Item 1. Business

General

EQT is a natural gas production company with operations focused in the Marcellus and Utica shales of the Appalachian Basin. Based on average daily sales volumes, EQT is the largest producer of natural gas in the United States. As of December 31, 2019, EQT had 17.5 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 1.3 million gross acres, including approximately 1.1 million gross acres in the Marcellus play.

Strategy

The Company is dedicated to responsibly developing its world-class asset base in the core of the Appalachian Basin. The Company believes its asset scale and contiguity of its acreage position differentiates it from its Appalachian Basin peers and that its evolution into a modern, digitally-enabled exploration and production business will continue to enhance its strategic advantage.

The Company's unique asset base supports a multi-year inventory of combo-development projects in its core acreage position, which consist of developing multiple wells and pads simultaneously. Following a change in leadership in July 2019, the Company implemented an operational strategy designed to leverage this differentiation to become the lowest cost operator in the Appalachian Basin, primarily by focusing on combo-development projects to maximize operational efficiencies. The Company believes that combo-development projects are key to delivering sustainably low well costs and higher returns on invested capital. Beyond cost benefits, combo-development projects maximize reservoir recoveries, mitigate future curtailments and maximize the capital efficiency of the Company's midstream service providers. The Company expects to drill approximately 13 to 25 wells per combo-development project, with average lateral lengths from 12,000 feet to 14,000 feet. The Company's target Pennsylvania Marcellus well cost is $730 per foot, which the Company expects to achieve in the second half of 2020.

In an effort to further the Company's operational strategy and improve the Company's leverage ratio, in the fourth quarter of 2019, the Company announced a plan to reduce its absolute debt using free cash flow and targeted proceeds from the monetization of select, non-strategic exploration and production assets, core mineral assets and the Company's remaining retained equity interest in Equitrans Midstream (the Deleveraging Plan).

2019 Highlights

•	Substantially reconstituted the Company's Board of Directors and senior leadership following the Company's July 2019 annual meeting of shareholders

•

Successfully implemented the 100-Day Transformation Plan, a management-led initiative designed to effect operational, organizational, cultural and other changes to the Company's business that will facilitate long-term planning and prioritize combo-development projects, which are expected to (i) lower well costs, selling, general and administrative costs, land and lease acquisitions capital expenditures and other production infrastructure capital expenditures; (ii) increase drilling efficiencies (measured in horizontal feet drilled per hour); and (iii) increase free cash flow generation

•	Reduced 2019 capital expenditures by $966 million, or 35.3%, compared to 2018

•	Achieved 2019 sales volumes of 1,508 Bcfe and average daily sales volumes of 4,131 MMcfe per day, a year-over-year increase of 1.4%, or 4.2% excluding sales volumes related to the 2018 Divestitures (defined herein)

Outlook

In 2020, the Company expects to spend $1.15 billion to $1.25 billion in total capital expenditures. Planned capital expenditures will be funded by cash generated from operations and allocated as follows: approximately $0.9 billion to reserve development, approximately $150 million to land and lease acquisitions, approximately $85 million to other production infrastructure and approximately $55 million to capitalized overhead. Reserve development capital expenditures will be spent across the Company's three primary operating areas, with approximately 70% spent in Pennsylvania Marcellus, approximately 22% spent in Ohio Utica and approximately 8% spent in West Virginia Marcellus. The Company's 2020 capital expenditure program is expected to deliver sales volumes of 1,450 Bcfe to 1,500 Bcfe, which is in line with 2019 sales volumes, using approximately $500 million less capital funding than the 2019 capital expenditure program.

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, NGLs and oil. Due to the volatility of commodity prices, the Company is unable to predict future potential movements in the market prices for natural gas, NGLs and oil 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 and changes in development plans 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 impairments or downward adjustments to the Company's estimated reserves could potentially be material to the Company.

See "Impairment of Oil and Gas Properties" 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 accounting policies and processes related to impairment reviews for proved and unproved property and goodwill.

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.

Reserves

The following tables summarize the Company's proved natural gas, NGLs and crude oil reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by product and play. Substantially all of the Company's reserves reside in continuous accumulations.

	December 31, 2019
	Natural Gas			NGLs and Crude Oil			Total
	(Bcf)			(MMbbl)			(Bcfe)
Proved developed reserves	11,811			105			12,444
Proved undeveloped reserves	4,866			27			5,025
Total proved reserves	16,677			132			17,469

	December 31, 2019
	Marcellus			Upper Devonian			Ohio Utica			Other			Total
	(Bcfe)
Proved developed reserves	10,513			880			947			104			12,444
Proved undeveloped reserves	4,584			—			441			—			5,025
Total proved reserves	15,097			880			1,388			104			17,469

The following table summarizes the Company's proved developed and undeveloped reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by state.

	December 31, 2019
	Pennsylvania			West Virginia			Ohio			Total
	(Bcfe)
Proved developed producing reserves	8,100			2,786			879			11,765
Proved developed non-producing reserves	522			89			68			679
Proved undeveloped reserves	3,883			701			441			5,025
Total proved reserves	12,505			3,576			1,388			17,469
Gross proved undeveloped drilling locations	179			34			38			251
Net proved undeveloped drilling locations	171			34			29			234

The Company's total proved reserves decreased by 4,348 Bcfe or 19.7% in 2019 from 2018 due to a downward revision of previously proved reserves of 4,907 Bcfe as a result of changes in the Company's development strategy and the production of 1,508 Bcfe, partly offset by extensions, discoveries and other additions of 2,068 Bcfe.

Following a change in leadership in July 2019, the Company implemented a combo-development strategy that refocused operations in the Company's core assets and is driving the execution of new development sequencing processes that emphasize efficiency and productivity. While these efforts are expected to result in an approximate 25% decrease in well costs, they negatively impact proved undeveloped reserves as a result of (i) derecognizing previously-recorded proved undeveloped reserves that are now not included in the Company's substantially revised five-year capital allocation program for purposes of the Company's reserves calculations and (ii) executing a development sequencing strategy that will result in increased probable-to-proved developed conversion.

The following table provides a rollforward of proved undeveloped reserves.

	Proved Undeveloped Reserves
	(Bcfe)
Balance at January 1, 2019	10,267
Conversions into proved developed reserves	(2,646	)
Revisions (a)	(4,508	)
Extensions, discoveries and other additions (b)	1,912
Balance at December 31, 2019	5,025

(a)	Related to proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of implementation of the Company's combo-development strategy.

(b)

Composed of (i) 1,796 Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2019 reserve development that expanded the number of the Company's technically proven locations, implementation of, and alignment with, the Company's combo-development strategy and revisions to the Company's five-year drilling plan; and (ii) 116 Bcfe from extension of proved undeveloped reserves lateral lengths.

As of December 31, 2019, the Company had one well with proved undeveloped reserves of 9.1 Bcfe that had remained undeveloped for more than five years. Completion activities for this well are planned for 2020.

See Note 20 to the Consolidated Financial Statements for further discussion of the preparation of, and year-over-year changes in, the Company's reserves estimate.

Based on the Company's mix of proved undeveloped and probable reserves, the Company estimates an undeveloped drilling inventory of approximately 1,565 net locations in Pennsylvania and West Virginia Marcellus. At the Company's current drilling pace, these net locations provide more than 15 years of drilling inventory based on net undeveloped Marcellus acres, average expected lateral length of 12,000 feet and well spacing of 1,000 feet. The Company believes that its change in development strategy, coupled with its undeveloped inventory located in a premier core asset base, will lead to sustainable free cash flow generation and higher returns on invested capital.

The following table summarizes the Company's capital expenditures for reserve development.

	Years Ended December 31,
	2019				2018				2017
	(Millions)
Marcellus (a)	$	1,184			$	1,889			$	1,134
Utica	193				360				50
Other	—				—				21
Total	$	1,377			$	2,249			$	1,205

(a)	Includes Upper Devonian formations.

Lease operating costs, excluding production taxes for the years ended December 31, 2019, 2018 and 2017 was $0.06, $0.07 and $0.13, respectively.

Properties

The majority of the Company's acreage is held by lease or occupied under perpetual easements or other rights acquired, for the most part, without warranty of underlying land titles. Approximately 29% of the Company's total gross acres is developed.

The following table summarizes acreage disaggregated by state.

	December 31, 2019
	Pennsylvania			West Virginia (a)			Ohio			Kentucky and Virginia (a)			Total
Total gross productive acreage	216,887			107,368			45,211			2,235			371,701
Total gross undeveloped acreage	434,496			396,189			46,690			24,685			902,060
Total gross acreage	651,383			503,557			91,901			26,920			1,273,761
Total net productive acreage	214,933			107,804			31,875			2,163			356,775
Total net undeveloped acreage	398,155			298,788			32,454			22,344			751,741
Total net acreage	613,088			406,592			64,329			24,507			1,108,516
Average net revenue interest of proved developed reserves	80.7	%		78.3	%		43.8	%		—	%		75.3	%

(a)	In 2018, the Company sold approximately 2.5 million non-core, net acres in the Huron play; however, the Company retained deep drilling rights across 1.5 million, 0.2 million and 0.8 million of divested acreage in Kentucky, Virginia and West Virginia, respectively. The retained deep drilling rights have been excluded from acreage totals.

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, 77,444, 50,145 and 52,332 of the Company's net undeveloped acreage as of December 31, 2019 will expire in the years ended December 31, 2020, 2021 and 2022, respectively.

The following tables summarize the Company's productive and in-process natural gas wells. The Company had no productive or in-process oil wells as of December 31, 2019.

	December 31, 2019
Productive wells:
Total gross	3,404
Total net	3,181
In-process wells:
Total gross	186
Total net	178

	December 31, 2019
	Pennsylvania			West Virginia			Ohio			Total
Total gross productive wells (a)	1,913			1,234			257			3,404
Total net productive wells	1,865			1,193			123			3,181

(a)	Of the Company's total gross productive wells, there are 688 gross conventional wells in Pennsylvania and 623 gross conventional wells in West Virginia. There are no gross conventional wells in Ohio.

The following table summarizes the net exploratory and development wells drilled. There were no net productive exploratory wells drilled during the years ended December 31, 2019, 2018 and 2017.

	Years Ended December 31,
	2019			2018			2017
Net exploratory wells:
Dry	—			—			1
Net development wells:
Productive	145			210			149
Dry (a)	—			5			5

(a)	Dry development wells are related primarily to non-core wells that the Company no longer plans to drill to depth or complete, acquired wells with mechanical integrity issues and wells that have been plugged and abandoned due to future mining operations or mechanical integrity issues.

During 2019, the Company commenced drilling operations (spud) on 122 gross wells (114 net), including 89 Pennsylvania Marcellus gross wells (87 net), 6 West Virginia Marcellus gross wells (6 net) and 27 Ohio Utica gross wells (21 net). The Company's Pennsylvania and West Virginia Marcellus wells have average depths of 5,000 feet to 8,500 feet. The Company's Ohio Utica wells have average depths of 8,500 feet to 10,500 feet. The Company retains deep drilling rights on the majority of its acreage.

Sales volumes in 2019 from the Marcellus play, including the Upper Devonian play, were 1,270 Bcfe. The following table summarizes produced and sold volumes by state and reflects the effect of the Company's 2018 sale of approximately 2.5 million non-core, net acres in the Huron play and Permian Basin assets located in Texas (collectively, the 2018 Divestitures) and 2017 acquisition of Rice Energy Inc. (the Rice Merger).

	Pennsylvania			West Virginia			Ohio			Other (a)			Total
	(MMcfe)
Produced and sold natural gas, NGLs and oil for the years ended December 31,
2019	1,001,973			274,378			231,545			—			1,507,896
2018	922,033			323,976			209,428			32,252			1,487,689
2017	456,600			343,199			24,113			63,608			887,520

(a)	Primarily Kentucky and Virginia.

Markets and Customers

Natural Gas Sales. 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 typically lower relative to NYMEX Henry Hub, Louisiana (the location for pricing NYMEX natural gas futures) as a result of the significant increases in the supply of natural gas in the Northeast United States in recent years. 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 at, for the most part, NYMEX natural gas prices. For information on the Company's hedging strategy and its derivative instruments, refer to "Commodity Risk Management" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations," Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 4 to the Consolidated Financial Statements.

NGLs Sales. The Company primarily sells NGLs recovered from its natural gas production. The Company primarily contracts with MarkWest Energy Partners, L.P. (MarkWest) to process its natural gas and extract from the produced natural gas heavier hydrocarbon streams (consisting predominately of ethane, propane, isobutane, normal butane and natural gasoline). The Company also contracts with MarkWest to market a portion of the Company's NGLs. In addition, the Company has contractual arrangements with Williams Ohio Valley Midstream LLC to process its natural gas and market a portion of its NGLs.

Average Sales Price. The following table presents the Company's average sales price per unit of natural gas, NGLs and oil, with and without the effects of cash settled derivatives as applicable.

	Years Ended December 31,
	2019				2018				2017
Natural gas ($/Mcf):
Average sales price, excluding cash settled derivatives	$	2.48			$	3.04			$	2.82
Average sales price, including cash settled derivatives	2.65				2.89				2.89
NGLs, excluding ethane ($/Bbl):
Average sales price, excluding cash settled derivatives	$	23.63			$	37.63			$	31.59
Average sales price, including cash settled derivatives	25.82				36.56				30.90
Ethane ($/Bbl):
Average sales price, excluding cash settled derivatives	$	6.16			$	8.09			$	6.32
Average sales price, including cash settled derivatives	7.18				8.09				6.32
Oil ($/Bbl):
Average sales price	$	40.90			$	52.70			$	40.70
Natural gas, NGLs and oil ($/Mcfe):
Average sales price, excluding cash settled derivatives	$	2.51			$	3.15			$	2.98
Average sales price, including cash settled derivatives	2.69				3.01				3.04

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."

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

Customers. The Company sells natural gas and NGLs to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through the Company's transportation portfolio, particularly where there is expected future demand growth, such as in the Gulf Coast, Midwest and Northeast United States and Canada. As of December 31, 2019, approximately 60% of Company sales volumes reach markets outside of Appalachia. Following the Mountain Valley Pipeline's in-service date, which is currently expected to be January 1, 2021, approximately 80% of Company sales volumes are expected to reach markets outside of Appalachia.

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. In addition, the Company is committed to an initial 1.29 Bcf per day of firm capacity on the Mountain Valley Pipeline upon its in-service date. These firm transportation and processing agreements may require minimum volume delivery commitments, which the Company expects to principally fulfill with existing proved developed and proved undeveloped reserves. The following table summarizes the Company's delivery commitments for the next five years as of December 31, 2019.

	Natural Gas			NGLs
Years ended December 31,	(Bcf)			(Mbbl)
2020	1,073			4,123
2021	833			1,836
2022	610			1,832
2023	534			1,825
2024	455			1,830

No single customer accounted for more than 10% of the Company's total operating revenues for 2019, 2018 and 2017.

Seasonality

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may also impact demand.

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 following: 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 following: 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. Ohio 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 maintains limited gathering operations that are subject to various types of federal and state environmental laws and local zoning ordinances, including the following: 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, including regulations by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration; 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 OTC 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 full 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 use, 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 and disruptive trading practices 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 negotiated rates, both of which are subject to FERC approval. The FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of FERC-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 could be subject to potential 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 and NGLs is through FERC-regulated 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 plugging 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. Recently, in April 2019, following litigation and a resulting consent decree related to the EPA's requirements under RCRA to review oil and gas waste regulations, the EPA determined that revisions to the regulations were not required, concluding that any adverse effects related to oil and gas waste were more appropriately and readily addressed within the framework of existing state regulatory programs. Any changes to state programs could result in an increase in the Company's costs to manage and dispose waste, 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 used 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 June 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 legal challenges. The EPA and the Corps proposed a rule in July 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, which lifted the stay and resulted in a patchwork application of the rule in some states, but not in others. In October 2019, the EPA issued a final rule repealing the WOTUS rule and the repeal rule became effective in December 2019. The repeal rule has already been challenged in federal district courts in New Mexico, New York, and South Carolina. In January 2020, the EPA and the Corps announced the final rule redefining the definition of WOTUS. The new definition narrows the scope of waters that are covered as jurisdictional under the CWA. Several groups have already announced their intention to challenge the new rule. As a result, future implementation is uncertain at this time. To the extent a stay of this rule or the implementation of 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 use 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, although

all counties in which the Company operates are currently in attainment with the 2015 National Ambient Air Quality Standard (NAAQS) for ozone, 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 any newly designated non-attainment areas. Compliance with 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 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 are required to meet "best available control technology" standards established by the states or, in some cases, by the EPA on a case‑by‑case basis. These CAA requirements could adversely affect the Company's 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.

In June 2016, the EPA finalized new regulations that established 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. 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. In November 2019, the EPA issued a proposed rulemaking to revise Subpart OOOOa to rescind the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. 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 2019, the Pennsylvania Environmental Quality Board (EQB) approved a proposed rulemaking for the control of emissions of VOCs and other pollutants for existing sources. Upon publication in the Pennsylvania Bulletin, the PADEP will accept public comments on the proposed rulemaking. A final rulemaking could be submitted to and approved by the EQB in late 2020. 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. In October 2019, Pennsylvania Governor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join the Regional Greenhouse Gas Initiative (RGGI), a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. Subsequently, legislators in the Pennsylvania General Assembly introduced a bill that, if approved, would require legislative approval by both chambers of the Pennsylvania General Assembly in order for Pennsylvania to join the RGGI. The EQB also accepted an economy-wide cap-and-trade petition for study in April 2019. The PADEP is evaluating the petition and will provide a recommendation to the EQB that could result in a state-wide cap-and-trade program across all sectors of the economy. If Pennsylvania ultimately becomes a member of the RGGI, or otherwise implements a cap-and-trade program, it could result in increased operating costs if the Company is required to purchase emission allowances in connection with its operations.

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 the Company's 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 funding 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 agencies, 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 requirement to obtain new permits, or closure, of centralized impoundments used 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. Additionally, in January 2020, the EQB approved a well permit fee increase from $5,000 to $12,500 for all unconventional wells. 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 16 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.

Employees

The Company and its subsidiaries had 647 employees as of December 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. Reports filed with the SEC are also available on the SEC's website, http://www.sec.gov.

Composition of Operating Revenues

The following table presents operating revenues for each class of products and services.

	Years Ended December 31,
	2019				2018				2017
	(Thousands)
Operating revenues:
Sales of natural gas, NGLs and oil	$	3,791,414			$	4,695,519			$	2,651,318
Gain (loss) on derivatives not designated as hedges	616,634				(178,591		)		390,021
Net marketing services and other	8,436				40,940				49,681
Total operating revenues	$	4,416,484			$	4,557,868			$	3,091,020

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.