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

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

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

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.

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

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

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

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.

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

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.

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.