What changed in this filing

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Item 1. Business

2022-02-10 compared with 2021-02-17 · 148 added, 166 removed, 348 unchanged (47% of the section changed)

We are a natural gas production company with operations focused in the Marcellus and Utica Shales of the Appalachian Basin.

Based on average daily sales volumes, we are the largest producer of natural gas in the United States.

Based on average daily sales volume, we are the largest producer of natural gas in the United States.

As of December 31, 2021, we had 25.0 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 2.0 million gross acres, including approximately 1.7 million gross acres in the Marcellus play.

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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 measure sustainability through our best-in-class team and culture, ESG-focused operations, substantial inventory of core drilling locations and strong balance sheet.

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.

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We believe that combo-development projects are key to delivering sustainably low well costs and higher returns on invested capital and that our long-term transformative plan has been designed to create value by leveraging our strategic advantage, both operational and environmental, over our peers.

We believe our business model is sustainable and we expect to generate significant free cash flow over the next six years.

Our capital allocation plan is focused on reducing our debt and leverage, while also returning capital to shareholders through a combination of dividends and a share repurchase program.

We are focused on achieving and maintaining investment grade credit metrics as well as regaining our investment grade credit rating in the near term, which will allow us to capture a lower cost of capital and enhance shareholder returns.

2021 Highlights

• Achieved 2020 sales volumes of 1,498 Bcfe or average daily sales volumes of 4.1 Bcfe per day;

• Achieved 2021 sales volume of 1,858 Bcfe, average daily sales volume of 5.1 Bcfe per day;

received an average realized price of $2.50 per Mcfe.

• Reduced 2020 capital expenditures by $694 million, or 39.1%, compared to 2019, while delivering flat sales volumes.

• Increased total proved reserves by 2.3 Tcfe or 13% in 2020 compared to 2019.

• Decreased total debt by $368 million and addressed near-term maturities, improving our financial position.

• Executed a new gas gathering agreement and exchanged half of our equity stake in Equitrans Midstream, substantially reducing our future gathering fee structure.

• Acquired strategic assets from Chevron U.S.A.

located in the Appalachian Basin for an aggregate purchase price of $735 million (Chevron Acquisition).

• Divested certain non-strategic assets for an aggregate purchase price of $125 million.

• Executed long-term contract to use electric hydraulic fracturing services in our completions operations, promoting our ESG initiatives.

• Received approximately $440 million in federal income tax refunds, including interest.

In 2021, we expect to spend approximately $1.1 to $1.2 billion in total capital expenditures, excluding amounts attributable to noncontrolling interests.

We expect to fund planned capital expenditures with cash generated from operations, allocated as follows:

approximately $800 to $850 million to fund reserve development, approximately $125 to $140 million to fund land and lease acquisitions, approximately $130 to $155 million to fund other production infrastructure and approximately $45 to $55 million applied towards capitalized overhead.

Reserve development capital expenditures will be spent across our three primary operating areas, with approximately 65% spent in Pennsylvania Marcellus, approximately 30% spent in West Virginia Marcellus, and approximately 5% spent in Ohio Utica.

Our 2021 capital expenditure program is expected to deliver sales volumes of 1,620 Bcfe to 1,700 Bcfe, an increase of 120-200 Bcfe when compared to 2020 sales volumes primarily driven by increased production from the Chevron Acquisition.

• Increased 2021 total proved reserves by 5.2 Tcfe, or 26%, compared to 2020.

• Acquired strategic assets located in the Appalachian Basin from Alta Resources Development, LLC for total consideration of $2,925 million (the Alta Acquisition).

• Realized a meaningful reduction of gathering and transmission expense on a per Mcfe basis of $0.05 and $0.06, respectively, during 2021 compared to 2020.

• Achieved credit ratings upgrades from S&P, Moody's and Fitch.

• Extended the term of our credit facility and reduced outstanding letters of credit under our credit facility by $351 million.

• Obtained Equitable Origin and MiQ Certifications for a majority of our natural gas.

In 2022, we expect to spend approximately $1.30 to $1.45 billion in total capital expenditures, excluding amounts attributable to noncontrolling interest.

We expect to allocate the planned capital expenditures as follows:

approximately $1.0 to $1.1 billion to fund reserve development, approximately $110 to $130 million to fund land and lease acquisitions, approximately $120 to $160 million to fund other production infrastructure and approximately $55 to $75 million applied towards capitalized overhead.

Our 2022 capital expenditure program is expected to deliver sales volume of 1,950 to 2,050 Bcfe.

In December 2021, we reaffirmed our commitment to attaining investment grade credit metrics and outlined a leverage and debt reduction strategy with the goal of reducing total debt by at least $1.5 billion by the end of 2023.

In addition, we announced our plan to return capital to shareholders, which included the commencement of a share repurchase program, under which we are authorized to repurchase $1.0 billion of our outstanding common stock, and the reinstatement of a quarterly cash dividend at an annual rate of $0.50 per share of our common stock starting in the first quarter of 2022.

Our capital allocation plan is focused on maintaining production volumes.

We have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, which will enable us to execute on our capital expenditure, debt reduction and shareholder return strategy.

Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of, natural gas, NGLs and oil.

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Any such impairments or downward adjustments to our estimated reserves could potentially be material to us.

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 our accounting policies and significant assumptions related to accounting for gas, NGL and oil producing activities and our accounting policies and processes related to impairment reviews for proved and unproved property.

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 our accounting policies and significant assumptions related to accounting for gas, NGLs and oil producing activities and our accounting policies and processes related to impairment reviews for proved and unproved property.

Segment and Geographical Information

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Net proved undeveloped drilling locations 195 118 1 314

Our 2020 total proved reserves increased 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 the current estimate of proved reserves.

During 2020, we conducted a study of our reserves areas to determine the reliability of the technology used in calculating our reserves.

This study demonstrated that technologies used in the course of our reserves determination are reliable, provide reasonable certainty of future performance and economics of our wells, and conform to booking practices when using reliable technologies.

The technologies used in the estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well logs, geologic maps, core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation and application of statistical analysis.

Proved undeveloped reserves increased by 1,136 Bcfe, or 23%, in 2020 from 2019.

Our 2021 total proved reserves increased by 5.2 Tcfe, or 26%, compared to 2020 due to acquisitions of 4,187 Bcfe from the Alta Acquisition and Reliance Asset Acquisition (defined in Note 6 to the Consolidated Financial Statements) and extensions, discoveries and other additions of 3,104 Bcfe, partly offset by production of 1,858 Bcfe and revisions to previous estimates of 274 Bcfe.

Our 2021 proved undeveloped reserves increased by 1,582 Bcfe, or 26%, compared to 2020.

The following table provides a rollforward of our proved undeveloped reserves.

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Balance at December 31, 2021 7,743

(a) Composed of (i) negative revisions of 510 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of changes to our development plan which inc luded 245 Bcfe from lower pricing that impacted well economics, shifting capital from the Ohio Utica, to Pennsylvania and West Virginia Marcellus and 265 Bcfe as a result of continued implementation of our combo-development strategy;

and (ii) positive revisions of 155 Bcfe due primarily to changes in working interests and net revenue interests as well as revisions to type curves.

(b) Composed of (i) 2,096 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved using reliable technologies which expanded the number of our technically proven locations;

(ii) 1,295 Bcfe due to additions

associated with directly offsetting development;

(a) Composed of (i) negative revisions of 819 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of changes to our development plan to support the continued implementation of our combo-development strategy;

and (ii) negative revisions of 62 Bcfe due primarily to changes in working interests and net revenue interests.

(b) Composed of (i) 2,828 Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2021 reserve development that expanded the number of our proven locations, implementation of, and alignment with, our combo-development strategy and additions to our five-year drilling plan;

and (ii) 52 Bcfe from the extension of lateral lengths of proved undeveloped reserves.

As of December 31, 2021, we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

See Note 18 to the Consolidated Financial Statements for further discussion of the preparation of, and year-over-year changes in, our reserves estimate and calculation of our standardized measure of estimated future net cash flows from natural gas and crude oil 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 prior twelve months (which is referred to as SEC pricing), was $3,366 million as described in Note 18 to the Consolidated Financial Statements.

See Note 18 to the Consolidated Financial Statements for further discussion of the preparation of, and year-over-year changes in, our reserves estimate and calculation of the standardized measure of estimated future net cash flows from natural gas and crude oil reserves.

As of December 31, 2021, 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 prior twelve months (referred to as SEC pricing), was $17,281 million, as described in Note 18 to the Consolidated Financial Statements.

If the prices used in the calculation of the standardized measure instead reflected five-year strip pricing as of December 31, 2021 and held constant thereafter using (i) the NYMEX 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 production 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).

M-2, Transcontinental Gas Pipe Line, Leidy Line, and Tennessee Gas Pipeline Co., Zone 4-300 Leg 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 holding all other assumptions constant, our total proved reserves would be 24,913 Bcfe, the standardized measure of our discounted net future cash flows after taxes of our proved reserves would be $16,059 million and the discounted future net cash flows before taxes would be $19,672 million.

The average realized product prices weighted by production over the remaining lives of the properties would be $46.84 per barrel of oil, $27.22 per barrel of NGLs and $2.448 per Mcf of gas (compared to $51.57 per barrel of oil, $29.95 per barrel of NGLs and $2.694 per Mcf of gas using SEC pricing, as described in Note 18 to the Consolidated Financial Statements).

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.

We believe that the presentation of reserve volume 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.

We hedge certain amounts of future production based on 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.

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Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC pricing, when considering our reserves.

Based on our mix of proved undeveloped and probable reserves, we estimate that we have an undeveloped drilling inventory of approximately 1,660 net locations in Pennsylvania and West Virginia Marcellus.

Based on our mix of proved undeveloped and probable reserves, we estimate that we have an undeveloped drilling inventory of approximately 2,400 net locations in the Pennsylvania and West Virginia Marcellus Shale.

At our current drilling pace, these net locations provide more than 20 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.

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2021 2020 2019

Marcellus (i ncludes Upper Devonian )

$ 788 $ 737 $ 1,184

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Total $ 828 $ 839 $ 1,377

Lease operating costs, excluding production taxes, for the years ended December 31, 2020, 2019 and 2018 was $0.07, $0.06 and $0.07, respectively.

For the years ended December 31, 2021, 2020 and 2019, lease operating costs, excluding production taxes were $0.07, $0.07 and $0.06, respectively.

The majority of our acreage is held by lease or occupied under perpetual easements or other rights acquired, for the most part, without warranty of underlying land titles.

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December 31, 2021

Pennsylvania West Virginia Ohio Total

Pennsylvania West

Virginia Ohio Total

Total gross productive acreage 396,356 117,972 51,109 565,437

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Total net acreage 1,141,577 443,220 147,032 1,731,829

Average net revenue interest of proved developed reserves 72.9 % 83.0 % 48.8 % 72.7 %

Average net revenue interest of proved developed reserves (a) 59.8 % 82.0 % 48.9 % 62.5 %

(a) As of December 31, 2021, the average net revenue interest of proved developed reserves was 30.9% for northeastern Pennsylvania and 79.0% for southwestern Pennsylvania.

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, 2020 will expire in the years ending December 31, 2021, 2022 and 2023, respectively.

In the event that production is not established or we do not extend or renew the terms of our expiring leases, 57,361, 36,799 and 31,123 of our net undeveloped acreage as of December 31, 2021 will expire in the years ending December 31, 2022, 2023 and 2024, respectively.

The following tables summarize our productive and in-process natural gas wells.

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We have no gross conventional wells in Ohio.

The following table summarizes our net development wells drilled.

There were no net productive or net dry exploratory wells drilled during the years ended December 31, 2020, 2019 and 2018.

Years Ended December 31,

2020 2019 2018

Net development wells:

Productive 120 145 210

Dry (a) — — 5

(a) Dry development wells are related primarily to non-core wells that we no longer plan 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 2020, we commenced drilling operations (spud) on 88 gross wells (84 net), including 66 Pennsylvania Marcellus gross wells (65 net), 17 West Virginia Marcellus gross wells (16 net) and 5 Ohio Utica gross wells (3 net).

Our sales volumes in 2020 from the Marcellus play, including the Upper Devonian play, were 1,315 Bcfe.

The following table summarizes our produced and sold volumes by state.

Pennsylvania West Virginia Ohio Other (a) Total

We drilled 99, 120 and 145 net productive development wells during the years ended December 31, 2021, 2020 and 2019, respectively.

During the years ended December 31, 2021, 2020 and 2019, we drilled zero net dry development, net productive exploratory and net dry exploratory wells.

During 2021, we commenced drilling operations (spud) on 96 gross wells (67 net), composed of 50 Pennsylvania Marcellus gross wells (34 net), 41 West Virginia Marcellus gross wells (32 net) and 5 Ohio Utica gross wells (1 net).

Our sales volume in 2021 from the Marcellus Shale was 1,685 Bcfe.

The following table summarizes our produced and sold volume by state.

Pennsylvania West Virginia Ohio Total

Produced and sold natural gas, NGLs and oil for the years ended December 31,

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2019 1,001,973 274,378 231,545 1,507,896

(a) Primarily Kentucky and Virginia.

Markets and Customers

Natural Gas Sales.

Natural gas is a commodity and, therefore, we typically receive market-based pricing.

Natural gas is a commodity and, therefore, we typically receive market-based pricing for our produced natural gas.

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 increased supply of natural gas in the Northeast United States.

To protect cash flow from undue exposure to the risk of changing commodity prices, we hedge a portion of our forecasted natural gas production at, for the most part, NYMEX natural gas prices.

We also enter into derivative instruments to hedge basis.

For information on our hedging strategy and our 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 3 to the Consolidated Financial Statements.

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We sell natural gas and NGLs to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our 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, 2020, approximately 60% of our sales volumes reach markets outside of Appalachia.

As of December 31, 2021, approximately 50% of our sales volume reaches markets outside of Appalachia.

We do not depend on any single customer and believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil.

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These firm transportation and processing agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.

During 2021, we entered into a long-term asset management agreement with an investment grade entity, pursuant to which, we agreed to deliver and sell up to 525,000 Dth of natural gas per day to the investment grade entity for a period of up to six years while managing and using our committed capacity on the Mountain Valley Pipeline upon its in-service date.

The asset management agreement is subject to currently unsatisfied conditions;

therefore, its impacts have been excluded from the schedule of total gross commitments summarized in the table below.

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.

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Natural Gas NGLs

Years ending December 31, (Bcf) (Mbbl)

2021 1,390 7,814

Years Ending December 31,

2022 1,425 7,123

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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.

Seasonal anomalies such as mild winters or summers may also impact demand.

Other natural gas producers compete with us in the acquisition of properties;

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Regulation of our Operations.

Our exploration and production operations are subject to various types of federal, state and local laws and regulations, including regulations related to the following:

Our exploration and production operations are subject to various federal, state and local laws and regulations, including regulations related to the following:

the location of wells;

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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, we must rely on voluntary pooling of lands and leases for Marcellus and Upper Devonian acreage.

In West Virginia, we must rely on voluntary pooling of lands and leases for Marcellus acreage.

In Pennsylvania, lease integration legislation authorizes joint development of existing contiguous leases.

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Various states also impose certain regulatory requirements to transfer wells to third parties or discontinue operations in the event of divestitures by 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:

We maintain limited gathering operations that are subject to various 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;

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Among 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 rules necessary to implement the Dodd-Frank Act have yet to be adopted, regulators have issued numerous rules under 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).

Although some of the rules necessary to implement the Dodd-Frank Act have yet to be adopted, regulators have issued numerous rules under the Dodd-Frank Act, including a rule establishing an "end-user" exception to mandatory clearing (End-User Exception), a rule requiring the posting of 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.

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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.

Finally, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under the Position Limits Rule and are not materially impacted by 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.

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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 $1.3 million per day for each violation and disgorgement of profits associated with any violation.

While our production activities have not been regulated by the FERC as a natural gas company under the NGA, we are 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.

While our production activities have not been regulated by the FERC as a natural gas company under the NGA, we are required to report aggregate volume 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 our otherwise non-FERC jurisdictional facilities to further regulation.

Failure to comply with those regulations in the future could subject us to civil penalty liability.

The CFTC also holds authority to monitor certain segments of the physical and futures energy commodities market including natural gas, NGLs and oil.

With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we 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.

Failure to comply with those regulations in the future could subject us to civil penalties.

The CFTC also holds authority to monitor certain segments of the physical, futures and other derivatives with respect to energy commodities markets, including natural gas, NGLs and oil.

The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.

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therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our 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.

Under the FERC's current regulatory regime, transportation 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 natural 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.

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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, our costs of transporting gas to point of sale locations may increase.

We believe that the third-party natural gas pipelines on which our 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.

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Sales prices of oil and NGLs are not currently regulated and are made at market prices.

Our 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.

Our sales of these commodities are, however, subject to laws and 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 $1.2 million per day per violation.

Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.

The price we receive from the sale of these products may be affected by the cost of transporting the products to market.

Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight and enforcement authority as discussed above.

The price we receive from the sale of our produced oil and NGLs may be affected by the cost of transporting the products to market.

Some of our transportation of oil and NGLs is through FERC-regulated interstate common carrier pipelines.

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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 FERC 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 our crude oil producing operations.

The FERC's five-year index level for 2021–2026 went into effect on July 1, 2021.

In January 2022, the FERC issued an order on rehearing, lowering the index level and directing oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 to ensure compliance with the new index level.

Environmental, Health and Safety Regulation.

Our business operations 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 generation, storage, transportation, handling and disposal of certain materials, including solid and hazardous wastes;

the safety of employees and the general public;

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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;

These laws and regulations may require us to acquire 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;

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limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands 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;

require some form of remedial action to prevent, remediate or mitigate pollution from operations, such as plugging abandoned wells or closing earthen pits;

establish specific safety and health criteria addressing worker protection;

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We have established procedures, however, for the ongoing evaluation of our 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 our business operations are subject and for which compliance may have a material adverse impact on our financial condition, earnings or cash flows.

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

Hazardous Substances and Waste Handling.

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Although we believe that we 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 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 our 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 our control.

In addition, some of our 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 our control.

We are able to control directly the operation of only those wells with respect to which we act or have acted as operator.

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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, we 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.

Under such laws, we could be required to undertake response or corrective measures, regardless of fault, which could include removal of previously disposed substances and wastes, clean-up 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 Federal Water Pollution Control Act, known as 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.

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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), which was stayed nationwide in October 2015 pending resolution of several 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.

In April 2020, the EPA and the Corps published the Navigable Waters Protection Rule (NWPR), which narrowed 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 federal district court in Colorado stayed implementation of the rule.

The stay is limited to application of the rule in Colorado;

the rule has taken effect in all other states.

In addition, in an April 2020 decision defining the scope of the CWA that was handed down just days after the NWPR was published, the U.S.

In June 2015, the EPA and the Corps issued a rule defining the scope of the EPA's and the Corps' jurisdiction over waters of the United States (WOTUS), which never took effect before being replaced by the Navigable Waters Protection Rule (NWPR) in December 2019.

A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021.

The EPA is undergoing a rulemaking process to redefine the definition of waters of the United States;

in the interim, the EPA is using the pre-2015 definition.

In addition, in an April 2020 decision further defining the scope of the CWA, the U.S.

Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit.

The Court rejected the EPA and Corps' assertion that groundwater should be totally excluded from the CWA.

The Court’s decision is expected to bolster challenges to the NWPR.

On January 20, 2021, the Biden Administration announced it will review the NWPR in accordance with the January 20, 2021 Executive Order that revokes President Trump’s Executive Order 13778, which required review and reversal of the WOTUS rule.

The EPA and the Corps have requested to stay the litigation over the NWPR during the agencies’ review of the rule.

To the extent a revised rule expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects.

To the extent a new rule or further litigation expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects.

Also, pursuant to these laws and regulations, we 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.

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances and may impose substantial potential liability for the costs of removal, remediation and natural resource and other 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 us 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 our oil and natural gas projects.

Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues.

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 our ability to obtain permits for our operations or require us to install additional pollution control equipment, the costs of which could be significant.

Through the federal Clean Air Act (CAA) and comparable state and local laws and regulations, the EPA regulates emissions of various air pollutants through the issuance of permits and the imposition of other requirements.

The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources.

New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits.

In June 2016, the EPA finalized regulations establishing 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 2020, the EPA finalized two sets of amendments to the 2016 Subpart OOOOa standards.

The first, known as the 2020 Technical Rule, reduced the 2016 rule's fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes.

The second, known as the 2020 Policy Rule, rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments.

On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the 2020 Technical Rule by September 2021 and consider revising the 2020 Policy Rule.

On June 30, 2021, President Biden signed a Congressional Review Act (CRA) resolution passed by Congress that revoked the 2020 Policy Rule.

The CRA did not address the 2020 Technical Rule.

Further, on November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources.

The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA, including intermittent vent pneumatic controllers and associated gas and liquids unloading facilities.

In addition, the proposed rule would establish "Emissions Guidelines," creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA.

Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule.

The EPA is expected to issue both a supplemental proposed rule, which may expand or modify the current proposed rule, and final rule by the end of 2022.

As a result of these regulatory changes, the scope of any final methane regulations or the costs for complying with federal methane regulations are uncertain.

We may incur costs as necessary to remain in compliance with these regulations.

Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

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 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 oil and gas production sources in the United States on an annual basis, which include certain of our 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 2020, the EPA finalized amendments to the 2016 Subpart OOOOa standards, known as the Reconsideration Rule, that 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 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, we 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 May 2020, the Pennsylvania Environmental Quality Board (EQB) published in the Pennsylvania Bulletin a 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 our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of federal legislation in recent years.

In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting 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.

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 expected 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 2022, as currently anticipated, it will result in increased operating costs if we are required to purchase emission 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' intent to withdraw from the Paris Agreement, with such withdrawal becoming effective in November 2020.

However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, 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 oil and natural gas we produce and lower the value of our reserves.

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that natural 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, 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.

In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the signatories to the agreement to undertake "ambitious efforts" to limit increases in the average global temperature.

Although the agreement does not create any binding obligations for nations to limit their greenhouse gas (GHG) emissions, it does include pledges to voluntarily limit or reduce future emissions.

On June 1, 2017, President Trump announced that the U.S.

would withdraw from the Paris Agreement and completed the process of withdrawing from the Paris Agreement on November 4, 2020.

However, on January 20, 2021, President Biden issued written notification to the United Nations of the U.S.'s intention to rejoin the Paris Agreement, which became effective on February 19, 2021.

In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions to at least 30% below 2020 levels by 2030.

Since its formal launch at the United Nations Climate Change Conference (COP26), over 100 countries have joined the pledge.

On November 3, 2021, the U.S.

House of Representatives passed budget reconciliation bill H.R.

5376, known as the Build Back Better Act.

The House version of the bill includes a provision targeting methane emissions from oil and gas sources by proposing to implement fees for excess methane leaking from wells, storage sites and pipelines as well as fees for new producing and non-producing oil and gas leases and off-shore pipelines.

It is unclear whether the Build Back Better Act will be passed in its current form by the U.S.

Additionally, 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 Pennsylvania Department of Environmental Protection (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.

In September 2020, the Pennsylvania Environmental Quality Board (EQB) approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020.

In September 2021, Pennsylvania's Independent Regulatory Review Commission adopted a regulation approving Pennsylvania's participation in RGGI;

however, in October 2021 the Pennsylvania Senate approved a resolution to block the state's participation in RGGI, and such resolution was subsequently approved by the Pennsylvania House in December 2021.

On January 10, 2022, Governor Wolf vetoed the Senate's resolution, and as a result, it is likely that Pennsylvania will join RGGI in 2022 unless the Pennsylvania legislature overrides the Governor's veto by the vote of two-thirds of the members of each of the Pennsylvania House and Senate.

In the event that Pennsylvania ultimately becomes a member of RGGI, it will result in increased operating costs if we are required to purchase emission allowances in connection with our operations.

Any legislation or regulatory programs at the federal, state or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the natural gas, NGLs and oil we produce.

Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

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 imposing a tax or fee or otherwise limiting emissions of GHGs from, our equipment and operations could require us to incur costs to comply with such regulations.

Substantial limitations or fees on GHG emissions could also adversely affect demand for the natural gas, NGLs and oil we produce and lower the value of our reserves.

Nonetheless, recent activism directed at shifting funding away from fossil fuel companies could result in limitations or restrictions on certain sources of funding for the sector.

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While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events;

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events.

If any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations.

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Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers.

To assess water sources near our drilling locations, we conduct baseline and, as appropriate, post-drilling water testing at all water wells within at least 2,500 feet of our 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, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules.

To assess water sources near our drilling locations, we conduct multiple pre-drill samplings for all water sources within 3,000 feet of our sites and post-drill samplings for sources within 1,500 feet of our sites.

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 has prohibited the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

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.

For example, 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.

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Occupational Safety and Health Act.

We are 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 our operations and that this information be provided to employees, state and local government authorities, and citizens.

We are also subject to the requirements of the federal Occupational Safety and Health Act (OSH Act) and comparable state laws that regulate the protection of the health and safety of employees.

In addition, the Occupational Health and Safety Administration's (OSHA) hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require us to maintain information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens.

Endangered Species Act and Migratory Bird Treaty Act.

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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.

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.

In August 2019, the FWS and National Marine Fisheries Service issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat.

In August 2019, the FWS and National Marine Fisheries Service (NMFS) issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat.

A coalition of states and environmental groups have challenged the three rules and litigation remains pending.

In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations;

In addition, in December 2020, the FWS amended its regulations governing critical habitat designations;

the amended regulations are subject to ongoing litigation.

Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (MBTA), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit.

In June 2021, the FWS and the NMFS announced plans to begin rulemaking processes to rescind these rules.

Protections similar to the ESA are offered to migratory birds under the Migratory Bird Treaty Act (MBTA), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit.

This prohibition covers most bird species in the U.S.

In January 2021, the Department of the Interior finalized a rule limiting application of the MBTA;

however, the Department of the Interior under President Biden delayed the effective date of the rule and opened a public comment period for further review.

however, the Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the Department's plan to develop regulations that authorize incidental taking under certain prescribed conditions.

Future implementation of the rules implementing the ESA and the MBTA are uncertain.

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Of our total permanent employee base, 75% were male and 25% were female.

The substantial majority of our employees reside in Pennsylvania and West Virginia.

Approximately 70% of our permanent employees worked remotely, with 93% residing in Pennsylvania or West Virginia.

We aim to develop a workforce that produces peer leading results.

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Our digital work environment serves as our primary platform for communication and collaboration as well as the home for our critical work processes and drives decision-making based on a shared and transparent view of operational data.

We use our digital work environment to engage directly with our employees by sharing company updates and personnel accomplishments and internal polling.

We use our digital work environment to engage directly with our employees by sharing company updates and personnel accomplishments as well as to solicit suggestions and comments from all employees.

We believe that this helps promote real-time feedback and a greater degree of employee engagement, which lays the foundation for the success of our remote workforce.

We understand that providing employees with the resources and support they need to live a physically, mentally and financially healthy life is critical for sustaining a workplace of choice.

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We also offer our employees the flexibility to elect to work a "9/80" work schedule, under which, during the standard 80-hour pay period, an employee works eight 9-hour days and one 8-hour day (Friday), with a tenth day off (alternative Friday).

In 2020, we launched an “equity-for-all” program, which granted equity awards to all of our permanent full-time employees.

With the equity-for-all program, all of our permanent full-time employees have the opportunity to share directly in our financial success.

These grants were in addition to, and not in lieu of, existing compensation for these employees.

In 2020, we launched an "equity-for-all" program, pursuant to which, in 2021, we granted equity awards to all of our permanent employees.

In 2022, we continued our equity-for-all program by granting equity awards to all permanent employees.

With the equity-for-all program, all of our permanent employees become owners of EQT and have the opportunity to share directly in our financial success.

Equity-for-all grants are in addition to, and not in lieu of, the existing compensation opportunities for our employees.

Availability of Reports and Other Information

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Reports filed with the SEC are also available on the SEC's website, http://www.sec.gov.

We also use our Twitter account, @EQTCorp, our Facebook account, @EQTCorporation, and our LinkedIn account, EQT Corporation, as additional ways of disseminating information that may be relevant to investors.

We use our Twitter account, @EQTCorp, our Facebook account, @EQTCorporation, and our LinkedIn account, EQT Corporation, as additional ways of disseminating information that may be relevant to investors.

We generally post the following to our investor relations website shortly before or promptly following its first use or release:

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Operating revenues:

Sales of natural gas, NGLs and oil $ 2,650,299 $ 3,791,414 $ 4,695,519

Gain (loss) on derivatives not designated as hedges 400,214 616,634 (178,591)

Sales of natural gas, natural gas liquids and oil $ 6,804,020 $ 2,650,299 $ 3,791,414

(Loss) gain on derivatives not designated as hedges (3,775,042) 400,214 616,634

Net marketing services and other 35,685 8,330 8,436

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business