EQT Corporation (EQT or the Company) isWe are a natural gas production company with emphasisoperations focused in the Marcellus and Utica Shales of the Appalachian Basin and operations throughout Pennsylvania, West Virginia and Ohio. EQT isBasin. Based on average daily sales volumes, we are the largest producer of natural gas in the United States, based on average daily sales volumes, with 21.8States. As of December 31, 2020, we had 19.8 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 1.41.8 million gross acres, including approximately 1.11.5 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.play.

The Company seeksWe are committed to beresponsibly developing our world-class asset base and being the premier produceroperator of choice for all stakeholders. By promoting a culture that prioritizes operational efficiency, technology and sustainability, we seek to continuously improve the way we produce environmentally responsible, reliable low-cost energy. We believe that the scale and contiguity of our acreage position differentiates us from our Appalachian Basin peers and that our evolution into a modern, digitally-enabled exploration and production business enhances our strategic advantage.

Our operational strategy focuses on the successful execution of combo-development projects. Combo-development refers to the development of several multi-well pads in tandem. Combo-development generates value across all levels of the reserves development process by maximizing operational and capital efficiencies. In the drilling stage, rigs spend more time drilling and less time transitioning to new sites. Advanced planning, a prerequisite to pursuing combo-development, facilitates the delivery of bulk hydraulic fracturing sand and piped fresh water (as opposed to truck-transported water), the ability to continuously meet completions supply needs and the use 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 valuetechnologies. Operational efficiencies realized from combo-development are passed on 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 cadenceour service providers, which is expected to result in higher capital efficiency.reduces overall contract rates.

The Company believesbenefits of combo-development extend beyond financial gains to include environmental and social interests. We have developed an integrated ESG program that interplays with our combo-development-driven operational strategy. Core tenets of our ESG program include investing in technology and human capital; improving data collection, analysis and reporting; and engaging with stakeholders to understand, and align our actions with, their needs and expectations. Combo-development, when compared to similar production from non-combo-development operations, translates into fewer trucks on the long-term outlook for its business is favorable dueroad, decreased fuel usage, shorter periods of noise pollution, fewer areas impacted by midstream pipeline construction and shortened duration of site operations, all of which fosters a greater focus on safety and environmental protection.

Combo-development projects require significant advanced planning, including the establishment of a large, contiguous leasehold position; the advanced acquisition of regulatory permits and sourcing of fracturing sand and water; the timely verification of midstream connectivity; and the ability to the Company’s substantial resource base, financial strength,quickly respond to internal and its commitment to capital discipline and operational efficiencies. The Company believes the combination of these factors provide it withexternal stimuli. Without a modern, digitally-connected operating model or 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 corethat enables operations of the Marcellus and Utica shales which the Company believes will allow it to realize operational efficiencies and improve overall returns. The Company believesthis scale, combo-development would not be possible.

We believe 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 padsour proprietary digital work environment in conjunction with longer laterals, optimizedthe size and contiguity of our asset base uniquely position us to execute on a multi-year inventory of combo-development projects in our core acreage position. Our operational strategy employs this differentiation to advance our mission of being the operator of choice for all stakeholders. We believe that combo-development projects are key to delivering sustainably low well spacing,costs and completion techniques allow the Companyhigher returns on invested capital and that our long-term transformative plan has been designed to maximize development efficiencies while reducing the overallcreate value by leveraging our strategic advantage, both operational and environmental, surface footprint of its drilling operations.over our peers.

See "Impairment of Oil and Gas PropertiesProperties" and Goodwill" and “Critical"Critical Accounting Policies and Estimates”Estimates" included in Item 7, "Management’s7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of the Company’sour accounting policies and significant assumptions related to accounting for oilgas, NGL and gasoil producing activities and the Company'sour accounting policies and processes with respectrelated to impairment reviews for proved and unproved property and goodwill.property.

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

 

The Company’sfollowing tables summarize our proved developed and undeveloped 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 our reserves reside in continuous accumulations.

Our 2020 total proved reserves increased 2%by 2.3 Tcfe, or 13%, compared to 2019 due to extensions, discoveries and other additions of 3,446 Bcfe and the acquisition of 1,381 Bcfe from the Chevron Acquisition, partly offset by production of 1,498 Bcfe, revisions to previous estimates of 739 Bcfe and divestitures of 257 Bcfe. We have an additional 13 Tcfe of reserves that meet the definition of proved reserves, except they are planned to be developed beyond five years and are therefore not included in 2018,the current estimate of proved reserves.

Proved undeveloped reserves increased by 1,136 Bcfe, or 11% when adjusted23%, in 2020 from 2019. The following table provides a rollforward of our proved undeveloped reserves.

As of December 31, 2020, the standardized measure of our estimated future net cash flows from natural gas and crude oil reserves, which is calculated using average first-day-of-the-month closing prices for the impactprior twelve months (which is referred to as SEC pricing), was $3,366 million as described in Note 18 to the Consolidated Financial Statements. If the prices used in the calculation 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 reservesstandardized measure instead reflected five-year strip pricing as of December 31, 20182020 and increased 13% as compared to December 31, 2017. The Company’s Marcellus assets constituted approximately 87% ofheld constant thereafter using (i) the Company'sNYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp. M-2, for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the standardized measure, and with all other assumptions held constant, our total proved reserves would be 20,296 Bcfe, the standardized measure of our discounted net future cash flows after taxes of our proved reserves would be $8,952 million, and the discounted future net cash flows before taxes would be $10,152 million. The average realized product prices weighted by volumeproduction over the remaining lives of the properties would be $27.18 per barrel of oil, $13.55 per barrel of NGL and $2.075 per Mcf of gas (as compared to $20.94 per barrel of oil, $11.97 per barrel of NGL and $1.38 per Mcf of gas using SEC pricing, as described in Note 18). The NYMEX strip price proved reserves and related metrics are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with “SEC pricing” proved reserves and do not comply with SEC pricing assumptions. We believe that the presentation of reserve volumes and related metrics using NYMEX forward strip prices provides investors with additional useful information about our reserves because the forward prices are based on the market’s forward-looking expectations of oil and gas prices as of a certain date. The price at which we can sell our production in the future is the major determinant of the likely economic producibility of our reserves. We hedge substantial amounts of future production based upon futures prices. In addition, we use such forward-looking market-based data in developing our drilling plans, assessing our capital expenditure needs and projecting future cash flows. While NYMEX strip prices represent a consensus estimate of future pricing, such prices are only an estimate and not necessarily an accurate projection of future oil and gas prices. Actual future prices may vary significantly from the NYMEX prices; therefore, actual revenue and value generated may be more or less than the amounts disclosed. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC pricing, when considering our reserves.

We have an active lease renewal program in areas targeted for development. In the event that production is not established or we take no action to extend or renew the terms of our leases, 71,322, 69,813 and 40,958 of our net undeveloped acreage as of December 31, 2018. As2020 will expire in the years ending December 31, 2021, 2022 and 2023, respectively.

The following tables summarize our productive and in-process natural gas wells. We had no productive or in-process oil wells as of December 31, 2018, the Company’s proved reserves were as follows:2020.

The Company’s natural gasfollowing table summarizes our net development wells generallydrilled. There were no net productive or net dry exploratory wells drilled during the years ended December 31, 2020, 2019 and 2018.

The Company invested approximately $2,255.0 millionDuring 2020, we commenced drilling operations (spud) 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 15388 gross wells (133(84 net), including 10566 Pennsylvania Marcellus gross wells in Pennsylvania (99(65 net), 5 Upper Devonian wells in Pennsylvania, 12 Marcellus wells in17 West Virginia Marcellus gross wells (16 net) and 315 Ohio Utica gross wells (17(3 net). During

Our sales volumes in 2020 from the past three years,Marcellus play, including the Company’s capital expenditures for reserve development were:

We have access to approximately 2.92.5 Bcf per day of firm contractual pipeline takeaway capacity and 0.60.9 Bcf per day of firm processing capacity. The Company has alsoIn addition, we are committed to an initial 1.29 Bcf per day of firm capacity on the Mountain Valley Pipeline (MVP)upon its in-service date. These firm transportation and processing agreements may require minimum volume delivery commitments, which is expectedwe expect to be placed in-service inprincipally fulfill with production from existing reserves. 

We have contractually agreed to deliver firm quantities of gas and NGLs to various customers, which we expect to fulfill with production from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to meet commitments for the fourth quarternext one to three years. The following table summarizes our total gross commitments as of 2019.December 31, 2020.

 

Other natural gas producers compete with the Companyus in the acquisition of properties,properties; the search for, and development of, reserves,reserves; the production and sale of natural gas and NGLsNGLs; and the securing of services, labor, equipment and transportation required to conduct operations. The Company'sOur competitors include independent oil and gas companies, major oil and gas companies, and individual producers, operators and marketing companies.  companies and other energy companies that produce substitutes for the commodities that we produce.

 

The Company’sOur 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. 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 Companywe 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.us.

We maintain 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;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 over-the-counterOTC derivative market and entities, such as the Company,us, 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. AsAmong other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivative activities. Although some of the filing date of this Annual Report on Form 10-K,rules necessary to implement 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 CompanyDodd-Frank Act have yet to be finalized.  Because significant CFTCadopted, regulators have issued numerous rules relevantunder the Dodd-Frank Act, including a rule establishing an “end-user” exception to mandatory clearing (End-User Exception), a rule regarding margin for certain uncleared swaps (Margin Rule) and a rule imposing federal position limits on certain futures contracts relating to energy products, including natural gas (Position Limits Rule).

We qualify as a “non-financial entity” for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities haveare not been adoptedsubject to mandatory clearing or implemented, it is not possible at this timethe margin requirements imposed in connection with mandatory clearing, although we are subject to predict the extentcertain recordkeeping and reporting obligations associated with such rule. We also qualify as a “non-financial end user” for purposes of the impactMargin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, although the Position Limits Rule does not go into effect with respect to energy products until January 1, 2022, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under the Position Limits Rule and will not be subject to the limitations under such rule. However, many of our hedge counterparties and other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule, which may affect the pricing and/or availability of derivatives for us. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations on the Company’s hedging program or regulatory compliance obligations.  The Company has experienced increased, and anticipates additional, compliance costs and changesrelated to current market practices as participants continuederivatives which apply to adaptour transactions with counterparties subject to a changing regulatory environment.such foreign regulations.

Regulators periodically review or audit the Company’sour compliance with applicable regulatory requirements. The Company anticipatesWe anticipate that compliance with existing laws and regulations governing current operations will not have a material adverse effect upon itsour 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 CompanyWe cannot predict when or whether any such proposals may become effective or the effect that such proposals may have on the Company.us.

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

Historically, federal legislation and regulatory controls have affected the price of the natural gas the Company produceswe produce and the manner in which the Company markets itswe market our 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'sour sales of itsour 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'sour production activities have not been regulated by the FERC as a natural gas company under the NGA, the Company iswe are required to report aggregate volumes of natural gas purchased or sold at wholesale

to the extent such transactions utilize,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'sour otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject the Companyus to civil penalty liability.

The CFTC also holds authority to monitor certain segments of the physical and futures energy commodities market including oilnatural gas, NGLs and natural gas.oil. 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 iswe undertake, we are 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 Companywe may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that the Company produces,we produce, as well as the revenues the Company receiveswe receive for sales of natural gas and release of itsour 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 nondiscriminatorynon-unduly discriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. The FERC’sFERC'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 Companywe cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can the Companywe determine what effect, if any, future regulatory changes might have on the Company’sour natural gas relatedgas-related activities.

Under the FERC’sFERC's current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or atnegotiated 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 jurisdictionalFERC-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’sFERC'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'sour costs of transporting gas to point of sale locations may increase. The Company believesWe believe that the third-party natural gas pipelines on which itsour gas is gathered meet the traditional tests the FERC has used to establish a pipeline’spipeline's status as a gatherer not subject to regulation as a natural gas

The price the Company receiveswe receive from the sale of these products may be affected by the cost of transporting the products to market. Some of the Company'sour transportation of oil natural gas 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’sFERC'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 isFERC published the five-year index level for 2021-2026 in December 2020. We are 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'sour crude oil producing operations.

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 CompanyWe cannot predict when or whether any such proposals may become effective. Therefore, the Company iswe are 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 hasWe have established procedures, however, for the ongoing evaluation of itsour 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'sour business operations are subject and for which compliance may have a material adverse impact on the Company'sour financial condition, earnings or cash flows.

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’sRCRA'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 EPAIn April 2019, following litigation and environmental groups entered into a resulting consent decree related to address the EPA’s alleged failureEPA's requirements under RCRA to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production relatedreview oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requireswaste regulations, the EPA determined that revisions to propose a rulemaking no later than March 15, 2019, for revision of certain Subtitle D criteriathe regulations pertainingwere not required, concluding that any adverse effects related to oil and gas wasteswaste were more appropriately and readily addressed within the framework of existing state regulatory programs. Any changes to state 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 wastesfederal programs could result in an increase in the Company'sour costs to manage and dispose of generated wastes,waste, which could have a material adverse effect on the Company'sour results of operations and financial condition.

The CompanyWe currently owns, leases,own, lease or operatesoperate numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although the Company believeswe believe that it has utilizedwe have 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,us, 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'sour 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'sour control. The Company isWe are able to control directly the operation of only those wells with respect to which the Company actswe act or hashave 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 Companyus 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 Companywe 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.

In June 2016, the EPA finalized new regulations that establishestablished 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. WhileIn September 2020, 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 proposedfinalized amendments to the 2016 Subpart OOOOa standards, known as the Reconsideration Rule, that would reduce the 2016 rule’srule'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’sEPA'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 September 2020, the EPA issued a rule to revise Subpart OOOOa to rescind the methane-specific requirements for certain oil and natural gas sources in the production and processing segments, known as the Review Rule. Both the Reconsideration Rule and the Review Rule are subject to pending litigation. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the Reconsideration Rule by September 2021 and consider revising the Review Rule. As a result of the actions described above, the Companywe 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’sPennsylvania'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"best available technology”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,May 2020, the PADEP releasedPennsylvania Environmental Quality Board (EQB) published in the Pennsylvania Bulletin a draft proposed rulemaking for the control of emissions of VOCs and other pollutants for existing sources. EQB accepted public comments on the proposed rulemaking through July 2020; however, a final rulemaking has yet to be approved by the EQB. State regulations such as these could impose increased compliance costs on the Company'sour 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 tradecap-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. WhileIn October 2019, Pennsylvania is not currentlyGovernor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a membercap-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 tradecap-and-trade program comprised of several Eastern U.S. states, itstates. In September 2020, the EQB approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020. Based on the current timeline for implementation, final rulemaking is possible that it may joinexpected to be sent to the EQB for review and approval in the fourth quarter of 2021, with the first year of compliance anticipated to begin in 2022. Assuming Pennsylvania ultimately becomes a member of the RGGI in the future. This could2022, as currently anticipated, it will result in increased operating costs if the Company's operationswe are required to purchase emission allowances.allowances in connection with our 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’States' intent to withdraw from the Paris Agreement. The Paris Agreement, provides for a four-year exit process beginning when it took effectwith such withdrawal becoming effective in November 2016, which would result in an effective exit date2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of November 2020. Thethe United States’ adherenceintention to the exit process and/or the terms on which the United States may reenterrejoin the Paris Agreement, or a separately negotiated agreement are unclear at this time.which will become effective in 30 days from such date.

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'sour business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, the Company'sour equipment and operations could require the Companyus 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 produceswe produce and lower the value of itsour reserves.

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil andnatural 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,decades, in large part driven by the fact that natural gas produces significantly less CO2 compared to other fossil fuels - up to 50% less than coal and 20-30% less than oil, according to the U.S. Energy Information Administration. Nonetheless, recent activism directed at shifting funding away from fossil fuel companies with energy-related assets could result in limitations or restrictions on certain sources of findingfunding 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 Companywe 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’sEarth'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'sour assets or affect the availability of water and thus could have an adverse effect on the Company'sour exploration and production operations.

Hydraulic fracturing typically is regulated by state oil and natural gas commissions,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.

See Note 1516 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.

 

The Company and its subsidiariesAs of December 31, 2020, we had 863624 permanent employees, asnone of January 31, 2019; none arewhom were subject to a collective bargaining agreement. Of our total permanent employee base, 74% were male and 26% were female. The substantial majority of our employees reside in Pennsylvania and West Virginia.

 

The Company makesWe make certain filings with the SEC, including its annual reportour Annual Report on Form 10-K, quarterly reportsQuarterly Reports on Form 10-Q, current reportsCurrent Reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through itsour investor relations website, http://www.eqt.com,ir.eqt.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. The filingsReports filed with the SEC are also available by accessingon the SEC's website, at http://www.sec.gov.

 

Presented below areThe following table presents total operating revenues for each class of our products and services.

 

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

In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. Please noteNote that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.

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

Our business is subject to all of the inherent hazards and risks normally incidental to drilling for, producing, transporting and storing natural gas, NGLs and oil, such as fires, explosions, slips, landslides, blowouts, and well cratering; pipe and other equipment and system failures; delays imposed by, or resulting from, compliance with regulatory requirements; formations with abnormal or unexpected pressures; shortages of, or delays in, obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities; adverse weather conditions, such as freeze offs of wells and pipelines due to cold weather; issues related to compliance with environmental regulations; environmental hazards, such as natural gas leaks, oil and diesel spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized releases of brine, well stimulation and completion fluids, toxic gases or other pollutants into the environment, especially those that reach surface water or groundwater; inadvertent third partythird-party damage to our assets, and natural disasters. We also face various risks or threats to the operation and security of our or third parties’parties' facilities and infrastructure, such as processing plants, compressor stations and pipelines. Any of these risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, equipment and natural resources, pollution or other environmental damage, loss of hydrocarbons, disruptions to our operations, regulatory investigations and penalties, suspension of our operations, repair and remediation costs, and loss of sensitive confidential information. Moreover, in the event that one or more of these hazards occur, there can be no assurance that a response will be adequate to limit or reduce damage. As a result of these risks, we are also sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that the insurance policies we maintain to limit our liability for such losses will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices or to cover all risks. In addition, pollution and environmental risks generally are not fully insurable, and we may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event that is not fully covered by insurance could materially adversely affect our business, results of operations, cash flows and financial position.

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

The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. We can provide no assurance that we will not suffer such attacks in the future. Deliberate attacks on, or unintentional events affecting, our systemsdigital work environment or other technologies and infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas, NGLs and oil, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability. Further, as cyber incidents continue to evolve and cyber-attackerscyber attackers become more sophisticated, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. The cost to remedy an unintended dissemination of sensitive information or data may be significant. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

The demand for qualified and experienced field personnel to their expiration resultingdrill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the terminationnatural gas and impairmentoil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages or higher costs. Historically, there have been shortages of leasespersonnel and equipment as demand for properties which we have not developed.

Substantially all of our producing properties are geographically concentrated in the Appalachian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by, and costs associated with, governmental regulation, state and local political activities, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other weather relatedweather-related conditions, interruption of the processing or transportation of oil, natural gas,

NGLs or NGLsoil and changes in state and local laws, judicial precedents, political regimes and regulations. Such conditions could materially adversely affect our results of operations and financial position.

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

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

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

Opposition toward oil and natural gas drilling and development activities generally has been growing globally and is particularly pronounced in the U.S., and companies in our industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability and business practices. Negative public perception regarding us and/or our industry resulting from, among other things, the explosion of natural gas transmission and gathering lines, oil spills, and concerns raised by advocacy groups or the media about hydraulic fracturing, greenhouse gas or methane emissions or fossil fuels in general, or about royalty payment and surface use issues, may lead to increased litigation and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new local, state and federal laws, regulations, guidelines and enforcement interpretations in safety, environmental, royalty and surface use areas. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, challenged or burdened by requirements that restrict our ability to profitably conduct our business. In addition, anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations, such as drilling and development. If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition and results of operations.

Our operations are regulated extensively at the federal, state and local levels. Laws, regulations and other legal requirements have increased the cost to plan, design, drill, install, operate and abandon wells and related infrastructure. Our exploration and production operations are subject to various types of federal, state and local laws and regulations, including regulations related to the location of wells; the method of drilling, well construction, well stimulation, hydraulic fracturing and casing design; water withdrawal and procurement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of water and other fluids and materials, including solid and hazardous wastes, incidental to natural gas and oil operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the plugging and abandoning of wells; the calculation, reporting and disbursement of royalties and taxes; and the gathering of production in certain circumstances.

Our operations are also subject to conservation and correlative rights regulations, including the regulation of the size of drilling and spacing units or field rule units; setbacks; the number of wells that may be drilled in a unit or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of properties. Some states allow the statutory pooling and unitization of tracts to facilitate development and exploration, as well as joint

development of existing contiguous leases. In addition, state conservation and natural gas and oil laws generally limit the venting or flaring of natural gas and may set production allowances on the amount of annual production permitted from a well.

Environmental, health and safety legal requirements govern discharges of substances into the air, ground and water; the management and disposal of hazardous substances and wastes; the clean-up of contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for drilling; environmental impact studies and assessments prior to permitting; restoration of drilling properties after drilling is completed; and work practices related to employee health and safety.

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

Effective January 1, 2018, changes to certain U.S. federal income tax laws were signed into law whichthat impact us, including but not limited to: changes to the regular income tax rate; the elimination of the alternative minimum tax;tax (AMT); full expensing of capital equipment; limited deductibility of interest expense; and increased limitations on deductible executive compensation. The current administration continuesOn March 27, 2020, the U.S. Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (CARES Act), which, among other things, includes provisions relating to debate further changesnet operating loss (NOL) carryback periods, AMT credit refunds and modifications to the net interest deduction limitations. In particular, under the CARES Act, (i) for taxable years beginning before 2021, NOL carryforwards and carrybacks may offset 100% of taxable income, (ii) NOLs arising in 2018, 2019, and 2020 taxable years may be carried back to each of the preceding five years to generate a refund, and (iii) for taxable years beginning in 2019 and 2020, the base for interest deductibility is increased from 30% to 50% of EBITDA.

Members of Congress periodically introduce legislation to revise U.S. federal income tax laws that could be enacted which could have a material impact on us. The most significant potential tax law changes that could impact us include further changes toincreases in the regular income tax rate, a new minimum tax based on net income, the expensing of intangible drilling costs or percentage depletion, the repeal of like-kind exchange tax deferral rules on real property and further limited deductibility of interest expense, any of which could adversely impact our current and deferred federal and state income tax liabilities. State and local taxing authorities in jurisdictions in which we operate or own assets may enact new taxes, such as the imposition of a severance tax on the extraction of natural resources in states in which we produce natural gas, NGLs and oil, or change the rates of existing taxes, which could adversely impact our earnings, cash flows and financial position.

We use financial derivative instruments to hedge the impact of fluctuations in natural gas, NGLs and oil prices on our results of operations and cash flows. In 2010, Congress adopted the Dodd-Frank Act, which established federal oversight and regulation of the over-the-counterOTC derivative market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC, the SEC and other regulatorycertain federal agencies that regulate the banking and insurance sectors (Prudential Regulators) to promulgate rules and regulations implementing the legislation. AsAmong other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivative activities. Although some of the filing date of this Annual Report on Form 10-K,rules necessary to implement the CFTC had adopted and implemented many final rules that impose regulatory obligations on all market participants, including us, such as recordkeeping and certain reporting obligations.  Other rules that may be relevant to us or our counterpartiesDodd-Frank Act have yet to be finalized.  Because significantadopted, the CFTC, the SEC and Prudential Regulators have issued numerous rules, relevantincluding the End-User Exception, which exempts certain “end-users” from having to comply with mandatory clearing, a Margin Rule mandating margining for certain uncleared swaps, and a Position Limits Rule imposing federal position limits on certain futures contracts relating to energy products, including natural gasgas.

We qualify as a “non-financial entity” for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities haveare not been adoptedsubject to mandatory clearing or implemented, it is not possible at this timethe margin requirements imposed in connection with mandatory clearing, although we are subject to predict the extentcertain recordkeeping and reporting obligations associated with such rule. We also qualify as a “non-financial end user” for purposes of the impactMargin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, although the Position Limits Rule does not go into effect with respect to energy products until January 1, 2022, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under the Position Limits Rule and will not be subject to the limitations under such rule. However, many of our hedge counterparties and other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule, which may affect the pricing and/or availability of derivatives for us. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which apply to our transactions with counterparties subject to such Foreign Regulations.

The Dodd-Frank Act, the rules adopted thereunder and the Foreign Regulations could increase the cost of our derivative contracts, alter the terms of our derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or the Foreign Regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements. Any of these consequences could have a material and adverse effect on our hedging program, including available counterparties, or regulatory compliance obligations.business, financial position and results of operations. We have experienced increased, and anticipate additional, compliance costs and changes to current market practices as participants continue to adapt to a changing financial regulatory environment.

We utilizeuse hydraulic fracturing in the completion of our natural gas and oil wells. Hydraulic fracturing typically is regulated by state natural gas and oil commissions, but the EPA has asserted federal regulatory authority. For example, the EPA also finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.plants, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules.

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

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

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those

actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and occupational health and workplace safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters.

In addition, new or additional laws and regulations, new interpretations of existing requirements or changes in enforcement policies could impose unforeseen liabilities, significantly increase compliance costs or result in delays of, or denial of rights to conduct, our development programs. For example, in SeptemberJune 2015, the EPA and the Corps issued a final rule under the CWA defining the scope of the EPA’sEPA's and the Corps’Corps' jurisdiction over WOTUS, but several legal challenges to the rule followed, and the WOTUS rulewhich was stayed nationwide in October 2015 pending resolution of the courtseveral legal challenges. The EPA and the Corps proposed a rule in JuneJuly 2017 to repeal the WOTUS rule and announced their intent to issue a new rule defining the CWA’sCWA'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,courts, which lifted the previously filed district court cases were allowed to proceed, resultingstay and resulted in a patchwork application of implementationthe rule in some states, and staysbut not in others. FollowingIn October 2019, the U.S. Supreme Court’s decision,EPA issued a final rule repealing the WOTUS rule and the repeal rule became effective in December 2019. In April 2020, the EPA and the Corps issuedpublished the NWPR, which narrows the definition of WOTUS to four categories of jurisdictional waters and includes twelve categories of exclusions, including groundwater. A coalition of states and cities, environmental groups, and agricultural groups have challenged the NWPR and a final rulefederal district court in January 2018 stayingColorado stayed implementation of the WOTUS rule for two years while the agencies reconsider the rule, but a federal judge barred the agencies’ suspensionrule. The stay is limited to application of the rule in August 2018. Subsequently, various district court decisions

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

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

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best"best available control technology”technology" standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring

and reporting of GHG emissions from specified onshore and offshore natural gas and oil production sources in the United States on an annual basis, which include certain of our operations. At the state level, several states including Pennsylvania have proceeded with regulation targeting GHG emissions. Such state regulations could impose increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of federal legislation in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and tradecap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. WhileIn October 2019, Pennsylvania is not currentlyGovernor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a membercap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join the RGGI, a multi-state regional cap and tradecap-and-trade program comprised of several Eastern U.S. states, itstates. In September 2020, the Pennsylvania Environmental Quality Board approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020. Based on the current timeline for implementation, final rulemaking is possible that it may joinexpected to be sent to the Pennsylvania Environmental Quality Board for review and approval in the fourth quarter of 2021, with the first year of compliance anticipated to begin in 2022. Assuming Pennsylvania ultimately becomes a member of the RGGI in the future. This could2022, as currently anticipated, it will result in increased operating costs if our operationswe are required to purchase emission allowances.allowances in connection with our operations.

On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does not impose any binding obligations on its participants. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’States' intent to withdraw from the Paris Agreement. The Paris Agreement, provides for a four-year exit process beginning when it took effectwith such withdrawal becoming effective in November 2016, which would result in an effective exit date2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of November 2020. Thethe United States’ adherenceintention to the exit process and/or the terms on which the United States may reenterrejoin the Paris Agreement, or a separately negotiated agreement are unclear at this time.which will become effective in 30 days from such date.

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

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

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

We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures. These transactions involve various inherent risks, such as our ability to obtain the necessary regulatory and third partythird-party approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; the assumption of potential environmental or other liabilities; and our ability to realize the benefits expected from the transactions. In addition, various factors, including prevailing market conditions, could negatively impact the benefits we receive from these transactions. Competition for transaction opportunities in our industry is intense and may increase the cost of, or cause us to refrain from, completing transactions. Joint venture arrangements may restrict our operational and corporate flexibility.

Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may have little or partial control over, and our joint venture partners may not satisfy their obligations to the joint venture. Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our earnings, cash flows and financial position.

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

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

In November 2018, we completed the Separation and Distribution (each defined and discussed in Note 8 to the Consolidated Financial Statements), resulting in the spin-off of Equitrans Midstream, a stand-alonestandalone publicly traded corporation whichthat holds our former midstream business.

In connection with the Separation and Distribution, we obtained a private letter ruling from the IRS and an opinion of outside counsel regarding the qualification of the Distribution, together with certain related transactions, as a transaction that is generally tax-free, for U.S. federal income tax purposes, under Sections 355 and 368(a)(1)(D) of the U.S. Internal Revenue Code, (the Code)as amended, and certain other U.S. federal income tax matters relating to the Distribution and certain related transactions. The IRS private letter ruling and the opinion of counsel are based uponon and rely on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of us and Equitrans Midstream, including those relating to the past and future conduct of us and Equitrans Midstream. If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if we or Equitrans Midstream breach any representations or covenants contained in any of the Separation-related agreements and documents or in any documents relating to the IRS private letter

ruling and/or the opinion of counsel, we and our shareholders may not be able to rely on the IRS private letter ruling or the opinion of counsel.

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

Following the Separation and Distribution, we retained approximately 19.9% of the outstanding shares of Equitrans Midstream's common stockstock. On February 26, 2020, we entered into share purchase agreements with Equitrans Midstream to sell approximately 50% of our equity interest in Equitrans Midstream to Equitrans Midstream (the Equitrans Share Exchange) in exchange for a combination of cash and fee relief under our gathering agreements with EQM. We currently own 25,296,026 shares of Equitrans Midstream.Midstream's common stock. The value of our investment in Equitrans Midstream may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the midstream industry, including loss of gathering and transportation volumes, the effect of laws and regulations on the operation of its business and development of its assets, increased competition, loss of contracted volumes, adverse rate-making decisions, policies and rulings by the FERC, pipeline safety rulemakings initiated or finalized by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration, delays in the timing of, or the failure to complete, expansion projects, lack of access to capital and operating risks and hazards.

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

We believe that our principal areas of operational risk resulting from a pandemic are availability of service providers and supply chain disruption. Active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of personnel and contractors on site. While we believe that we are following best practices under COVID-19 guidance, the potential for transmission still exists. In certain instances, it may sell additional shares of common stock in subsequent public offerings. Webe necessary or determined advisable for us to delay development operations.

To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also issue additional shares of common stock or convertible securities.

 

 

Principal facilities are owned or, in the caseSee Item 1., "Business" for a description of certain office locations, warehouse buildings and equipment, leased, by the Company and its subsidiaries.  The majority of the Company’s properties are located on or under (i) private properties owned in fee, held by lease or occupied under perpetual easements or other rights acquired for the most part without warranty of underlying land titles or (ii) public highways under franchises or permits from various governmental authorities.  The Company’s facilities are generally well maintained and, where appropriate, are replaced or expanded to meet operating requirements.