLs production (MMcfe) – 2017 (a) (c)	456,614		352,481		24,426		74,371		907,892
Natural gas, oil and NGLs production (MMcfe) – 2016 (a)	426,524		272,529		541		76,769		776,363

Natural gas, oil and NGLs sales (MMcfe) – 2018 (c)	922,033		323,976		209,428		32,252		1,487,689
Natural gas, oil and NGLs sales (MMcfe) – 2017 (c)	456,600		343,199		24,113		63,608		887,520
Natural gas, oil and NGLs sales (MMcfe) – 2016	429,011		264,452		536		64,968		758,967

Average net revenue interest of proved reserves (%)	78.9	%	82.8	%	47.7	%	—	%	75.9	%

Total gross productive wells	1,778		1,259		221		—		3,258
Total net productive wells	1,733		1,215		102		—		3,050

Total gross productive acreage	223,977		103,617		39,784		—		367,378
Total gross undeveloped acreage	444,439		486,301		48,243		42,632		1,021,615
Total gross acreage	668,416		589,918		88,027		42,632		1,388,993

Total net productive acreage	221,954		102,836		30,027		—		354,817
Total net undeveloped acreage	419,612		392,698		34,368		19,717		866,395
Total net acreage	641,566		495,534		64,395		19,717		1,221,212

(Amounts in Bcfe)
Proved developed producing reserves	7,525		2,924		827		—		11,276
Proved developed non-producing reserves	203		—		71		—		274
Proved undeveloped reserves	8,497		1,059		711		—		10,267
Proved developed and undeveloped reserves	16,225		3,983		1,609		—		21,817

Gross proved undeveloped drilling locations	547		75		72		—		694
Net proved undeveloped drilling locations	498		71		46		—		615

(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 primarily includes Kentucky and Virginia. During 2018, as a result of the Huron Divestiture, the Company sold approximately 2.5 million non-core, net acres in the Huron play, however, the Company retained the deep drilling rights across the divested acreage in Kentucky and Virginia of 1.5 million and 0.2 million, respectively, which are excluded from the acreage totals above. Natural gas, oil and NGLs production and sales primarily represents activity prior to the completion of the 2018 Divestitures.


(c)	For the years ended December 31, 2018 and 2017, the natural gas, oil and NGLs production volumes and sales volumes includes volumes from the production operations acquired in the Rice Merger (defined in Note 3 to the Consolidated Financial Statements) which occurred on November 13, 2017.


(d)	During 2018, as a result of the Huron Divestiture, the Company sold approximately 2.5 million non-core, net acres in the Huron play, however, the Company retained the deep drilling rights across the divested acreage in West Virginia of 0.8 million, which is excluded from the acreage totals above.

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The Company sells natural gas and NGLs within the Appalachian Basin and in markets accessible through its transportation portfolio 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, 2018, the Company’s delivery commitments for the next five years were as follows:



For the Year Ended December 31,	Natural Gas (Bcf)	Natural Gas Liquids (Mbbls)
2019	1,298	3,817
2020	902	1,841
2021	769	1,836
2022	577	1,833
2023	504	1,825

During the year ended December 31, 2018, the Company’s total proved developed reserves increased by 252 Bcfe. The increase in proved developed reserves was primarily due to the conversion of approximately 2,722 Bcfe of proved undeveloped reserves to proved developed reserves, an upward revision of 459 Bcfe from processing, ownership changes, and other revisions and the addition of 315 Bcfe due to extensions, discoveries, and other additions that were not previously recorded as proved reserves. These increases were partly offset by the sale of hydrocarbons in place of 1,749 Bcfe associated with the 2018 Divestitures as described in Note 8 and 2018 production of 1,495 Bcfe.

The Company’s 2018 extensions, discoveries and other additions totaled 4,739 Bcfe, which exceeded the 2018 production of 1,495 Bcfe. Of these, 315 Bcfe of proved developed reserves were extensions from reservoirs underlying acreage not previously booked as proved, 886 Bcfe of proved undeveloped reserves were extensions from acreage proved by drilling activity, and 3,538 Bcfe of other proved undeveloped additions are associated with acreage that was excluded from prior year proved reserves bookings, but subsequently became proved due to inclusion with the Company’s five year drilling plan.

The Company’s 2018 revisions totaled a downward adjustment of 1,125 Bcfe which was primarily due to the removal of certain proved undeveloped locations that are no longer expected to be developed within 5 years of initial booking as proved reserves, resulting from changes in Company’s future development plans to focus more heavily on developing the Company’s core Pennsylvania assets.

Wells located in Pennsylvania and West Virginia are primarily in Marcellus formations with depths ranging from 5,000 feet to 8,500 feet. Wells located in Ohio are primarily in Utica formations with depths ranging from 8,500 feet to 10,500 feet.

The Company’s corporate headquarters is located in leased office space in Pittsburgh, Pennsylvania. The Company also owns or leases office space in Pennsylvania, West Virginia and Ohio.

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.

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Item 3. Legal Proceedings

In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal 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 condition, results of operations or liquidity of the Company.

Environmental Proceedings

Phoenix S Impoundment, Tioga County, Pennsylvania

In June and August 2012, the Company received three Notices of Violation (NOVs) from 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. 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 PADEP’s legal interpretation of the penalty provisions of the Clean Streams Law, which interpretation the Company believed was legally flawed and unsupportable. On October 7, 2014, based on its interpretation of the penalty provisions, the PADEP filed a complaint against the Company before the Pennsylvania Environmental Hearing Board (the EHB) seeking $4.53 million in civil penalties. In January 2017, the Commonwealth Court ruled in favor of the Company, finding the PADEP’s interpretation of the penalty provisions of the Clean Streams Law erroneous. The PADEP appealed that decision to the Pennsylvania Supreme Court, and the parties made oral arguments in front of the Pennsylvania Supreme Court on November 28, 2017. Following a July 2016 hearing before the EHB, in May 2017, the EHB ruled that the Company should pay $1.1 million in civil penalties. In June 2017, both the Company and the PADEP appealed the EHB’s decision to the Commonwealth Court. In September 2018, the Commonwealth Court upheld the $1.1 million civil penalty, which the Company paid in November 2018. The payment of the civil penalty did not have a material impact on the financial condition, results of operations or liquidity of the Company.

Fresh Water Pipeline Bore Release, Allegheny County, Pennsylvania

On February 24, 2017, the Company received an NOV from the PADEP. The NOV alleged violations of the Pennsylvania Oil and Gas Act and Clean Streams Law related to an unintentional release, by a Company vendor, of mine water into the Monongahela River in January 2017 from a mine void that was pierced while boring under a road for the installation of a fresh water pipeline in Allegheny County, Pennsylvania. The Company cooperated with the PADEP to take appropriate actions to stop the release. On February 15, 2017, the Company entered into a civil penalty settlement related to the release with the Pennsylvania Fish and Boat Commission for $4,555 for alleged violations of the Pennsylvania Fish and Boat Code. In November 2018, the Company and the PADEP entered into a settlement agreement related to the release. Under the terms of the agreement, the Company paid a civil penalty of $294,000 and provided $100,000 in trust for future maintenance of a mine water drain. The payments did not have a material impact on the financial condition, results of operations or liquidity of the Company.

Wilson Creek Water Withdrawals, Tioga County, Pennsylvania

On June 7, 2018, the Company received an NOV from the Susquehanna River Basin Commission (the SRBC). The NOV alleged violations of the Company’s Water Management Plan and its Wilson Creek Docket related to the withdrawal of water from Wilson Creek between March 14, 2018 and April 3, 2018, when the stream flow was below the required flow protection threshold. The Company cooperated fully with the SRBC to address the matter. On December 18, 2018, the Company and the SRBC agreed to settle this matter and the Company paid a civil penalty of $120,000. The payment of the civil penalty did not have a material impact on the financial condition, results of operations or liquidity of the Company.

Erosion and Sedimentation Releases, Allegheny County, Pennsylvania

Between November 2017 and March 2018, the Company received multiple NOVs from the PADEP relating to four of the Company’s well pads in Allegheny County, Pennsylvania. During this time period, Pennsylvania experienced unprecedented amounts of rainfall. The NOVs alleged violations of the Oil and Gas Act, and Clean Streams Law in connection with the effects

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of the rainfall on erosion and sedimentation controls at the Prentice, Fetchen, Oliver East, and Oliver West well pads. The Company cooperated fully with the PADEP to take appropriate actions to address the erosion and sedimentation control issues. The Company and the PADEP are currently negotiating a civil penalty settlement. While the Company expects the PADEP’s claims to result in penalties that exceed $100,000, the Company expects that the resolution of this matter will not have a material impact on the financial condition, results of operations or liquidity of the Company.

Phoenix S Pad Well Control Incident, Tioga County, Pennsylvania

On December 1, 2017 and May 1, 2018, the Company received NOVs from the PADEP relating to a well control incident that occurred at a Phoenix S well on November 12, 2017. The well was brought back under control, but in the interim natural gas was vented to the atmosphere and flowback water was released to the ground water and a stream. The Company fully cooperated with the PADEP and took appropriate actions to address the environmental impacts from the incident. On January 22, 2019, the Company and the PADEP agreed to settle this matter and the Company agreed to pay a civil penalty of $138,000 to resolve the matter. The payment of the civil penalty did not have a material impact on the financial condition, results of operations or liquidity of the Company.

Other Legal Proceedings

Kay Company, LLC, et al. v. EQT Production Company, et al., United States District Court for the Northern District of West Virginia

On January 16, 2013, several royalty owners who had entered into leases with EQT Production Company, a subsidiary of the Company, filed a gas royalty class action lawsuit in the Circuit Court of Doddridge County, West Virginia. The suit alleged that EQT Production Company and a number of related companies, including the Company, EQT Energy, LLC, EQT Investments Holdings, LLC, EQM (the Company’s former midstream affiliate) and Equitrans Gathering Holdings, LLC (formerly known as EQT Gathering Holdings, LLC, and a former subsidiary of the Company), failed to pay royalties on the fair value of the gas produced from the leases and took improper post-production deductions from the royalties paid. The plaintiffs sought more than $100 million (according to expert reports) in compensatory damages, punitive damages, and other relief. On May 31, 2013, the defendants removed the lawsuit to federal court. On September 6, 2017, the district court granted the plaintiffs’ motion to certify the class and granted the plaintiffs’ motion for summary judgment, finding that EQT Production Company and its marketing affiliate EQT Energy, LLC are alter egos of one another. The defendants sought immediate appeal of the class certification. On November 30, 2017, the Court of Appeals declined the request for an immediate review. On February 13, 2019, the Company announced that it and the other defendants reached a tentative settlement agreement with the class representatives. Pursuant to the terms of the proposed settlement agreement, the Company agreed to pay $53.5 million into a settlement fund that will be established to disburse payments to class participants, and stop taking future post production deductions on leases that are determined by the Court to not permit deductions. The Company and the class representatives also agreed that future royalty payments will be based on a clearly defined index pricing methodology. The tentative settlement agreement is subject to Court approval and achieving a threshold minimum percentage of participation by the class members. Each class member will have the opportunity to opt out of the settlement. If approved, the settlement will resolve the royalty claims for the class period, which spans from 2009 through 2017.

Item 4. Mine Safety Disclosures

Not Applicable.

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Executive Officers of the Registrant (as of February 14, 2019)



Name and Age	Current Title (Year Initially Elected an Executive Officer)	Business Experience
Erin R. Centofanti (43)	Executive Vice President, Production (2018)	Elected to present position October 2018. Ms. Centofanti served as Senior Vice President, Asset Development, EQT Production Company, from March 2017 to October 2018; Senior Vice President, Engineering, EQT Production Company, from November 2014 to March 2017; Vice President, Commercial Operations, EQT Energy, LLC, from February 2014 to November 2014; and Vice President, Business Development, EQT Production Company, from July 2011 to February 2014.
Donald M. Jenkins (46)	Executive Vice President, Commercial Business Development, Information Technology and Safety (2017)	Elected to present position November 2018. Mr. Jenkins served as the Company’s Chief Commercial Officer from March 2017 to November 2018; Executive Vice President, Commercial, EQT Energy, LLC, from May 2014 to February 2017; and Senior Vice President, Trading and Origination, EQT Energy, LLC, from December 2012 to May 2014.
Jonathan M. Lushko (43)	General Counsel and Senior Vice President, Government Affairs (2018)	Elected to present position October 2018. Mr. Lushko served as the Company’s Deputy General Counsel, Governance & Enterprise Risk, from May 2017 to October 2018. Mr. Lushko joined the Company in 2006 as Counsel, and later served as Senior Counsel prior to assuming the role of Deputy General Counsel, Governance & Enterprise Risk in May 2017.
Robert J. McNally (48)	President and Chief Executive Officer (2016)	Elected to present position November 2018. Mr. McNally served as Senior Vice President and Chief Financial Officer of the Company from March 2016 to November 2018, and in March 2017 he assumed additional management responsibilities for the Business Development, Facilities, Information Technology, Innovation, and Procurement functions. Mr. McNally served as a Director and Senior Vice President and Chief Financial Officer of the general partners of EQM Midstream Partners, LP and EQGP Holdings, LP (master limited partnerships formed by the Company and divested by the Company as part of the Separation, from March 2016 to October 2018. He also served as a Director and Senior Vice President and Chief Financial Officer of the general partner of Rice Midstream Partners LP (former master limited partnership acquired by the Company through its acquisition of Rice Energy Inc.) from November 2017 to July 2018. Prior to joining the Company, Mr. McNally served as Executive Vice President and Chief Financial Officer of Precision Drilling Corporation, a publicly traded drilling services company, from July 2010 to March 2016. Mr. McNally is also a Director of the Company, having served on the Company’s Board of Directors since November 2018.
Jeffery C. Mitchell (46)	Vice President and Principal Accounting Officer (2018)	Elected to present position November 2018. Mr. Mitchell served as Vice President and Controller of the Company’s production business from March 2015 to November 2018; Corporate Director, Internal Audit, from March 2013 to March 2015; and Corporate Director, Internal Audit and Financial Risk, from October 2011 to March 2013.
David J. Smith (60)	Senior Vice President, Human Resources (2018)	Elected to present position November 2018. Mr. Smith served as Corporate Director, Compensation and Benefits, of the Company from February 1995 to November 2018.
Jimmi Sue Smith (46)	Senior Vice President and Chief Financial Officer (2016)	Elected to present position November 2018. Ms. Smith served as the Company’s Chief Accounting Officer from September 2016 to November 2018; Vice President and Controller of the Company’s midstream and commercial businesses from March 2013 to September 2016; and Vice President and Controller of the Company’s midstream business from January 2013 through March 2013. Ms. Smith also served as Chief Accounting Officer of the general partners of EQM Midstream Partners, LP and EQGP Holdings, LP from September 2016 to October 2018, and served as the Chief Accounting Officer of the general partner of Rice Midstream Partners LP, from November 2017 to July 2018.

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 trading under the ticker symbol "EQT."

As of January 31, 2019, there were 2,188 shareholders of record of the Company’s common stock.

The amount and timing of dividends declared and paid by the Company, if any, is subject to the discretion of the Company's Board of Directors and depends upon business conditions, such as the Company’s results of operations and financial condition, strategic direction and other factors. The Company's Board of Directors has the discretion to change the annual dividend rate at any time for any reason.

Recent Sales of Unregistered Securities

None.

Market Repurchases

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, 2018:



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	Approximate dollar value of shares that may yet be purchased under plans or programs
October 2018 (October 1 – October 31)	424	$	46.78	—	$	—
November 2018 (November 1 – November 30)	25,332	31.35		—	—
December 2018 (December 1 – December 31)	242	17.20		—	—
Total	25,998	$	31.47	—	—

(a) Reflects the number of shares withheld by the Company to pay taxes upon vesting of restricted stock plus the number of shares purchased as part of publicly announced plans or programs.

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 two customized peer groups. The individual companies of the 2017 customized peer group (the 2017 Self-Constructed Peer Group) and the 2018 customized peer group (the 2018 Self-Constructed Peer Group) are listed in footnotes (a) and (b) below, respectively. An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2013 in the Company’s common stock, in the S&P 500 Index and in each of the customized peer groups. Historical prices prior to the Separation and Distribution in November 2018 have been adjusted to reflect the value of the Separation and Distribution transactions. Relative performance is tracked through December 31, 2018.

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	12/13		12/14		12/15		12/16		12/17		12/18
EQT Corporation	$	100.00	$	84.42	$	58.23	$	73.18	$	63.82	$	39.05
S&P 500	100.00		113.69		115.26		129.05		157.22		150.33
2017 Self-Constructed Peer Group (a)	100.00		83.34		51.53		76.10		71.46		53.20
2018 Self-Constructed Peer Group (b)	100.00		86.64		55.75		81.24		75.12		53.95

*The stock price performance included in this graph is not necessarily indicative of future stock price performance.

(a)

The 2017 Self-Constructed Peer Group includes the following twenty-one companies: Antero Resources Corp, Cabot Oil & Gas Corp, Chesapeake Energy Corp, Cimarex Energy Co, CNX Resources Corp, Concho Resources Inc., Continental Resources, Inc., Devon Energy Corp, EOG Resources, Inc., EXCO Resources, Inc., Marathon Oil Corp, National Fuel Gas Co, Newfield Exploration Co, Noble Energy, Inc., ONEOK, Inc., Pioneer Natural Resources Co, QEP Resources, Inc., Range Resources Corp, SM Energy Co, Southwestern Energy Co and Whiting Petroleum Corp. Energen Corp was included in the self-constructed peer group that served as the basis for the stock performance graph in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 but has been excluded from the 2017 Self-Constructed Peer Group because it was acquired.

(b)

The 2018 Self-Constructed Peer Group includes the following nineteen companies: Anadarko Petroleum Corp, Antero Resources Corp, Apache Corp, Cabot Oil & Gas Corp, Chesapeake Energy Corp, Cimarex Energy Co, CNX Resources Corp, Concho Resources Inc., Continental Resources, Inc., Devon Energy Corp, Diamondback Energy, Inc., Encana Corp, EOG Resources, Inc., Hess Corp, Marathon Oil Corp, Newfield Exploration Co, Noble Energy, Inc., Pioneer Natural Resources Co and Range Resources Corp. The 2018 Self-Constructed Peer Group is the peer group that is used for the Company’s 2018 Incentive Performance Share Unit Program, which utilizes three-year total shareholder return against the peer group as one performance metric. Changes in the 2018 Self-Constructed Peer Group compared to the 2017 Self-Constructed Peer Group were made to reflect the change in size and business operations of the Company.

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Equity Compensation Plans

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

Item 6. Selected Financial Data

The Following selected financial data should be read in conjunction with Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Item 8 "Financial Statements and Supplementary Data," both contained herein.



	As of and for the Years Ended December 31,
	2018			2017		2016			2015			2014
	(Thousands, except per share amounts)
Total operating revenues	$	4,557,868		$	3,091,020	$	1,387,054		$	2,131,664		$	2,285,138

Amounts attributable to EQT Corporation:
(Loss) income from continuing operations	$	(2,380,920	)	$	1,387,029	$	(531,493	)	$	(87,274	)	$	256,791
Income from discontinued operations, net of tax	136,352			121,500		78,510			172,445			130,174
Net (loss) income	$	(2,244,568	)	$	1,508,529	$	(452,983	)	$	85,171		$	386,965

Earnings per share of common stock attributable to EQT Corporation:
Basic:
(Loss) income from continuing operations	$	(9.12	)	$	7.40	$	(3.18	)	$	(0.57	)	$	1.69
Income from discontinued operations	0.52			0.65		0.47			1.13			0.86
Net (loss) income	$	(8.60	)	$	8.05	$	(2.71	)	$	0.56		$	2.55

Diluted:
(Loss) income from continuing operations	$	(9.12	)	$	7.39	$	(3.18	)	$	(0.57	)	$	1.68
Income from discontinued operations	0.52			0.65		0.47			1.13			0.86
Net (loss) income	$	(8.60	)	$	8.04	$	(2.71	)	$	0.56		$	2.54

Total assets	$	20,721,344		$	29,522,604	$	15,472,922		$	13,976,172		$	12,035,353
Total long-term debt (including current portion)	$	5,497,381		$	5,997,329	$	2,427,020		$	2,299,942		$	2,466,720

Cash dividends declared per share of common stock	$	0.12		$	0.12	$	0.12		$	0.12		$	0.12

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

You should read the following discussion and analysis of financial condition and results of operations in conjunction with the consolidated financial statements, and the notes thereto, included in Item 8 of this Annual Report on Form 10-K. The Statements of Consolidated Operations and Consolidated Balance Sheets of Equitrans Midstream are reflected as discontinued operations for all periods presented. Prior periods have been recast to reflect this presentation. This recast also includes presenting certain transportation and processing expenses in continuing operations for all periods presented which were previously eliminated in consolidation prior to the Separation and Distribution. The cash flows related to Equitrans Midstream have not been segregated and are included within the Statements of Consolidated Cash Flows for all periods presented. See Note 2 to the Consolidated Financial Statements for amounts of the discontinued operations related to Equitrans Midstream which are included in the Statements of Consolidated Cash Flows.

Consolidated Results of Operations

Key Events in 2018:


•	Completed the Separation and Distribution on November 12, 2018


•	Completed the 2018 Divestitures


•	Achieved annual sales volumes of 1,488 Bcfe and average daily sales volumes of 4,076 MMcfe/d. Adjusted for the impact of the 2018 Divestitures, total annual sales volumes were 1,447 Bcfe or 3,964 MMcfe/d.

See further discussion of the Separation, Distribution and the 2018 Divestitures as discussed in the "Key Events in 2018" section of Item 1, "Business."

Loss from continuing operations for 2018 was $2.4 billion, a loss of $9.12 per diluted share, compared with income from continuing operations of $1.4 billion, $7.39 per diluted share, in 2017. The $3.8 billion decrease was primarily attributable to $3.5 billion of impairments and losses on the sale of long-lived assets including: $2.7 billion associated with the 2018 Divestitures, goodwill impairment and higher lease impairments. Excluding these items, a $1.5 billion increase in operating revenues was offset by higher operating expenses including depreciation and depletion and transportation and processing expenses and higher interest expense as well as a lower tax benefit.

Income from continuing operations for 2017 was $1.4 billion, $7.39 per diluted share, compared with a loss from continuing operations of $0.5 billion, a loss of $3.18 per diluted share, in 2016. The $1.9 billion increase in income from continuing operations was primarily attributable to higher sales of natural gas, oil and NGLs, an income tax benefit recorded as a result of the lower federal corporate tax rate beginning in 2018 and a gain on derivatives not designated as hedges in 2017 compared to a loss in 2016, partly offset by higher operating expenses, higher interest expense and a loss on debt extinguishment in 2017.

See “Sales Volumes and Revenues” and “Operating Expenses” for a discussion of items impacting operating income and “Other Income Statement Items” for a discussion of other income statement items.

Average Realized Price Reconciliation

The following table presents detailed natural gas and liquids operational information to assist in the understanding of the Company’s consolidated operations, including the calculation of the Company's average realized price ($/Mcfe), which is based on adjusted operating revenues, a non-GAAP supplemental financial measure. Adjusted 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. Adjusted operating revenues should not be considered as an alternative to total operating revenues. See “Reconciliation of Non-GAAP Financial Measures” for a reconciliation of adjusted operating revenues to total operating revenues.

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	Years Ended December 31,
	2018 (e)			2017 (e)			2016
	(Thousands, unless noted)
NATURAL GAS
Sales volume (MMcf)	1,386,718			774,076			683,495
NYMEX price ($/MMBtu) (a)	$	3.10		$	3.09		$	2.47
Btu uplift	$	0.19		$	0.27		$	0.22
Natural gas price ($/Mcf)	$	3.29		$	3.36		$	2.69

Basis ($/Mcf) (b)	(0.25		)	(0.54		)	(0.81		)
Cash settled basis swaps (not designated as hedges) ($/Mcf)	$	(0.08	)	$	0.01		$	0.09
Average differential, including cash settled basis swaps ($/Mcf)	$	(0.33	)	$	(0.53	)	$	(0.72	)

Average adjusted price ($/Mcf)	$	2.96		$	2.83		$	1.97
Cash settled derivatives (cash flow hedges) ($/Mcf)	—			0.01			0.13
Cash settled derivatives (not designated as hedges) ($/Mcf)	(0.07		)	0.05			0.31
Average natural gas price, including cash settled derivatives ($/Mcf)	$	2.89		$	2.89		$	2.41

Natural gas sales, including cash settled derivatives	$	4,004,147		$	2,237,234		$	1,649,831

LIQUIDS
NGLs (excluding ethane):
Sales volume (MMcfe) (c)	63,247			74,060			57,243
Sales volume (Mbbls)	10,542			12,343			9,540
Price ($/Bbl)	$	37.63		$	31.59		$	19.43
Cash settled derivatives (not designated as hedges) ($/Bbl)	(1.07		)	(0.69		)	—
Average NGL price, including cash settled derivatives ($/Bbl)	$	36.56		$	30.90		$	19.43
NGLs sales	$	385,364		$	381,327		$	185,405
Ethane:
Sales volume (MMcfe) (c)	33,645			33,432			13,856
Sales volume (Mbbls)	5,607			5,572			2,309
Price ($/Bbl)	$	8.09		$	6.32		$	5.08
Ethane sales	$	45,339		$	35,241		$	11,742
Oil:
Sales volume (MMcfe) (c)	4,079			5,952			4,373
Sales volume (Mbbls)	680			992			729
Price ($/Bbl)	$	52.70		$	40.70		$	34.73
Oil sales	$	35,825		$	40,376		$	25,312

Total liquids sales volume (MMcfe) (c)	100,971			113,444			75,472
Total liquids sales volume (Mbbls)	16,829			18,907			12,578

Liquids sales	$	466,528		$	456,944		$	222,459

TOTAL PRODUCTION
Total natural gas & liquids sales, including cash settled derivatives (d)	$	4,470,675		$	2,694,178		$	1,872,290
Total sales volume (MMcfe)	1,487,689			887,520			758,967

Average realized price ($/Mcfe)	$	3.01		$	3.04		$	2.47


(a)	The Company’s volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/MMBtu) was $3.09, $3.11 and $2.46 for the years ended December 31, 2018, 2017 and 2016, respectively).


(b)	Basis represents the difference between the ultimate sales price for natural gas and the NYMEX natural gas price.


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


(d)	Also referred to in this report as adjusted operating revenues, a non-GAAP supplemental financial measure.


(e)	For the year ended December 31, 2018, results include operations acquired in the Rice Merger (defined in Note 3 to the Consolidated Financial Statements). For the year ended December 31, 2017, results include operations acquired in the Rice Merger for the period of November 13, 2017 through December 31, 2017.

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Reconciliation of Non-GAAP Financial Measures

The table below reconciles adjusted operating revenues, a non-GAAP supplemental financial measure, to total operating revenues, its most directly comparable financial measure calculated in accordance with GAAP.

Adjusted operating revenues (also referred to as total natural gas & liquids sales, including cash settled derivatives) is presented because it is an important measure used by the Company’s management to evaluate period-over-period comparisons of earnings trends. Adjusted operating revenues as presented excludes the revenue impact of changes in the fair value of derivative instruments prior to settlement and the revenue impact of "Net marketing services and other". Management utilizes adjusted operating revenues to evaluate earnings trends because the measure reflects only the impact of settled derivative contracts and thus does not impact the revenue from natural gas sales with the often volatile fluctuations in the fair value of derivatives prior to settlement. Adjusted operating revenues also excludes "Net marketing services and other" because management considers these revenues to be unrelated to the revenues for its natural gas and liquids production. "Net marketing services and other" primarily includes the cost of and recoveries on pipeline capacity not used for the Company's sales volumes and revenues for gathering services. Management further believes that adjusted operating revenues as presented provides useful information to investors for evaluating period-over-period earnings trends.



Adjusted operating revenues	Years Ended December 31,
	2018			2017			2016
	(Thousands, unless noted)
Total operating revenues	$	4,557,868		$	3,091,020		$	1,387,054
(Deduct) add back:
Loss (gain) on derivatives not designated as hedges	178,591			(390,021		)	248,991
Net cash settlements (paid) received on derivatives not designated as hedges	(225,279		)	40,728			279,425
Premiums received (paid) for derivatives that settled during the year	435			2,132			(2,132		)
Net marketing services and other	(40,940		)	(49,681		)	(41,048		)
Adjusted operating revenues, a non-GAAP financial measure	$	4,470,675		$	2,694,178		$	1,872,290

Total sales volumes (MMcfe)	1,487,689			887,520			758,967

Average realized price ($/Mcfe)	$	3.01		$	3.04		$	2.47

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Sales Volumes and Revenues



	Years Ended December 31,
	2018 (c)			2017 (c)		% change 2018 - 2017		2016			% change 2017 - 2016
Sales volume detail (MMcfe):
Marcellus (a)	1,229,934			770,620		59.6		660,146			16.7
Ohio Utica	209,428			24,266		763.1		536			4,427.2
Other	48,327			92,634		(47.8	)	98,285			(5.7	)
Total sales volumes (b)	1,487,689			887,520		67.6		758,967			16.9

Average daily sales volumes (MMcfe/d)	4,076			2,432		67.6		2,074			17.3

Average realized price ($/Mcfe)	$	3.01		$	3.04	(1.0	)	$	2.47		23.1

Revenues (thousands):
Sales of natural gas, oil and NGLs	$	4,695,519		$	2,651,318	77.1		$	1,594,997		66.2
Net marketing services and other	40,940			49,681		(17.6	)	41,048			21.0
(Loss) gain on derivatives not designated as hedges	(178,591		)	390,021		(145.8	)	(248,991		)	(256.6	)
Total operating revenues	$	4,557,868		$	3,091,020	47.5		$	1,387,054		122.8


(a)	Includes Upper Devonian wells.


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


(c)	For the year ended December 31, 2018, results include operations acquired in the Rice Merger (defined in Note 3 to the Consolidated Financial Statements). For the year ended December 31, 2017, results include operations acquired in the Rice Merger for the period of November 13, 2017 through December 31, 2017.

Total operating revenues were $4,557.9 million for 2018 compared to $3,091.0 million for 2017. Sales of natural gas, oil and NGLs increased as a result of a 68% increase in sales volumes in 2018, which was primarily a result of the Rice Merger and increased production from the 2016 and 2017 drilling programs, partly offset by the 2018 Divestitures and the normal production decline in the Company’s producing wells. The average realized price decreased in 2018 compared to 2017 due to a decrease in the average NYMEX natural gas price net of cash settled derivatives and a decrease in higher priced liquids sales as a result of the 2018 Divestitures partly offset by an increase in the average natural gas differential. The Company paid $225.3 million and received $40.7 million of net cash settlements for derivatives not designated as hedges for the years ended December 31, 2018 and 2017, respectively, that are included in the average realized price but are not in GAAP operating revenues. Changes in fair market value of derivative instruments prior to settlement are recognized in (loss) gain on derivatives not designated as hedges. The increase in the average differential primarily related to higher prices during the first quarter of 2018 at sales points in the United States Northeast where colder weather led to increased demand, higher Appalachian Basin basis as well as increased sales volumes at higher priced Gulf Coast and Midwest markets accessible through the Company’s increased transportation portfolio following the Rice Merger.

Total operating revenues for 2018 included a $178.6 million loss on derivatives not designated as hedges compared to a $390.0 million gain on derivatives not designated as hedges in 2017. The loss in 2018 primarily related to decreases in the fair market value of the Company’s 2018 NYMEX swaps and options and basis swaps from December 31, 2017 through the date of settlement as a result of increases in the underlying prices throughout this period. These losses were partly offset by increases in the fair market value of the Company's open NYMEX positions at December 31, 2018 due to a decrease in forward NYMEX during 2018.

Total operating revenues were $3,091.0 million for 2017 compared to $1,387.1 million for 2016. Sales of natural gas, oil and NGLs increased as a result of higher average realized price and a 17% increase in sales volumes in 2017. EQT received $40.7 million and $279.4 million of net cash settlements for derivatives not designated as hedges for the years ended December 31, 2017 and 2016, respectively, that are included in the average realized price but are not in GAAP operating revenues. The increase in sales volumes was primarily the result of acquisition activity, including the Rice Merger, as well as increased production from the 2015 and 2016 drilling programs, primarily in the Marcellus play, partially offset by the normal production decline in the Company's producing wells in 2017.

The $0.57 per Mcfe increase in the average realized price for the year ended December 31, 2017 was primarily due to the

increase in the average NYMEX natural gas price net of cash settled derivatives of $0.29 per Mcf, an increase in the average natural gas differential of $0.19 per Mcf and an increase in liquids prices. The improvement in the average differential primarily

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related to more favorable basis partly offset by unfavorable cash settled basis swaps. During 2017, basis improved in the Appalachian Basin and at sales points reached through the Company’s transportation portfolio, particularly in the United States Northeast. In addition, the Company started flowing its produced volumes to its Rockies Express pipeline capacity and Texas Eastern Transmission Gulf Markets pipeline capacity in the fourth quarter of 2016, which resulted in a favorable impact to basis for the year ended December 31, 2017 compared to the year ended December 31, 2016.

Total operating revenues for the year ended December 31, 2017 included a $390.0 million gain on derivatives not designated as hedges compared to a $249.0 million loss on derivatives not designated as hedges for the year ended December 31, 2016. The gains for the year ended December 31, 2017 primarily related to increases in the fair market value of the Company’s NYMEX swaps due to decreased NYMEX prices, partly offset by decreases in the fair market value of its basis swaps due to increased basis prices.

Operating Expenses

The following presents information about certain of the Company's operating expenses for each of the last three years.



	Years Ended December 31,
	2018		2017		% change 2018 - 2017		2016		% change 2017 - 2016
	(Thousands, unless otherwise noted)
Per Unit ($/Mcfe)
Gathering	$	0.54	$	0.55	(1.8	)	$	0.55	—
Transmission	$	0.49	$	0.56	(12.5	)	$	0.45	24.4
Processing	$	0.11	$	0.20	(45.0	)	$	0.16	25.0
Lease operating expenses (LOE), excluding production taxes	$	0.07	$	0.13	(46.2	)	$	0.15	(13.3	)
Production taxes	$	0.06	$	0.08	(25.0	)	$	0.08	—
Exploration	$	—	$	0.02	(100.0	)	$	0.01	100.0
Selling, general and administrative (SG&A)	$	0.19	$	0.24	(20.8	)	$	0.29	(17.2	)
Production depletion	$	1.04	$	1.04	—		$	1.06	(1.9	)

Operating expenses:
Gathering	$	801,746	$	489,610	63.8		$	413,758	18.3
Transmission	$	729,537	$	495,635	47.2		$	341,569	45.1
Processing	$	165,718	$	179,538	(7.7	)	$	124,864	43.8
LOE, excluding production taxes	$	100,644	$	112,501	(10.5	)	$	111,853	0.6
Production taxes	$	95,131	$	68,848	38.2		$	62,317	10.5
Exploration	$	6,765	$	17,565	(61.5	)	$	4,663	276.7
Selling, general and administrative	$	284,220	$	208,986	36.0		$	218,946	(4.5	)

Gathering. Gathering expense increased on an absolute basis in 2018 compared to 2017 due to the 68% increase in sales volumes partly offset by a lower gathering rate per unit on gathering capacity acquired in the Rice Merger, which also decreased the rate per Mcfe. Gathering expense increased in 2017 compared to 2016 on an absolute basis due to increased gathering capacity and expense from the Company’s 2016 and 2017 acquisitions.

Transmission. Transmission expense increased on an absolute basis in 2018 compared to 2017 due to increased third party capacity incurred to move the Company’s natural gas out of the Appalachian Basin, primarily firm capacity acquired in connection with the Rice Merger, the Company's capacity on the Rover pipeline, which started in 2018, as well as an increase in the Company’s firm capacity on Columbia Gas Transmission pipeline which increased in the first quarter of 2018. These increases were partly offset by reduced firm capacity costs as a result of the Huron Divestiture. Transmission expense per Mcfe decreased as a result of increased sales volumes in 2018. Transmission expense increased on an absolute basis in 2017 compared to 2016 due to increased capacity incurred to move the Company’s natural gas out of the Appalachian Basin. During the fourth quarter of 2016, the Company started flowing its produced volumes to its Rockies Express and Texas Eastern Transmission Gulf Markets pipeline capacity. Additionally, the Company's firm capacity on Rockies Express pipeline increased in the first quarter of 2017. Firm capacity acquired in connection with the Rice Merger also increased transmission expenses by approximately $24.2 million. Transmission expense per Mcfe increased in 2017 compared to 2016 as the impact of the above items exceeded the 17% growth in sales volumes during the period.

Processing. Processing expense decreased on an absolute basis in 2018 compared to 2017 primarily as a result of the 2018 Divestitures and decreased on a per Mcfe basis as a result of a 68% increase in sales volumes when combined with the impact

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of the 2018 Divestitures. Processing expense increased on an absolute basis in 2017 compared to 2016 as a result of increased processing capacity acquired through acquisitions and higher volumes processed, which is consistent with higher ethane and NGLs sales volumes of approximately 50% in 2017 compared to 2016. These factors also contributed to an increase in processing expense on a per Mcfe basis as they exceeded the offsetting impact of growth in sales volumes during the period.

LOE. LOE decreased on an absolute and per Mcfe basis in 2018 compared to 2017 primarily as a result of the 2018 Divestitures and growth in sales volumes in 2018 partly offset by higher salt water disposal costs and personnel costs due to increased activity in the Company's Marcellus and Utica operations. Excluding the costs related to the 2018 Divestitures, per unit LOE was $0.05 per Mcfe in 2018 as compared to a divestiture adjusted $0.07 per Mcfe in 2017. LOE increased on an absolute basis in 2017 compared to 2016 primarily due to increased salt water disposal costs as a result of increased activity in the Company’s Marcellus operations, but decreased on a per Mcfe basis due to the growth in sales volumes during the period.

Production taxes. Production taxes increased on an absolute basis in 2018 compared to 2017 primarily as a result of the significant increase in the number of wells subject to the Pennsylvania Impact Fee as well as the increased asset base and production volumes in Ohio following the Rice Merger, partly offset by the lower asset base and production volumes in Kentucky, West Virginia, Virginia and Texas following the 2018 Divestitures. Production taxes decreased on a per Mcfe basis in 2018 compared to 2017 due to an increase in sales volumes. Production taxes increased on an absolute basis in 2017 compared to 2016 as a result of higher market prices in 2017 in combination with an increase in the number of wells subject to the Pennsylvania Impact Fee as well as an increased asset base and production from acquisitions.

Exploration. Exploration expense decreased in 2018 compared to 2017 and increased in 2017 compared to 2016 on an absolute and per Mcfe basis, primarily due to expenses related to an exploratory well in a non-core operating area classified as a dry hole in 2017.

SG&A. SG&A expense increased on an absolute basis in 2018 compared to 2017, primarily due to increased legal reserves, increased charitable contributions to the EQT Foundation and increased personnel costs associated with workforce reductions. SG&A expense decreased on an absolute basis in 2017 compared 2016, primarily due to lower pension expense related to the termination of the EQT Corporation Retirement Plan for Employees in the second quarter of 2016, lower legal reserves in 2017, a reduction to the reserve for uncollectible accounts, and the absence of costs related to the consolidation of the Company’s Huron operations in 2016. This was partly offset by higher costs associated with acquisitions. SG&A expense per Mcfe decreased in 2018 compared to 2017 and in 2017 compared 2016 due to an increase in sales volumes for each respective period.

Depreciation and depletion. Depreciation and depletion increased as a result of higher produced volumes in 2018, partly offset by lower depreciation as a result of the 2018 Divestitures. Depreciation and depletion increased as a result of higher produced volumes partly offset by a lower overall depletion rate in 2017 compared to 2016.

Years Ended December 31,

2018