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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2020
Commission file number 001-08246
https://cdn.kscope.io/f7e10ebf483f660cb071b063894211b8-swn-20201231_g1.jpg
Southwestern Energy Company
(Exact name of registrant as specified in its charter)
Delaware71-0205415
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
10000 Energy Drive
Spring, Texas 77389
(Address of principal executive offices)(Zip Code)
(832) 796-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, Par Value $0.01SWNNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒   No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐   No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒   No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒   No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerAccelerated filerNon-accelerated filerSmaller reporting companyEmerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes    No ☒ 
The aggregate market value of the voting stock held by non-affiliates of the registrant was $1,493,259,580 based on the New York Stock Exchange – Composite Transactions closing price on June 30, 2020 of $2.56. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.
As of February 25, 2021, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 674,457,398.
Document Incorporated by Reference
Portions of the registrant’s definitive proxy statement to be filed with respect to the annual meeting of stockholders to be held on or about May 18, 2021 are incorporated by reference into Part III of this Form 10-K.



SOUTHWESTERN ENERGY COMPANY
ANNUAL REPORT ON FORM 10-K
For Fiscal Year Ended December 31, 2020
TABLE OF CONTENTS
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This Annual Report on Form 10-K (“Annual Report”) includes certain statements that may be deemed to be “forward-looking” within the meaning of Section 27A of the Securities Act of 1933, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act.  We refer you to “Risk Factors” in Item 1A of Part I and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Annual Report for a discussion of factors that could cause actual results to differ materially from any such forward-looking statements.  The electronic version of this Annual Report, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those forms filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge as soon as reasonably practicable after they are filed with the Securities and Exchange Commission, or SEC, on our website at www.swn.com.  Our corporate governance guidelines and the charters of the Audit, the Compensation, the Health, Safety, Environment and Corporate Responsibility and the Nominating and Governance Committees of our Board of Directors are available on our website and, upon request, in print free of charge to any stockholder.  Information on our website is not incorporated into this report.
We file periodic reports, current reports and proxy statements with the SEC electronically.  The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.  The public may also read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549.  The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
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PART I
ITEM 1. BUSINESS
Southwestern Energy Company (including its subsidiaries, collectively, “we”, “our”, “us”, “the Company” or “Southwestern”) is an independent energy company engaged in exploration, development and production activities, including the related marketing of natural gas, oil and natural gas liquids (“NGLs”) produced in our operations.  Southwestern is a holding company whose assets consist of direct and indirect ownership interests in, and whose business is conducted substantially through, its subsidiaries.  Currently we operate exclusively in the United States.  Our common stock is listed and traded on the NYSE under the ticker symbol “SWN.”
Southwestern, which is incorporated in Delaware, has its executive offices located at 10000 Energy Drive, Spring, Texas 77389, and can be reached by phone at 832-796-1000.  The Company also maintains offices in Tunkhannock, Pennsylvania, Morgantown, West Virginia, and Zanesville, Ohio. 
Our Business Strategy
We aim to deliver sustainable and industry-leading returns through excellence in exploration and production and marketing performance from our extensive resource base and targeted expansion of our activities and assets along the hydrocarbon value chain.  Our Company’s formula embodies our corporate philosophy and guides how we operate our business:
https://cdn.kscope.io/f7e10ebf483f660cb071b063894211b8-swn-20201231_g2.jpg
Our formula, “The Right People doing the Right Things, wisely investing the cash flow from our underlying Assets will create Value+,” also guides our business strategy.  We always strive to attract and retain strong talent, to work safely and act ethically with unwavering vigilance for the environment and the communities in which we operate, and to creatively apply technical skills, which we believe will grow long-term value for our shareholders.  The arrow in our formula is not a straight line: we acknowledge that factors may adversely affect quarter-by-quarter results, but the path over time points to value creation.
In applying these core principles, we concentrate on:
Financial Strength. We are committed to rigorously managing our balance sheet and financial risks.  We budget and dynamically manage our operations in order to ensure that our investments do not exceed our cash flow from operations (net of changes in working capital) in each calendar year, protect our projected cash flows through hedging and continue to maintain a strong balance sheet with ample liquidity.  Our capital investment program in 2020 was supplemented with the remaining earmarked proceeds from the sale of our Fayetteville Shale assets in December 2018.
Increasing Margins. We apply strong technical, operational, commercial and marketing skills to reduce costs, improve the productivity of our wells and pursue commercial arrangements to extract greater value.  We believe our demonstrated ability to maximize margins, especially by leveraging the scale of our large assets, gives us a competitive advantage as we move into the future.
Exercising Capital Allocation Discipline. We continually assess market conditions in order to adjust our capital allocation decisions to maximize shareholder returns.  This allocation process includes consideration of multiple alternatives including but not limited to the development of our natural gas and oil assets, strategic mergers or acquisitions, reducing debt and returning capital to our shareholders.
Operational Value Creation.  We prepare an economic analysis for our drilling programs and other investments based upon the expected Internal Rate of Return.  We target projects that generate the highest returns in excess of our cost of capital.  This disciplined investment approach governs our investment decisions at all times, including the current lower-price commodity market.
Dynamic Management of Assets Throughout Life Cycle.  We own large-scale, long-life assets in various phases of development.  In early stages, we ramp up development through technical, operational and commercial skills, and as they grow we look for ways to maximize their value through efficient operating practices along with applying our commercial and marketing expertise.
Deepening Our Inventory.  We continue to expand the inventory of properties that we can develop profitably by converting our extensive resources into proved reserves, targeting additions whose productivity largely has been demonstrated and improving efficiencies in production.
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The Hydrocarbon Value Chain. We believe that our vertical integration enhances our margins and provides us competitive advantages.  For example, we own and operate drilling rigs and well stimulation equipment and have invested in a water transportation project in West Virginia.  These activities provide operational flexibility, lower our well costs, minimize the risk associated with the lack of availability of these resources from third parties and capture additional value over time.
Technological Innovation.  Our people constantly search for the next revolutionary technology and other operational advancements to capture greater value in unconventional hydrocarbon resource development.  These developments – whether single, step-changing technologies or a combination of several incremental ones – can reduce finding and development costs and thus increase our margins.
Environmental Solutions and Policy Formation. We are a leader in identifying and implementing innovative solutions to unconventional hydrocarbon development to minimize the environmental and community impacts of our activities.  We work extensively with governmental, non-governmental and industry stakeholders to develop responsible and cost-effective programs.  We demonstrate that a company can operate responsibly and profitably, putting us in a better position to comply with new regulations as they evolve.
During 2020 we executed on these business strategies by:
Expanding our portfolio in Appalachia by acquiring Montage Resources Corporation through an accretive all-stock transaction, increasing our economic inventory while recognizing immediate cost structure savings;
Dynamically managing our operational focus from liquids to dry gas in response to adverse economic conditions, resulting from the COVID-19 pandemic, in order to take advantage of more favorable commodity pricing;
Lowering our costs through drilling, completions and operational efficiencies and optimizing gathering and transportation costs;
Continuing to identify and implement structural, process and organizational changes to further reduce general and administrative costs;
Maintaining a robust multi-year hedging program to ensure a certain level of cash flow;
Focusing on delivering operational excellence with improved well productivity and economics from enhanced completion techniques, innovative water sourcing, optimization of surface equipment and managing reservoir drawdown;
Repurchasing approximately $107 million in aggregate principal amount of our outstanding senior notes for $72 million, recognizing a gain on the extinguishment of debt of $35 million; and
Publishing our 7th Annual Corporate Responsibility report for 2019 (available at www.swn.com). Key environmental highlights include:
We reported the lowest greenhouse gas intensity among our Appalachian peers in the annual Environmental Health and Safety Survey;
Our methane intensity was 85% better than the target set by ONE Future (a coalition of 37 natural gas companies working together to voluntarily lower methane emissions); and
We were fresh water neutral for the fifth year in a row; 100% of our fresh water usage was offset through recycling and conservation projects.
Note that the information on our website is not incorporated by reference into this filing.
The bulk of our operations, which we refer to as “Exploration and Production” (“E&P”), are focused on the finding and development of natural gas, oil and NGL reserves.  We are also focused on creating and capturing additional value through our marketing business, which we refer to as “Marketing.”

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Exploration and Production
Overview
Our primary business is the exploration for, and production of, natural gas, oil and NGLs, with our current operations solely within the United States.  We are currently focused on the development of unconventional natural gas reservoirs located in Pennsylvania, Ohio and West Virginia.  Our operations in northeast Pennsylvania (herein referred to as “Northeast Appalachia”) are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale, and our operations in West Virginia, southwest Pennsylvania and Ohio (herein referred to as “Southwest Appalachia”) are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas, oil and NGL reservoirs.  Collectively, our properties located in Pennsylvania, Ohio and West Virginia are herein referred to as “Appalachia.”
Our E&P segment recorded operating loss of $2,864 million in 2020, compared to operating income of $283 million in 2019.  Our E&P segment operating income (loss) decreased $3,147 million in 2020 from 2019 primarily due to $2,825 million of non-cash full cost ceiling test impairments. Excluding the impact of ceiling test impairments, operating income (loss) decreased $322 million compared to the same period in 2019 primarily due to lower margins associated with decreased commodity pricing.
Our cash flow from operations was $372 million in 2020, compared to $781 million in 2019. This $409 million decrease was primarily due to a 20% decrease in weighted average commodity prices, including derivatives, partially offset by a 13% increase in production volumes.
Oilfield Services Vertical Integration
We provide certain oilfield services that are strategic and economically beneficial for our E&P operations when our E&P activity levels and market pricing support these activities.  This vertical integration lowers our well costs, allows us to operate efficiently, provides agility to our operations allowing us to react quickly to rapid changes in market conditions and helps us to mitigate certain operational and environmental risks.  These services include drilling, completions and water management and movement. As of December 31, 2020, we operated a fleet of drilling rigs and leased two pressure pumping spreads with a total capacity of 72,000 horsepower. These assets provide us greater flexibility to align our operational activities with commodity prices. In 2020, we provided drilling rigs for all of our 98 drilled wells.  In addition, we provided completions services utilizing one pressure pumping spread in Southwest Appalachia.
Our Proved Reserves
For the years ended December 31,
20202019
Proved reserves: (Bcfe)
Appalachia11,989 12,720 
Other
Total proved reserves11,990 12,721 
Prices used:
Natural gas (per Mcf)
$1.98 $2.58 
Oil (per Bbl)
$39.57 $55.69 
NGL (per Bbl)
$10.27 $11.58 
PV-10: (in millions)
Pre-tax$1,847 $3,735 
PV of taxes— 
(1)
(35)
After-tax$1,847 $3,700 
Percent of estimated proved reserves that are:
Natural gas76 %68 %
Proved developed68 %50 %
Percent of E&P operating revenues generated by natural gas sales69 %71 %
(1)Our existing tax attributes, including net operating losses and remaining depreciable tax basis related to our natural gas and oil properties, more than offset our future net operating income, resulting in no tax effect to our PV-10 calculation for the year ended December 31, 2020.
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Our reserve estimates and the after-tax PV-10 measure, or standardized measure of discounted future net cash flows relating to proved natural gas, oil and NGL reserve quantities, are highly dependent upon the respective commodity price used in our reserve and after-tax PV-10 calculations.
Our reserves decreased 6% in 2020, compared to 2019, primarily due to a decrease in commodity pricing, partially offset by the reserves acquired from Montage.
Our after-tax PV-10 value decreased in 2020 compared to 2019 as lower reserve levels resulted primarily from a decrease in SEC 12-month backward-looking commodity prices.
We are the designated operator of approximately 97% of our reserves, based on the pre-tax PV-10 value of our proved developed producing reserves, and our reserve life index was approximately 11.3 years at year-end 2020, using an estimate of full year production from our recently acquired Montage properties.
The following table presents the PV-10 value of our reported year-end 2020 reserves balance using SEC 12-month backward-looking prices and the 12-month forward-looking strip prices as of January 4, 2021:
2020 Year-End
SEC Pricing (1)
Strip Pricing
Natural gas price (per MMBtu)
$1.98 $2.70 
WTI oil price (per Bbl)
$39.57 $47.67 
NGL price (per Bbl)
$10.27 $11.82 
Proved reserves after-tax PV-10 (in billions)
$1.85 $5.85 
(1)Adjusted for market differentials.
The difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2020 Proved Reserves by Category and Summary Operating Data table below) is the discounted value of future income taxes on the estimated cash flows.   Our existing tax attributes, including net operating losses and remaining depreciable tax basis related to our natural gas and oil properties, more than offset our future net operating income, resulting in no tax effect to our PV-10 calculation for the year ended December 31, 2020.
We believe that the pre-tax PV-10 value of the estimated cash flows related to our estimated proved reserves is a useful supplemental disclosure to the after-tax PV-10 value.  Pre-tax PV-10 is based on prices, costs and discount factors that are comparable from company to company, while the after-tax PV-10 is dependent on the unique tax situation of each individual company.  We understand that securities analysts use pre-tax PV-10 as one measure of the value of a company’s current proved reserves and to compare relative values among peer companies without regard to income taxes.  We refer you to “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report for a discussion of our standardized measure of discounted future cash flows related to our proved natural gas, oil and NGL reserves, to the risk factor “Our proved natural gas, oil and NGL reserves are estimates that include uncertainties.  Any material change to these uncertainties or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A of Part I of this Annual Report, and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Annual Report for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.
Lower natural gas, oil and NGL prices reduce the value of our assets, both by a direct reduction in what the production could be sold for and by making some properties uneconomic, resulting in decreases to the overall value of our reserves and potential non-cash impairment charges to earnings.  Further non-cash impairments in future periods could occur if the trailing 12-month commodity prices decrease as compared to the average used in prior periods.
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The following table provides an overall and categorical summary of our natural gas, oil and NGL reserves, as of year-end 2020 based on average year prices, and our well count, net acreage and PV-10 as of December 31, 2020, and sets forth 2020 annual information related to production and capital investments for each of our operating areas:
2020 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA
Appalachia
NortheastSouthwest
Other (1)
Total
Estimated proved reserves:
Natural gas (Bcf):
Developed3,668 2,674 — 6,342 
Undeveloped1,248 1,591 — 2,839 
4,916 4,265 — 9,181 
Crude oil (MMBbls):
Developed— 33.5 0.1 33.6 
Undeveloped— 24.5 — 24.5 
— 58.0 0.1 58.1 
Natural gas liquids (MMBbls):
Developed— 276.5 — 276.5 
Undeveloped— 133.6 — 133.6 
— 410.1 — 410.1 
Total proved reserves (Bcfe) (2):
Developed3,668 4,534 8,203 
Undeveloped1,248 2,539 — 3,787 
4,916 7,073 11,990 
Percent of total41 %59 %— %100 %
Percent proved developed75 %64 %100 %68 %
Percent proved undeveloped25 %36 %0%32 %
Production (Bcfe)
473 407 — 880 
Capital investments (in millions)
$362 $510 $27 
(3)
$899 
Total gross producing wells (4)
744 1,833 14 2,591 
Total net producing wells668 1,521 11 2,200 
Total net acreage217,296 571,922 22,001 
(5)
811,219 
Net undeveloped acreage89,086 425,702 9,764 
(5)
524,552 
PV-10:
Pre-tax (in millions) (6)
$876 $974 $(3)
(7)
$1,847 
PV of taxes (in millions) (6)
— — —  
After-tax (in millions) (6)
$876 $974 $(3)
(7)
$1,847 
Percent of total47 %53 %0%100 %
Percent operated (8)
98 %100 %97 %97 %
(1)Other reserves and acreage consists primarily of properties in Colorado. 
(2)We have no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil.  We used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis, offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors.
(3)Other capital investments includes $9 million related to our water infrastructure project, $16 million related to our E&P service companies and $2 million related to other developmental activities.
(4)Excludes 587 wells in Northeast Appalachia and 99 wells in Southwest Appalachia in which we only have an overriding royalty interest. These wells were included in the December 31, 2020 reserves calculation.
(5)Excludes exploration licenses for 2,518,519 net acres in New Brunswick, Canada, which have been subject to a moratorium since 2015. We are currently working with Canadian officials to extend our licenses, although we cannot assure that the licenses will be extended past March 2021.
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(6)Pre-tax PV-10 (a non-GAAP measure) is one measure of the value of a company’s proved reserves that we believe is used by securities analysts to compare relative values among peer companies without regard to income taxes.  The reconciling difference in pre-tax PV-10 and the after-tax PV-10, or standardized measure, is the discounted value of future income taxes on the estimated cash flows from our proved natural gas, oil and NGL reserves. Our existing tax attributes, including net operating losses and remaining depreciable tax basis related to our natural gas and oil properties, more than offset our future net operating income, resulting in no tax effect to our PV-10 calculation for the year ended December 31, 2020.
(7)Includes future asset retirement obligations outside of Appalachia.
(8)Based upon pre-tax PV-10 of proved developed producing activities.
Lease Expirations
The following table summarizes the leasehold acreage expiring over the next three years, assuming successful wells are not drilled to develop the acreage and leases are not extended:
For the years ended December 31,
Net acreage expiring:202120222023
Northeast Appalachia5,861 
(1)
6,460 6,921 
Southwest Appalachia (2)
36,690 
(1)
20,149 11,986 
Other
US – Other Exploration
5,683 646 — 
US – Sand Wash Basin3,435 — — 
Canada – New Brunswick (3)
2,518,519 — — 
(1)We have no reported proved undeveloped locations expiring in 2021.
(2)The leasehold acreage expiring includes 8,907 acres acquired through the Montage Merger that are subject to annual extension options at our sole discretion. Excluding this acreage, of the remaining leasehold acreage expiring, 17,460 net acres in 2021, 6,173 net acres in 2022 and 5,573 net acres in 2023 can be extended for an average 4.9 years.
(3)Exploration licenses were extended through March 2021 but have been subject to a moratorium since 2015. We are currently working with Canadian officials to extend our licenses, although we cannot assure that the licenses will be extended past March 2021. We fully impaired our investment in New Brunswick in 2016.
We refer you to “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report for a more detailed discussion of our proved natural gas, oil and NGL reserves as well as our standardized measure of discounted future net cash flows related to our proved natural gas, oil and NGL reserves.  We also refer you to the risk factor “Our proved natural gas, oil and NGL reserves are estimates that include uncertainties.  Any material changes to these uncertainties or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A of Part I of this Annual Report and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Annual Report for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.
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Proved Undeveloped Reserves
Presented below is a summary of changes in our proved undeveloped reserves for 2019 and 2020:
CHANGES IN PROVED UNDEVELOPED RESERVES
AppalachiaTotal
(in Bcfe)NortheastSouthwest
December 31, 20181,039 5,325 6,364 
Extensions, discoveries and other additions677 327 1,004 
Performance and production revisions (1)
(40)723 683 
Reclassification of PUD to unproved under SEC five-year rule (2)
— (109)(109)
Price revisions(12)(395)(407)
Developed(397)(838)(1,235)
Disposition of reserves in place— —  
Acquisition of reserves in place— —  
December 31, 20191,267 5,033 6,300 
Extensions, discoveries and other additions474 — 474 
Performance and production revisions (1)
(26)593 567 
Price revisions(213)(3,075)(3,288)
Developed(457)(1,030)(1,487)
Disposition of reserves in place— —  
Acquisition of reserves in place203 1,018 1,221 
December 31, 20201,248 2,539 3,787 
(1)Primarily due to changes associated with the analysis of updated data collected in the year and decreases related to current year production.
(2)Consists of reserves associated with planned wells that were PUD at the beginning of the year but were subsequently reclassified to unproved due to changes in the drilling plan, in accordance with the SEC five-year rule.
Performance, production and price revisions consist of revisions to reserves associated with wells having proved reserves in existence as of the beginning of the year.  Extensions, discoveries and other additions include new reserves locations added in the current year.
As of December 31, 2020, we had 3,787 Bcfe of proved undeveloped reserves, all of which we expect will be developed within five years of the initial disclosure as the starting reference date.  During 2020, we invested $674 million in connection with converting 1,487 Bcfe, or 24%, of our proved undeveloped reserves as of December 31, 2019 into proved developed reserves and added 474 Bcfe of proved undeveloped reserves. As a result of the commodity price environment in 2020, we had downward price revisions of 3,288 Bcfe. These reductions were partially offset by a 567 Bcfe increase due to performance and production revisions.
As of December 31, 2019, we had 6,300 Bcfe of proved undeveloped reserves.  During 2019, we invested $638 million in connection with converting 1,235 Bcfe, or 19%, of our proved undeveloped reserves as of December 31, 2018 into proved developed reserves and added 1,004 Bcfe of proved undeveloped reserves. As a result of the commodity price environment in 2019, we had downward price revisions of 407 Bcfe. In addition, we also had 109 Bcfe that was reclassified to unproven. These reductions were more than offset by a 683 Bcfe increase due to performance and production revisions. Certain planned wells that were proved undeveloped as of the beginning of 2019 were rescheduled beyond five years. Accordingly, the proved undeveloped reserves associated with these planned wells were removed in 2019 as they fell outside of the SEC mandated five-year development window. We expect these previous proved undeveloped reserves to be added back in future years.
Our December 31, 2020 proved reserves included 2,437 Bcfe of proved undeveloped reserves from 138 locations that have a positive present value on an undiscounted basis in compliance with proved reserve requirements but do not have a positive present value when discounted at 10%. These properties have a negative present value of $207 million when discounted at 10%. We have made a final investment decision and are committed to developing these reserves within five years from the date of initial booking.

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We expect that the development costs for our proved undeveloped reserves of 3,787 Bcfe as of December 31, 2020 will require us to invest an additional $1.6 billion for those reserves to be brought to production.  Our ability to make the necessary investments to generate these cash inflows is subject to factors that may be beyond our control.  The commodity price environment over the past year has resulted, and could continue to result, in certain reserves no longer being economic to produce, leading to both lower proved reserves and cash flows.  We refer you to the risk factors “Natural gas, oil and NGL prices greatly affect our revenues and thus profits, liquidity, growth, ability to repay our debt and the value of our assets” and “Significant capital investment is required to replace our reserves and conduct our business” in Item 1A of Part I of this Annual Report and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Annual Report for a more detailed discussion of these factors and other risks.
Our Reserve Replacement
The reserve replacement ratio measures the success of an E&P company in adding new reserves to replace the reserves that are being depleted by its current production volumes.  The reserve replacement ratio, which we discuss below, is an important analytical measure used by investors and peers in the E&P industry to evaluate performance results and long-term prospects.  There are limitations as to the usefulness of this measure, as it does not reflect the type of reserves or the cost of adding the reserves or indicate the potential value of the reserve additions. 
In 2020, we replaced 84% of our production volumes with 741 Bcfe of proved reserve additions, all of which were from Appalachia. The impact of the reserve decrease associated with price revisions was substantially offset by the positive performance and production revisions and reserves acquired in the Montage acquisition. The following table summarizes the changes in our proved natural gas, oil and NGL reserves for the year ended December 31, 2020:
Appalachia
Other (1)
Total
(in Bcfe)NortheastSouthwest
December 31, 20194,837 7,883 1 12,721 
Net revisions
Price revisions(389)(3,981)— (4,370)
Performance and production revisions46 1,378 — 1,424 
Total net revisions(343)(2,603)— (2,946)
Extensions, discoveries and other additions
Proved developed198 69 — 267 
Proved undeveloped474 — — 474 
Total reserve additions672 69 — 741 
Production(473)(407)— (880)
Acquisition of reserves in place223 2,131 — 2,354 
Disposition of reserves in place— — —  
December 31, 20204,916 7,073 1 11,990 
(1)Other includes properties outside of Appalachia.
Our ability to add reserves depends upon many factors that are beyond our control.  We refer you to the risk factors “Significant capital investment is required to replace our reserves and conduct our business” and “If we are not able to replace reserves, our production levels and thus our revenues and profits may decline.” in Item 1A of Part I of this Annual Report and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Annual Report for a more detailed discussion of these factors and other risks.
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Our Operations
Northeast Appalachia
Northeast Appalachia represented 54% of our total 2020 net production and 41% of our total reserves as of December 31, 2020.  In 2020, our reserves in Northeast Appalachia increased by 79 Bcf, which included net additions of 672 Bcf, acquisitions of 223 Bcf and net upward performance revisions of 46 Bcf, partially offset by net downward price revisions of 389 Bcf and production of 473 Bcf.  As of December 31, 2020, we had approximately 217,296 net acres in Northeast Appalachia and had a total of 677 wells on production that we operated.  Below is a summary of Northeast Appalachia’s operating results for the latest two years: 
For the years ended December 31,
20202019
Acreage
Net undeveloped acres89,086 
(1)
53,435 
Net developed acres128,210 120,559 
Total net acres217,296 173,994 
Net Production (Bcf)
473 459 
Reserves
Reserves (Bcf)
4,916 4,837 
Locations:
Proved developed producing (2)
744 695 
Proved developed non-producing (3)
11 
Proved undeveloped57 82 
Total locations810 

788 
Gross Operated Well Count Summary
Drilled49 39 
Completed44 44 
Wells to sales45 44 
Capital Investments (in millions)
Drilling and completions, including workovers$321 $314 
Acquisition and leasehold13 
Seismic and other
Capitalized interest and expense23 33 
Total capital investments$362 $365 
Average completed well cost (in millions)
$6.8 $7.3 
Average lateral length (feet)
10,765 9,029 
(1)Our undeveloped acreage position as of December 31, 2020 had an average royalty interest of 15%.
(2)Excludes 587 and 516 wells as of December 31, 2020 and 2019, respectively, in which we have only an overriding royalty interest.
(3)Excludes 27 and 3 wells as of December 31, 2020 and 2019, respectively, in which we have only an overriding royalty interest.
For 2020 as compared to 2019:
Our average completed well cost per foot decreased primarily due to increased lateral lengths and operational execution.
Our ability to bring our Northeast Appalachia production to market depends on a number of factors including the construction of and/or the availability of capacity on gathering systems and pipelines that we do not own.  We refer you to “Marketing” in Item 1 of Part I of this Annual Report for a discussion of our gathering and transportation arrangements for Northeast Appalachia production.

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Southwest Appalachia
Southwest Appalachia represented 46% of our total 2020 net production and 59% of our total reserves as of December 31, 2020.  In 2020, our reserves in Southwest Appalachia decreased by 810 Bcfe, as net downward price revisions of 3,981 Bcfe and production of 407 Bcfe were only partially offset by acquisitions of 2,131 Bcfe, net upward performance revisions of 1,378 Bcfe and net additions of 69 Bcfe.  As of December 31, 2020, we had approximately 571,922 net acres in Southwest Appalachia and had a total of 1,670 wells on production that we operated.  Below is a summary of Southwest Appalachia’s operating results for the latest two years:
For the years ended December 31,
20202019
Acreage
Net undeveloped acres425,702 
(1)
205,222 
Net developed acres146,220 82,471 
Total net acres571,922 287,693 
Net Production
Natural gas (Bcf)
221 150 
Oil (MBbls)
5,124 4,673 
NGL (MBbls)
25,923 23,611 
Total production (Bcfe) (2)
407 319 
Reserves
Reserves (Bcfe)
7,073 7,883 
Locations:
Proved developed producing (3)
1,833 496 
Proved developed non-producing (4)
162 48 
Proved undeveloped151 376 
Total locations2,146 920 
Gross Operated Well Count Summary
Drilled49 66 
Completed52 72 
Wells to sales55 69 
Capital Investments (in millions)
Drilling and completions, including workovers$360 $516 
Acquisition and leasehold28 42 
Seismic and other
Capitalized interest and expense121 149 
Total capital investments (5)
$510 $710 
Average completed well cost (in millions) (6)
$9.3 $8.9 
Average lateral length (feet) (6)
13,265 10,642 
(1)Our undeveloped acreage position as of December 31, 2020 had an average royalty interest of 15%.
(2)Approximately 405 Bcfe and 317 Bcfe for the years ended December 31, 2020 and 2019, respectively, were produced from the Marcellus Shale formation.
(3)Excludes 99 and 5 wells as of December 31, 2020 and 2019, respectively, in which we have only an overriding royalty interest.
(4)Excludes 27 wells as of December 31, 2020 in which we have only an overriding royalty interest.
(5)Excludes $9 million and $35 million for the years ended December 31, 2020 and 2019, respectively, related to our water infrastructure project.
(6)Average completed well cost and average lateral length for the years ended December 31, 2020 and 2019 include both Marcellus wells and Upper Devonian wells.
For 2020 as compared to 2019:
Our average completed well cost per foot decreased primarily due to increased lateral lengths, operational execution and savings from vertical integration.
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Our ability to bring our Southwest Appalachia production to market will depend on a number of factors including the construction of and/or the availability of capacity on gathering systems and pipelines that we do not own.  We refer you to “Marketing” within Item 1 of Part I of this Annual Report for a discussion of our gathering and transportation arrangements for Southwest Appalachia production.
Other
Excluding 2,518,519 acres in New Brunswick, Canada, which have been subject to a government-imposed drilling moratorium since 2015, we held 9,764 net undeveloped acres for the potential development of new resources as of December 31, 2020 in areas outside of Appalachia.  This compares to 27,334 net undeveloped acres held at year-end 2019, excluding the New Brunswick acreage.
We limited our activities in areas beyond our assets in Appalachia during 2020 and 2019 as a result of the commodity price environment as we focused our capital allocation on these more economically competitive plays.  There can be no assurance that any prospects outside of our development plays will result in viable projects or that we will not abandon our initial investments. 
New Brunswick, Canada. We currently hold exclusive licenses to search and conduct an exploration program covering 2,518,519 net acres in New Brunswick.  In 2015, the provincial government in New Brunswick imposed a moratorium on hydraulic fracturing until it is satisfied with a list of conditions.  In response to this moratorium, we requested and were granted an extension of its licenses to March 2021.  In May 2016, the provincial government announced that the moratorium would continue indefinitely.  Given this development, we fully impaired our investment in New Brunswick in 2016. We are currently working with Canadian officials to extend our licenses, although we cannot assure that the licenses will be extended past March 2021. Unless and until the moratorium is lifted, we will not be able to develop these assets.
Acquisitions and Divestitures
In November 2020, we completed a merger with Montage Resources Corporation (the “Merger”) pursuant to which Montage merged with and into Southwestern, with Southwestern continuing as the surviving company. At the effective time of the Merger we acquired all of the outstanding shares of common stock in Montage in exchange for 1.8656 shares of our common stock per share of Montage common stock. The Merger expanded our footprint in Appalachia by supplementing our Northeast Appalachia and Southwest Appalachia operations and by expanding our operations into Ohio. See Note 3 to the consolidated financial statements of this Annual Report for more information on the Merger.
During 2019, we sold non-core acreage for $38 million. There was no production or proved reserves associated with this acreage.
Capital Investments
For the years ended December 31,
(in millions)20202019
E&P Capital Investments by Type
Exploratory and development drilling, including workovers$692 $838 
Acquisition of properties37 55 
Seismic expenditures— 
Water infrastructure project35 
Other17 21 
Capitalized interest and expenses144 186 
Total E&P capital investments$899 $1,138 
E&P Capital Investments by Area
Northeast Appalachia$362 $365 
Southwest Appalachia510 710 
Other (1)
27 63 
Total E&P capital investments$899 $1,138 
(1)Includes $9 million and $35 million for the years ended December 31, 2020 and 2019 related to our water infrastructure project.
The decrease in 2020 E&P capital investing, as compared to the prior year, resulted from reduced average well costs as well as our commitment to invest within our cash flows from operations, which are heavily dependent on commodity prices, supplemented by the remaining proceeds from the Fayetteville Shale sale.
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In 2020, we drilled 98 wells (86 of which were spud in 2020), completed 96 wells, placed 100 wells to sales and had 42 wells in progress at year-end. 
Of the 42 wells in progress at year-end, 26 and 16 were located in Northeast Appalachia and Southwest Appalachia, respectively.
We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Investing” within Item 7 of Part II of this Annual Report for additional discussion of the factors that could impact our planned capital investments in 2021.
Sales, Delivery Commitments and Customers
Sales.  The following tables present historical information about our production volumes for natural gas, oil and NGLs and our average realized natural gas, oil and NGL sales prices:
For the years ended December 31,
20202019
Average net daily production (MMcfe/day)
2,403 2,133 
Production:
Natural gas (Bcf)
694 609 
Oil (MBbls)
5,141 4,696 
NGLs (MBbls)
25,927 23,620 
Total production (Bcfe)
880 778 
The increase in production in 2020 resulted primarily from a 88 Bcfe increase in net production in Southwest Appalachia and a 14 Bcf increase in production in Northeast Appalachia. These increases included 28 Bcfe in production from our acreage newly acquired through the Merger.
Average Realized Prices
For the years ended December 31,
20202019
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)
$2.08 $2.63 
Discount to NYMEX (2)
(0.74)(0.65)
Average realized gas price, excluding derivatives ($/Mcf)
$1.34 $1.98 
Gain on settled financial basis derivatives ($/Mcf)
0.11 — 
Gain on settled commodity derivatives ($/Mcf)
0.25 0.20 
Average realized gas price, including derivatives ($/Mcf)
$1.70 $2.18 
Oil Price:
WTI oil price ($/Bbl)
$39.40 $57.03 
Discount to WTI(10.20)(10.13)
Average realized oil price, excluding derivatives ($/Bbl)
$29.20 $46.90 
Gain on settled derivatives ($/Bbl)
17.71 2.66 
Average realized oil price, including derivatives ($/Bbl)
$46.91 $49.56 
NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)
$10.24 $11.59 
Gain on settled derivatives ($/Bbl)
0.91 2.05 
Average realized NGL price, including derivatives ($/Bbl)
$11.15 $13.64 
Percentage of WTI, excluding derivatives26 %20 %
Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)
$1.53 $2.18 
Including derivatives ($/Mcfe)
$1.94 $2.42 
(1)Based on last day settlement prices from monthly futures contracts.
(2)This discount includes a basis differential, a heating content adjustment, physical basis sales, third-party transportation charges and fuel charges, and excludes financial basis hedges.
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Sales of natural gas, oil and NGL production are conducted under contracts that reflect current prices and are subject to seasonal price swings.  We are unable to predict changes in the market demand and price for these commodities, including changes that may be induced by the effects of weather on demand for our production.  We regularly enter into various derivative and other financial arrangements with respect to a portion of our projected production to support certain desired levels of cash flow and to minimize the impact of price fluctuations.  We limit derivative agreements to counterparties with appropriate credit standings, and our policies prohibit speculation.
As of December 31, 2020, we had the following commodity price derivatives in place on our targeted future production:
For the years ended December 31,
202120222023
Natural gas (Bcf)
751 378 87 
Oil (MBbls)
6,631 2,155 878 
Ethane (MBbls)
6,473 1,710 — 
Propane (MBbls)
6,974 2,120 — 
Normal Butane (MBbls)
2,004 667 — 
Natural Gasoline (MBbls)
1,936 643 — 
As of February 25, 2021, we had the following commodity price derivatives in place on our targeted 2020 and future production:
For the years ended December 31,
202120222023
Natural gas (Bcf)
761 454 103 
Oil (MBbls)
6,631 2,850 878 
Ethane (MBbls)
6,560 1,893 — 
Propane (MBbls)
7,149 2,727 — 
Normal Butane (MBbls)
2,092 794 — 
Natural Gasoline (MBbls)
2,021 765 — 
We intend to use derivatives to limit the impact of price volatility on a large portion of expected future production volumes to ensure certain desired levels of cash flow.  We refer you to Item 7A of Part II of this Annual Report, “Quantitative and Qualitative Disclosures about Market Risk,” for further information regarding our derivatives and risk management as of December 31, 2020.
During 2020, the average price we received for our natural gas production, excluding the impact of derivatives and including the cost of transportation, was approximately $0.74 per Mcf lower than average New York Mercantile Exchange, or NYMEX, prices.  Differences between NYMEX and price realized (basis differentials) are due primarily to locational differences and transportation cost. 
As of December 31, 2020, we have entered into physical sales arrangements to limit the impact of basis volatility on approximately 217 Bcf and 65 Bcf of our 2021 and 2022 expected natural gas production, respectively, at a basis differential to NYMEX natural gas price of approximately ($0.24) per MMBtu and ($0.35) per MMBtu for 2021 and 2022, respectively.
We have also entered into financial basis swaps for approximately 219 Bcf, 139 Bcf, 47 Bcf, 11 Bcf and 4 Bcf of our 2021, 2022, 2023, 2024, and 2025 expected natural gas production, respectively, at a basis differential to NYMEX natural gas price of approximately ($0.21) per MMBtu, ($0.33) per MMBtu, ($0.45) per MMBtu, ($0.60) per MMBtu and ($0.59) per MMBtu for 2021, 2022, 2023, 2024 and 2025, respectively, as of December 31, 2020.
We refer you to Note 6 to the consolidated financial statements included in this Annual Report for additional discussion about our derivatives and risk management activities.
Delivery Commitments. As of December 31, 2020, we had natural gas delivery commitments of 486 Bcf in 2021 and 113 Bcf in 2022 under existing agreements. These amounts are well below our expected 2021 natural gas production from Northeast Appalachia and Southwest Appalachia and expected 2022 production from our available reserves, which are not subject to any priorities or curtailments that may affect quantities delivered to our customers or any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond our control that may affect our ability to meet our delivery commitments other than those discussed in Item 1A “Risk Factors” of Part I of this Annual Report.  We expect to be able to fulfill all of our short-term and long-term delivery commitments to provide natural gas from our own production of available reserves; however, if we are unable to do so, we may have to purchase natural gas at market to fulfill our obligations.
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Customers.  Our E&P production is marketed primarily by our Marketing segment.  Our customers include major energy companies, utilities and industrial purchasers of natural gas.  For the year ended December 31, 2020, one purchaser accounted for 10% of our revenues. A default on this account could have a material impact on the Company, but we do not believe that there is a material risk of default. No other purchasers accounted for greater than 10% of consolidated revenues. During the year ended December 31, 2019, no single third-party purchaser accounted for 10% or more of our consolidated revenues. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, oil and NGL production.
Competition
All phases of the natural gas and oil industry are highly competitive.  We compete in the acquisition and disposition of properties, the search for and development of reserves, the production and marketing of natural gas, oil and NGLs, and the securing of labor, services and equipment required to conduct our operations.  Our competitors include major oil and natural gas companies, other independent oil and natural gas companies and individual producers.  Many of these competitors have financial and other resources that substantially exceed those available to us.  Consequently, we will encounter competition that may affect both the price we receive and contract terms we must offer.  We also face competition in accessing pipeline and other services to transport our product to market.  Likewise, there are substitutes for the commodities we produce, such as other fuels for power generation, heating and transportation, and those markets in effect compete with us.
We cannot predict whether and to what extent any regulatory changes initiated by the Federal Energy Regulatory Commission, or the FERC, or any other new energy legislation or regulations will achieve the goal of increasing competition, lessening preferential treatment and enhancing transparency in markets in which our natural gas production is sold.  Similarly, we cannot predict whether legal constraints that have hindered the development of new transportation infrastructure, particularly in the northeastern United States, will continue.  However, we do not believe that we will be disproportionately affected as compared to other natural gas and oil producers and marketers by any action taken by the FERC or any other legislative or regulatory body or the status of the development of transportation facilities.
Regulation
Producing natural gas, oil and NGL resources and transporting and selling production historically have been heavily regulated.  For example, state governments regulate the location of wells and establish the minimum size for spacing units.  Permits typically are required before drilling.  State and local government zoning and land use regulations may also limit the locations for drilling and production.  Similar regulations can also affect the location, construction and operation of gathering and other pipelines needed to transport production to market.  In addition, various suppliers of goods and services may require licensing.
Currently in the United States, the price at which natural gas, oil or NGLs may be sold is not regulated.  Congress has imposed price regulation from time to time, and there can be no assurance that the current, less stringent regulatory approach will continue.  In 2015, the federal government repealed a 40-year ban on the export of crude oil.  The export of natural gas continues to require federal permits.  Broader freedom to export could lead to higher prices.  In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and the rules that the U.S. Commodity Futures Trading Commission, (the “CFTC”), the SEC, and certain other regulators have issued thereunder regulate certain swaps, futures and options contracts in the major energy markets, including for natural gas, oil and NGLs
Producing and transporting natural gas, oil and NGLs is also subject to extensive environmental regulation.  We refer you to “Other – Environmental Regulation” in Item 1 of Part 1 of this Annual Report and the risk factor “We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report for a discussion of the impact of environmental regulation on our business.
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Marketing
We engage in marketing activities which primarily support our E&P operations and generate revenue through the marketing of natural gas, oil and NGLs.
For the years ended December 31,
20202019
Marketing revenues (in millions)
$2,145 $2,849 
Other revenues (in millions)
— 
Total operating revenues (in millions)
$2,145 $2,850 
Operating income (loss) (in millions)
$(7)$(13)
Volumes marketed (Bcfe)
1,138 1,101 
Percent natural gas production marketed from affiliated E&P operations89 %79 %
Percent oil and NGL production marketed from affiliated E&P operations81 %61 %
Operating loss decreased $6 million for the year ended December 31, 2020, compared to 2019, primarily due to a $2 million decrease in operating costs and expenses. In addition, marketing operating loss for the year ended December 31, 2019 included a $3 million impairment of non-core gathering assets, a $2 million loss on the sale of operating assets and $1 million in gas storage gains recorded in other operating revenues.
Marketing revenues decreased in 2020, compared to 2019, primarily as a 27% decrease in the price received for volumes marketed more than offset a 37 Bcfe increase in marketed volumes.
Cash flow from operations of $317 million generated by our Marketing segment decreased in 2020, compared to 2019, as a $706 million decrease in cash operating costs and expenses was offset by a $705 million decrease in operating revenues and a $441 million decrease primarily related to timing differences of payables and receivables between the respective periods.
Marketing
We attempt to capture opportunities related to the marketing and transportation of natural gas, oil and NGLs primarily involving the marketing of our own equity production and that of royalty owners in our wells.  Additionally, we manage portfolio and locational, or basis, risk, acquire transportation rights on third-party pipelines and, in limited circumstances, purchase third-party natural gas to fulfill commitments specific to a geographic location.
Northeast Appalachia.  Our transportation portfolio in Northeast Appalachia is highly diversified and allows us to access premium city-gate markets as well as to deliver natural gas from the Appalachian basin area to the southeast United States.  The capacity agreements contain multiple extension and reduction options that allow us to right-size our transportation portfolio as needed for our production or to capture future market opportunities.  The table below details our firm transportation, firm sales and total takeaway capacity over the next three years as of February 25, 2021:
For the year ended December 31,
(MMBtu/d)202120222023
Firm transportation (1)
1,252,574 938,347 709,498 
Firm sales341,744 127,439 29,864 
Total firm takeaway – Northeast Appalachia1,594,318 1,065,786 739,362 
(1)We have extension options and potential contract renewal capacity of 332,000 MMBtu per day for 2022 and 559,000 MMBtu per day for 2023 for Northeast Appalachia.
Southwest Appalachia.  Our transportation portfolio for all products in Southwest Appalachia, including commitments acquired through the Montage Merger, allows us to capitalize on strengthening markets and provides a path for production growth.  Agreements with ET Rover Pipeline LLC and Columbia Pipeline Group, Inc.’s Mountaineer Xpress and Gulf Xpress pipelines allow us to access high-demand markets along the Gulf Coast while also capturing materially improving in-basin pricing, and our agreements with Rockies Express Pipeline LLC provide access to premium Midwest markets.  In addition to our natural gas transportation, we have ethane take-away capacity that provides direct access to Mont Belvieu pricing.  The table
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below details our natural gas firm transportation, firm sales and total takeaway capacity over the next three years as of February 25, 2021:
For the year ended December 31,
(MMBtu/d)202120222023
Firm transportation (1)
1,102,016 1,279,900 1,240,539 
Firm sales294,722 47,817 47,817 
Total firm takeaway – Southwest Appalachia1,396,738 1,327,717 1,288,356 
(1)We have extension options and potential contract renewal capacity of 76,900 MMBtu per day for 2022 and 76,900 MMBtu per day for 2023 for Southwest Appalachia.
Demand Charges
As of December 31, 2020, our obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $8.5 billion, $531 million of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts.  We also have guarantee obligations of up to $923 million of that amount.  In February 2020, we were notified that the proposed Constitution pipeline project was cancelled and that we were released from a firm transportation agreement with its sponsor.
In the first quarter of 2019, we agreed to purchase firm transportation with pipelines in Appalachia starting in 2021 and running through 2032 totaling $357 million in total contractual commitments, of which the seller has agreed to reimburse us for $133 million.
We refer you to Note 10 to the consolidated financial statements included in this Annual Report for further details on our demand charges and the risk factor “We have made significant investments in oilfield services businesses, including our drilling rigs, water infrastructure and pressure pumping equipment, to lower costs and secure inputs for our operations and transportation for our production.  If our development and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations.  In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers” in Item 1A of Part I of this Annual Report.
Competition
Our marketing activities compete with numerous other companies offering the same services, many of which possess larger financial and other resources than we have.  Some of these competitors are other producers and affiliates of companies with extensive pipeline systems that are used for transportation from producers to end users. Other factors affecting competition are the cost and availability of alternative fuels, the level of consumer demand and the cost of and proximity to pipelines and other transportation facilities.  We believe that our ability to compete effectively within the marketing segment in the future depends upon establishing and maintaining strong relationships with customers.
Customers
Our marketing customers include major energy companies, utilities and industrial purchasers of natural gas.  For the year ended December 31, 2020, one purchaser accounted for 10% of our revenues. A default could have a material impact on the Company, but we do not believe that there is a material risk of default. No other purchasers accounted for greater than 10% of consolidated revenues. During the year ended December 31, 2019, no single third-party purchaser accounted for 10% or more of our consolidated revenues. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, oil and NGL production.
Regulation
The transportation of natural gas, oil and NGLs is heavily regulated.  FERC regulates the rates and the terms and conditions of transportation service provided by interstate natural gas, crude oil and NGL pipelines. State governments typically must authorize the construction of pipelines for intrastate service. Moreover, the rates charged for intrastate transportation by pipeline are subject to regulation by state regulatory commissions. The basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate pipeline rates, varies from state to state. Currently, all pipelines we own are intrastate and immaterial to our operations.
State and local permitting, zoning and land use regulations can affect the location, construction and operation of gathering and other pipelines needed to transport production to market, and the lack of new pipeline capacity can limit our ability to reach relevant markets for the sale of the commodities we produce.
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The transportation of natural gas and oil is also subject to extensive environmental regulation.  We refer you to “Other – Environmental Regulation” in Item 1 of Part I of this Annual Report and the risk factor “We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report for a discussion of the impact of environmental regulation on our business.
Other
We currently have no significant business activity outside of our E&P and Marketing segments.
Environmental Regulation
General.  Our operations are subject to environmental regulation in the jurisdictions in which we operate.  These laws and regulations require permits for drilling wells and the maintenance of bonding requirements to drill or operate wells, and also regulate the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the prevention and cleanup of pollutants and other matters.  We maintain insurance for clean-up costs in limited instances arising out of sudden and accidental events, but otherwise we may not be fully insured against all such risks.  Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief.  Certain laws and legal principles can make us liable for environmental damage to properties we previously owned, and although we generally require purchasers to assume that liability, there is no assurance that they will have sufficient funds should a liability arise.  Changes in environmental laws and regulations occur frequently, and any changes may result in more stringent and costly waste handling, storage, transportation, disposal or cleanup requirements.  We do not expect continued compliance with existing requirements to have a material adverse impact on us, but there can be no assurance that this will continue in the future.  We refer you to “Other – Environmental Regulation” in Item 1 of Part 1 of this Annual Report and the risk factor “We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report for a discussion of the impact of environmental regulation on our business.
The following is a summary of the more significant existing environmental and worker health and safety laws and regulations to which we are subject.
Generation and Disposal of Wastes.  The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment.  These persons include the current or former owner or operator of a site where the release occurred, as well as persons that transported or disposed, or arranged for the transportation or disposal of, the hazardous substances found at the site.  Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
The Resource Conservation and Recovery Act, as amended, or RCRA, generally does not regulate wastes generated by the exploration and production of natural gas and oil.  RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.”  However, legislative and regulatory initiatives have been considered from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements.  If such measures were to be enacted, it could have a significant impact on our operating costs.  Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.
The Clean Water Act, as amended, or CWA, and analogous state laws, impose restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into regulated waters.  Permits must be obtained to discharge pollutants to regulated waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges
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of reportable quantities of oil and other hazardous substances.  The EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges.  Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.
The Oil Pollution Act, as amended, or OPA, and regulations promulgated thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills into regulated waters.  A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located.  OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages.  Although liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation.  If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply.  Few defenses exist to the liability imposed by OPA.  OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.  Although oil accounted for only 4% of our total production in 2020 and 2019 and 2% in 2018, we expect this percentage to increase as we continue to develop our Southwest Appalachia assets.
We own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration for and production of natural gas and oil.  Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us and/or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of wastes was not under our control.  Under CERCLA, the CWA, RCRA and analogous state laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.
Air Emissions. The Clean Air Act, as amended, restricts emissions into the atmosphere.  Various activities we conduct as part of our operations, such as drilling, pumping and the use of vehicles, can result in emissions to the environment.  We must obtain permits, typically from local authorities, to conduct various regulated activities.  Federal and state governmental agencies are looking into the issues associated with methane and other emissions from oil and natural gas activities, and further regulation could increase our costs or restrict our ability to produce.  Although methane emissions are not currently regulated at the federal level, we are required to report emissions of various greenhouse gases, including methane.
Threatened and Endangered Species. The Endangered Species Act and comparable state laws protect species threatened with possible extinction.  Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining drilling and other permits and may include restrictions on road building and other activities in areas containing the affected species or their habitats.  Based on the species that have been identified to date, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our operations at this time.
Hydraulic Fracturing.  We utilize hydraulic fracturing in drilling wells as a means of maximizing their productivity.  It is an essential and common practice in the oil and gas industry used to stimulate the production of oil, natural gas, and associated liquids from dense and deep rock formations.  Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore.
In the past several years, there has been an increased focus on the environmental aspects of hydraulic fracturing, both in the United States and abroad.  In the United States, hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have started to assert regulatory authority over certain aspects of the process.  For example, the Environmental Protection Agency, or EPA, issued final rules effective as of October 15, 2012 that subject oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP programs.  In May 2016, the EPA finalized additional regulations to control methane and volatile organic compound (“VOC”) emissions from certain oil and gas equipment and operations.  In September 2018, the EPA issued proposed revisions to those regulations, which would reduce certain obligations thereunder.  In September 2020, the EPA finalized further amendments to the standards that removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. Several lawsuits were filed challenging these amendments, and the U.S. Court of Appeals for the D.C. Circuit ordered an administrative stay of these amendments shortly after they were finalized. Although the administrative stay was lifted in October 2020, which brought the amendments into effect, the amendments may be subject to reversal under a new presidential administration. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to
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comply with such requirements. The EPA also finalized pretreatment standards that would prohibit the indirect discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned treatment works.  Based on our current operations and practices, management believes such newly promulgated rules will not have a material adverse impact on our financial position, results of operations or cash flows but these matters are subject to inherent uncertainties and management’s view may change in the future.
In addition, there are certain governmental reviews either underway or proposed that focus on environmental aspects of hydraulic fracturing practices.  A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing.  For example, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals for fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters and disposal or storage of fracturing wastewater in unlined pits.  The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations.
Although the prior administration relaxed many regulations adopted in the latter part of the prior administration, that trend is likely to reverse under the new administration. In January 2021, the new administration announced a 60-day suspension of new oil and gas leasing and drilling permits on federal lands, and subsequently signed an Executive Order directing the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. In addition, some states in which we operate have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether.  In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.  In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells.
Increased regulation and attention given to the hydraulic fracturing process has led to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques.  Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil, natural gas, and associated liquids including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing.  The adoption of additional federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.  In addition, various officials and candidates at the federal, state and local levels, including some presidential candidates, have proposed banning hydraulic fracturing altogether. We refer you to the risk factor “We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report.
In addition, concerns have been raised about the potential for seismic activity to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities.  New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others.  We utilize third parties to dispose of waste water associated with our operations.  These third parties may operate injection wells and may be subject to regulatory restrictions relating to seismicity. 
Greenhouse Gas Emissions.  In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources.  Facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to meet “best available control technology” standards that will be established on a case-by case basis.  One of our subsidiaries operates compressor stations, which are facilities that are required to adhere to the PSD or Title V permit requirements.  EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
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The EPA also has adopted rules requiring the monitoring and reporting of greenhouse gas 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.  Although Congress from time to time has considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years.  In the absence of such federal climate legislation, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap-and-trade programs.  Most of these cap-and-trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved.  These reductions may cause the cost of allowances to escalate significantly over time.
The adoption and implementation of regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or install new equipment to reduce emissions of greenhouse gases associated with our operations.  In addition, these regulatory initiatives could drive down demand for our products by stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels that serve as a major source of greenhouse gas emissions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.  At the same time, new laws and regulations are prompting power producers to shift from coal to natural gas, which is increasing demand.
Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions (the “Paris Agreement”). The Paris Agreement entered into effect in November 2016 after more than 70 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement. In November 2019, the United States initiated the year-long process of formally withdrawing from the Paris Agreement, which resulted in an effective exit date of November 2020. However, in January 2021, the new administration announced that the U.S. would be rejoining the Paris Agreement. To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and gas industry, it could have an adverse effect on our business.
Employee Health and Safety. Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.
Canada. Our activities in Canada have, to date, been limited to certain geological and geophysical activities and now are subject to a moratorium.  If and when the moratorium ends and should we begin drilling and development activities in New Brunswick, we will be subject to federal, provincial and local environmental regulations.
Human Capital
We aim to provide a safe, healthy, respectful and fair workplace for all employees. We focus our actions to ensure our people are engaged and have the necessary tools and skills to be highly successful.
Southwestern Energy is committed to respect in the workplace. All employees participate in a program addressing workplace behavior and respect on an annual basis. Our Human Rights Policy, which is consistent with the International Labour Organization’s Declaration on Fundamental Principles and Rights at Work, underscores our commitment to our workforce and extends to vendors and contractors. All decisions regarding recruiting, hiring, training, evaluation, assignment, advancement and termination of employment are made without unlawful discrimination on the basis of race, color, national origin, ancestry, citizenship, sex, sexual orientation, gender identity or expression, religion, age, pregnancy, disability, present military status or veteran status, genetic information, marital status or any other factor that the law protects from employment discrimination. Compensation is based on several primary factors, including performance, skills, years of experience, time in position and market data. Through our SWomeN initiatives, we actively seek to retain and develop our female talent.
Southwestern Energy leaders, including senior management, are evaluated on and held accountable for the health, safety and environmental (“HSE”) performance of their teams. We include HSE considerations in every business decision we make and foster a true “ONE Team” culture, where our employees and contractors work together to uphold the same high safety standards.
Our response to COVID-19 in 2020 was driven by our long-standing commitment to safety. We formed a cross-functional Incident Response Team (“IRT”) on March 12, 2020 to manage and oversee prolonged company-wide response and mitigation efforts. The IRT met daily and provided real-time and weekly reports to senior management. Increased safeguards for employees
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and contractors were put in place, including mask requirements, social distancing, isolation and quarantine procedures, dynamic office closures and remote work protocols, rapid cleaning response protocols, temperature screenings at office locations, COVID-19 questionnaires and modified protocols as necessary based on continuous monitoring of relevant data and guidance. We have also provided additional benefits to our employees including COVID-19 testing for all office and field employees and their families, paid time off for non-exempt workers required to isolate or quarantine, and have made plans to make the COVID-19 vaccine available to employees and their families who want it.
Additional information about our commitment to human capital is available on our website and in other company filings available on our website. Note that the information on our website is not incorporated by reference into this filing.
As of December 31, 2020, we had 900 total employees, a decrease of 2% compared to year-end 2019.  None of our employees were covered by a collective bargaining agreement at year-end 2020.  We believe that our relationships with our employees are good.
Executive Officers of the Registrant
The following table shows certain information as of February 25, 2021 about our executive officers, as defined in Rule 3b-7 of the Securities Exchange Act of 1934:
NameAgeOfficer Position
William J. Way61President and Chief Executive Officer
Michael E. Hancock44Vice President and Chief Financial Officer (Interim)
Clayton A. Carrell55Executive Vice President and Chief Operating Officer
Derek W. Cutright43Senior Vice President – Southwest Appalachia
John P. Kelly50Senior Vice President – Northeast Appalachia
Quentin Dyson51Senior Vice President – Operations Services
Jason Kurtz50Vice President – Marketing and Transportation
Chris Lacy43Vice President, General Counsel and Secretary
Andy Huggins40Vice President – Business and Commercial Development
Carina Gillenwater45Vice President – Human Resources
Mr. Way was appointed Chief Executive Officer in January 2016.  Prior to that, he served as Chief Operating Officer since 2011, having also been appointed President in December 2014.  Prior to joining the Company, he was Senior Vice President, Americas of BG Group plc with responsibility for E&P, Midstream and LNG operations in the United States, Trinidad and Tobago, Chile, Bolivia, Canada and Argentina since 2007.
Mr. Hancock was appointed Vice President and Chief Financial Officer (Interim) in January 2021.  Prior to that, he served as Vice President Financial Planning and Analysis since 2017. Prior to that, he served in various finance and accounting leadership roles since joining the Company in February 2010.
Mr. Carrell was appointed Executive Vice President and Chief Operating Officer in December 2017.  Prior to joining the Company, he was Executive Vice President and Chief Operating Officer of EP Energy since 2012.
Mr. Cutright was appointed Senior Vice President of Southwest Appalachia Division in September 2019; he served as Vice President & General Manager of Southwest Appalachia since 2016. Prior to that, he served in various operational leadership roles since joining the Company in December 2008.
Mr. Kelly was appointed Senior Vice President of Northeast Appalachia in October 2018, having previously served as Senior Vice President – Fayetteville since in 2017. Prior to joining the Company, he was President and Chief Executive Officer of Cantera Energy since 2012.
Mr. Dyson was appointed Senior Vice President of Operations Services in April 2019. He held Vice President roles at EP Energy and BP before joining SWN in January 2018 as Vice President – Operations Services.
Mr. Kurtz was appointed Vice President of Marketing and Transportation in May 2011.  Prior to that, he served in various marketing roles since joining the Company in May 1997.
Mr. Lacy was appointed Vice President, General Counsel and Secretary in 2020. Prior to that, he served Associate General Counsel and Assistant Secretary and various other roles in the legal department since joining the Company in 2014.
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Mr. Huggins has served as Vice President of Commercial and Business Development since March 2018. Prior to that he served in various operational and technical leadership roles since joining the Company in 2007.
Mrs. Gillenwater was appointed Vice President of Human Resources in June 2018. Prior to joining the Company, she served as Global Vice President of Human Resources at Nabors Industries and Vice President of Human Resources at Smith International / Schlumberger Ltd.
There are no family relationships between any of the Company’s directors or executive officers.
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below include indicated terms in this Annual Report. All natural gas reserves reported in this Annual Report are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit.  All currency amounts are in U.S. dollars unless specified otherwise.
Acquisition of properties”  Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties. For additional information, see the SEC’s definition in Rule 4-10(a) (1) of Regulation S-X, a link for which is available at the SEC’s website.
Available reserves”  Estimates of the amounts of natural gas, oil and NGLs which the registrant can produce from current proved developed reserves using presently installed equipment under existing economic and operating conditions and an estimate of amounts that others can deliver to the registrant under long-term contracts or agreements on a per-day, per-month, or per-year basis.  For additional information, see the SEC’s definition in Item 1207(d) of Regulation S-K, a link for which is available at the SEC’s website.
Basis differential”  The difference in price for a commodity between a market index price and the price at a specified location.
Bbl”  One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf”  One billion cubic feet of natural gas.
Bcfe”  One billion cubic feet of natural gas equivalent. Determined using the ratio of one barrel of oil or natural gas liquids to six Mcf of natural gas.
Btu”  One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Deterministic estimate”  The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. For additional information, see the SEC’s definition in Rule 4-10(a) (5) of Regulation S-X, a link for which is available at the SEC’s website.
Developed oil and gas reserves”  Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered:
(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
For additional information, see the SEC’s definition in Rule 4-10(a) (6) of Regulation S-X, a link for which is available at the SEC’s website.
Development costs”  Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing natural gas, oil and NGLs. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
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(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)Provide improved recovery systems.
For additional information, see the SEC’s definition in Rule 4-10(a) (7) of Regulation S-X, a link for which is available at the SEC’s website.
Development project”  A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. For additional information, see the SEC’s definition in Rule 4-10(a) (8) of Regulation S-X, a link for which is available at the SEC’s website.
Development well”  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.  For additional information, see the SEC’s definition in Rule 4-10(a) (9) of Regulation S-X, a link for which is available at the SEC’s website.
E&P”  Exploration for and production of natural gas, oil and NGLs.
Economically producible”  The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities.  For additional information, see the SEC’s definition in Rule 4-10(a) (10) of Regulation S-X, a link for which is available at the SEC’s website.
Estimated ultimate recovery (EUR)”  Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.  For additional information, see the SEC’s definition in Rule 4-10(a) (11) of Regulation S-X, a link for which is available at the SEC’s website.
Exploitation”  The development of a reservoir to extract its natural gas and/or oil.
Exploratory well”  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.  For additional information, see the SEC’s definition in Rule 4-10(a) (13) of Regulation S-X, a link for which is available at the SEC’s website.
Field”  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. For additional information, see the SEC’s definition in Rule 4-10(a) (15) of Regulation S-X, a link for which is available at the SEC’s website.
Gross well or acre”  A well or acre in which the registrant owns a working interest. The number of gross wells is the total number of wells in which the registrant owns a working interest. For additional information, see the SEC’s definition in Item 1208(c)(1) of Regulation S-K, a link for which is available at the SEC’s website.
Gross working interest”  Gross working interest is the working interest in a given property plus the proportionate share of any royalty interest, including overriding royalty interest, associated with the working interest.
Henry Hub”  A common market pricing point for natural gas in the United States, located in Louisiana.
Hydraulic fracturing”  A process whereby fluids mixed with proppants are injected into a wellbore under pressure in order to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.
Infill drilling”  Drilling wells in between established producing wells to increase recovery of natural gas, oil and NGLs from a known reservoir.
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Internal Rate of Return” Discount rate at which net present value of cash flow is zero.
MBbls”  One thousand barrels of oil or other liquid hydrocarbons.
Mcf”  One thousand cubic feet of natural gas.
Mcfe”  One thousand cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six Mcf of natural gas.
MMBbls”  One million barrels of oil or other liquid hydrocarbons.
MMBtu”  One million British thermal units (Btus).
MMcf”  One million cubic feet of natural gas.
MMcfe”  One million cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six Mcf of natural gas.
Mont Belvieu”  A pricing point for North American NGLs.
Net acres”  The sum, for any area, of the products for each tract of the acres in that tract multiplied by the working interest in that tract.  For additional information, see the SEC’s definition in Item 1208(c)(2) of Regulation S-K, a link for which is available at the SEC’s website.
Net revenue interest”  Economic interest remaining after deducting all royalty interests, overriding royalty interests and other burdens from the working interest ownership.
Net well”  The sum, for all wells being discussed, of the working interests in those wells.  For additional information, see the SEC’s definition in Item 1208(c)(2) of Regulation S-K, a link for which is available at the SEC’s website.
NGLs”  Natural gas liquids (includes ethane, propane, butane, isobutane, pentane and pentanes plus).
NYMEX”  The New York Mercantile Exchange, on which spot and future contracts for natural gas and other commodities are traded.
Operating interest”  An interest in natural gas and oil that is burdened with the cost of development and operation of the property.
Overriding royalty interest”  A fractional, undivided interest or right to production or revenues, free of costs, of a lessee with respect to an oil or natural gas well, that overrides a working interest.
Play”  A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and natural gas reserves.
Pressure pumping spread”  All of the equipment needed to carry out a hydraulic fracturing job.
Probabilistic estimate”  The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. For additional information, see the SEC’s definition in Rule 4-10(a) (19) of Regulation S-X, a link for which is available at the SEC’s website.
Producing property”  A natural gas and oil property with existing production.
Productive wells”  Producing wells and wells mechanically capable of production. For additional information, see the SEC’s definition in Item 1208(c)(3) of Regulation S-K, a link for which is available at the SEC’s website.
Proppant”  Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.  In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used.  Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.
Proved developed producing”  Proved developed reserves that can be expected to be recovered from a reservoir that is currently producing through existing wells.
Proved developed reserves”  Proved natural gas, oil and NGLs that are also developed natural gas, oil and NGL reserves.
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Proved natural gas, oil and NGL reserves”   Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGLs that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Also referred to as “proved reserves.” For additional information, see the SEC’s definition in Rule 4-10(a) (22) of Regulation S-X, a link for which is available at the SEC’s website.
Proved reserves”  See “proved natural gas, oil and NGL reserves.”
Proved undeveloped reserves” or “PUD”  Proved natural gas, oil and NGL reserves that are also undeveloped natural gas, oil and NGL reserves.
PV-10”  When used with respect to natural gas, oil and NGL reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.  Also referred to as “present value.” After-tax PV-10 is also referred to as “standardized measure” and is net of future income tax expense.
Reserve life index”  The quotient resulting from dividing total reserves by annual production and typically expressed in years.
Reserve replacement ratio”  The sum of the estimated net proved reserves added through discoveries, extensions, infill drilling and acquisitions (which may include or exclude reserve revisions of previous estimates) for a specified period of time divided by production for that same period of time.
Reservoir”  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. For additional information, see the SEC’s definition in Rule 4-10(a) (27) of Regulation S-X, a link for which is available at the SEC’s website.
Royalty interest”  An interest in a natural gas and oil property entitling the owner to a share of natural gas, oil or NGL production free of production costs.
Tcfe”  One trillion cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six Mcf of natural gas.
Unconventional play”  A play in which the targeted reservoirs generally fall into one of three categories: tight sands, coal beds, or shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to produce economic flow rates.
Undeveloped acreage”  Those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves. For additional information, see the SEC’s definition in Item 1208(c)(4) of Regulation S-K, a link for which is available at the SEC’s website.
Undeveloped natural gas, oil and NGL reserves”  Undeveloped natural gas, oil and NGL reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Also referred to as “undeveloped reserves.”  For additional information, see the SEC’s definition in Rule 4-10(a) (31) of Regulation S-X, a link for which is available at the SEC’s website.
Undeveloped reserves”  See “undeveloped natural gas, oil and NGL reserves.”
Wells to sales”  Wells that have been placed on sales for the first time.
Working interest”  An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.
Workovers”  Operations on a producing well to restore or increase production.
WTI”  West Texas Intermediate, the benchmark oil price in the United States.
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ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this Annual Report.  Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.
Risks Related to Our Business
Natural gas, oil and NGL prices greatly affect our revenues and thus profits, liquidity, growth, ability to repay our debt and the value of our assets.
Our revenues, profitability, liquidity, growth, ability to repay our debt and the value of our assets greatly depend on prices for natural gas, oil and NGLs.  The markets for these commodities are volatile, and we expect that volatility to continue.  The prices of natural gas, oil and NGLs fluctuate in response to changes in supply and demand (global, regional and local), transportation costs, market uncertainty and other factors that are beyond our control.  Short- and long-term prices are subject to a myriad of factors such as:
overall demand, including the relative cost of competing sources of energy or fuel;
overall supply, including costs of production;
the availability, proximity and capacity of pipelines, other transportation facilities and gathering, processing and storage facilities;
regional basis differentials;
national and worldwide economic and political conditions;
weather conditions and seasonal trends;
government regulations, such as regulation of natural gas transportation and price controls;
inventory levels; and
market perceptions of future prices, whether due to the foregoing factors or others.
For example, in 2020 and 2019, the NYMEX settlement price for natural gas ranged from a low of $1.50 per MMBtu in July 2020 to a high of $3.64 per MMBtu in January 2019, and during this period our production was 79% and 78% natural gas, respectively.  NGLs represent a growing part of our business, and in the same period settlement prices for ethane and propane, our two principal NGL products, ranged from $5.25 per Bbl in March 2020 to $13.00 per Bbl in February 2019 and $12.32 per Bbl in March 2020 to $28.22 per Bbl in February 2019, respectively.  Although we hedge a large portion of our production against changing prices, derivatives do not protect all our future volumes, may result in our forgoing profit opportunities if markets rise and, for NGLs, are not always available for substantial periods into the future.  In 2020, we received $362 million, net of amounts we paid, in settlement of hedging arrangements. Moreover, when market expectations of future prices fall, as they did in 2020, the prices at which we can hedge are lower, reducing future revenue.
Lower natural gas, oil and NGL prices directly reduce our revenues and thus our operating income and cash flow.  Lower prices also reduce the projected profitability of further drilling and therefore are likely to reduce our drilling activity, which in turn means we will have fewer wells on production in the future.  Lower prices also reduce the value of our assets, both by a direct reduction in what the production would be worth and by making some properties uneconomic, resulting in non-cash impairments to the recorded value of our reserves and non-cash charges to earnings.  For example, in 2020, we reported non-cash impairment charges on our natural gas and oil properties totaling $2,825 million, primarily resulting from decreases in trailing 12-month average first-day-of-the-month natural gas prices throughout 2020, as compared to 2019, and the non-cash impairment of certain undeveloped leasehold interests.  Further non-cash impairments in future periods could occur if the trailing 12-month commodity prices decrease as compared to the average used in prior periods.
As of December 31, 2020, we had $3.2 billion of debt outstanding, consisting principally of senior notes maturing in various increments from 2022 to 2028, and $700 million of borrowings under our revolving credit facility, which matures in 2024.  At current commodity price levels, our net cash flow from operations is substantially higher than our interest obligations under this debt, but significant drops in realized prices could affect our ability to pay our current obligations or refinance our debt as it becomes due.
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Moreover, general industry conditions may make it difficult or costly to refinance increments of this debt as it matures.  Although our indentures do not contain significant covenants restricting our operations and other activities, our bank credit agreements contain financial covenants with which we must comply.  We refer you to the risk factor “Our current and future levels of indebtedness may adversely affect our results and limit our growth.”  Our inability to pay our current obligations or refinance our debt as it becomes due could have a material and adverse effect on our company.  The drop in prices since 2014 has reduced our revenues, profits and cash flow, caused us to record significant non-cash asset impairments and led us to reduce both our level of capital investing and our workforce, which has caused us to incur significant expenses relating to employee terminations.  Further price decreases could have similar consequences.  Similarly, a rise in prices to levels experienced before 2015 could significantly increase our revenues, profits and cash flow, which could be used to expand capital investments.
Significant capital investment is required to replace our reserves and conduct our business.
Our activities require substantial capital investment, not only to expand revenues but also because production from existing wells and thus revenues declines each year.  We intend to fund our future capital investing through net cash flows from operations, net of changes in working capital.  Our ability to generate operating cash flow is subject to many of the risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time.  Future cash flows from operations are subject to a number of risks and variables, such as the level of production from existing wells, prices of natural gas, oil and NGLs, our success in developing and producing new reserves and the other risk factors discussed herein.  If we are unable to fund capital investing, we could experience a further reduction in drilling new wells, acquiring new acreage and a loss of existing leased acreage, resulting in a decline in our cash flow from operations and natural gas, oil and NGL production and reserves. 
If we are not able to replace reserves, our production levels and thus our revenues and profits may decline.
Production levels from existing wells decline over time, and drilling new wells requires an inventory of leases and other rights with reserves that have not yet been drilled.  Our future success depends largely upon our ability to find, develop or acquire additional natural gas, oil and NGL reserves that are economically recoverable.  Unless we replace the reserves we produce through successful development, acquisition or exploration activities, our proved reserves and production will decline over time.  Identifying and exploiting new reserves requires significant capital investment and successful drilling operations.  Thus, our future natural gas, oil and NGL reserves and production, and therefore our revenues and profits, are highly dependent on our level of capital investments, our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
Our business depends on access to natural gas, oil and NGL transportation systems and facilities. Our commitments to assure availability of transportation could lead to substantial payments for capacity we do not use if production falls below projected levels.
The marketability of our natural gas, oil and NGL production depends in large part on the operation, availability, proximity, capacity and expansion of transportation systems and facilities owned by third parties.  For example, we can provide no assurance that sufficient transportation capacity will exist for expected production from Appalachia or that we will be able to obtain sufficient transportation capacity on economic terms.  During the past few years, several planned pipelines intended to service production in the Northeast United States have experienced delays in their in-service dates due to regulatory delays and litigation.
Producers compete by lowering their sales prices, resulting in the locational differences from NYMEX pricing.  Further, a lack of available capacity on transportation systems and facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties.  A lack of availability of these systems and facilities for an extended period of time could negatively affect our revenues.  In addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.
We have entered into gathering agreements in producing areas and multiple long-term firm transportation agreements relating to natural gas volumes from all our producing areas. As of December 31, 2020, our aggregate demand charge commitments under these firm transportation agreements and gathering agreements were approximately $8.5 billion. If our development programs fail to produce sufficient quantities of natural gas and ethane to fill the contracted capacity within expected timeframes, we would be required to pay demand or other charges for transportation on pipelines and gathering systems for capacity that we would not be fully utilizing. In those situations, which have occurred on a small scale at various times, we endeavor to sell or transfer that capacity to others or fill the excess capacity with production purchased from third parties. There can be no assurance that these measures will recoup the full cost of the unused transportation.
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Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging in the face of shifting market conditions, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our future growth rate.
We necessarily must consider future price and cost environments when deciding how much capital we are likely to have available from net cash flow and how best to allocate it.  Our current philosophy is to generally operate within cash flow from operations, net of changes in working capital, and to invest capital in a portfolio of projects that are projected to generate the highest combined Internal Rate of Return.  Volatility in prices and potential errors in estimating costs, reserves or timing of production of the reserves can result in uneconomic projects or economic projects generating less than anticipated returns.
Certain of our undeveloped assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.
Approximately 19,242 and 68,825 net acres of our Northeast Appalachia and Southwest Appalachia acreage, respectively, will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases.  Our ability to drill wells depends on a number of factors, including certain factors that are beyond our control, such as the ability to obtain permits on a timely basis or to compel landowners or lease holders on adjacent properties to cooperate.  Further, we may not have sufficient capital to drill all the wells necessary to hold the acreage without increasing our debt levels, or given price projections at the time, drilling may not be projected to achieve a sufficient return or be judged to be the best use of our capital.  To the extent we do not drill the wells, our rights to acreage can be lost.
Natural gas and oil drilling and producing and transportation operations can be hazardous and may expose us to liabilities.
Drilling and production operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks.  Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of our prospects. If any of these risks occurs, we could sustain substantial losses as a result of:
injury or loss of life;
severe damage to or destruction of property, natural resources or equipment;
pollution or other environmental damage;
clean-up responsibilities;
regulatory investigations and administrative, civil and criminal penalties; and
injunctions resulting in limitation or suspension of operations.
For our properties that we do not operate, we depend on the operator for operational and regulatory compliance.
We rely on third parties to transport our production to markets.  Their operations, and thus our ability to reach markets, are subject to all of the risks and operational hazards inherent in transporting natural gas and ethane and natural gas compression, including:
damages to pipelines, facilities and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism;
maintenance, repairs, mechanical or structural failures;
damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines;
disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack; and
leaks of natural gas or ethane as a result of the malfunction of equipment or facilities.
A material event such as those described above could expose us to liabilities, monetary penalties or interruptions in our business operations.  Although we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be
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assessed by a governmental authority.  Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.
We have made significant investments in oilfield service businesses, including our drilling rigs, water infrastructure and pressure pumping equipment, to lower costs and secure inputs for our operations and transportation for our production.  If our development and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations.  In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers.
We also have made investments to meet certain of our field services’ needs, including establishing our own drilling rig operation, water transportation system in Southwest Appalachia and pressure pumping capability. If our level of operations is reduced for a long period, we may not be able to recover these investments.  Further, our presence in these service and supply sectors, including competing with them for qualified personnel and supplies, may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.
Our business depends on the availability of water and the ability to dispose of water.  Limitations or restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of drilling and hydraulic fracturing processes.  Limitations or restrictions on our ability to secure sufficient amounts of water, or to dispose of or recycle water after use, could adversely impact our operations.  In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs.  Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection control wells.
In addition, concerns have been raised about the potential for seismic activity to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities.  New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others.  We utilize third parties to dispose of waste water associated with our operations.  These third parties may operate injection wells and may be subject to regulatory restrictions relating to seismicity.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of water necessary for hydraulic fracturing of wells or the disposal of water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our producing properties are concentrated in the Appalachian basin, making us vulnerable to risks associated with operating in limited geographic areas.
Our producing properties currently are geographically concentrated in the Appalachian basin in Pennsylvania, West Virginia and Ohio.  At December 31, 2020, nearly 100% of our total estimated proved reserves were attributable to properties located in the Appalachian basin.  As a result of this concentration in one primary region, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, state and local politics, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or interruption of the processing or transportation of natural gas, oil or NGLs.
Competition in the oil and natural gas industry is intense, making it more difficult for us to market natural gas, oil and NGLs, to secure trained personnel and appropriate services, to obtain additional properties and to raise capital.
Our cost of operations is highly dependent on third-party services, and competition for these services can be significant, especially in times when commodity prices are rising.  Similarly, we compete for trained, qualified personnel, and in times of lower prices for the commodities we produce, we and other companies with similar production profiles may not be able to attract and retain this talent.  Our ability to acquire and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas, oil and NGLs and securing trained personnel.  Also, there is substantial competition for capital available for investment in the oil and gas industry.  Certain of our competitors may possess and employ financial, technical and personnel resources greater than ours.  Those companies may be able to pay more for personnel, property and services and to attract capital at lower rates.  This may become more likely if prices for oil and NGLs increase faster than prices for natural gas, as natural gas comprises a greater percentage of our overall production than it does for most of the companies with whom we compete for talent.
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We may be unable to dispose of assets on attractive terms, and may be required to retain liabilities for certain matters.
Various factors could materially affect our ability to dispose of assets if and when we decide to do so, including the availability of purchasers willing to purchase the assets at prices acceptable to us, particularly in times of reduced and volatile commodity prices.  Sellers typically retain liabilities for certain matters.  The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material.  Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets.  As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.
The elimination of certain key U.S. federal income tax deductions currently available to oil and natural gas exploration and production companies may be proposed in the future.  These changes may include, among other proposals:
repeal of the percentage depletion allowance for natural gas and oil properties;
elimination of current deductions for intangible drilling and development costs; and
extension of the amortization period for certain geological and geophysical expenditures.
The passage of these or any similar changes in U.S. federal income tax laws to eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development could have an adverse effect on our financial position, results of operations and cash flows.
In March 2020, the Coronavirus Aid, Relief, and Economic Security Act (“CARES” Act) was introduced to stabilize the economy during the coronavirus pandemic. The CARES Act temporarily suspends and modifies certain tax laws established by the 2017 tax reform law known as the Tax Cuts and Jobs Act, including, but not limited to, modifications to net operating loss limitations, business interest limitations and alternative minimum tax.
We may experience adverse or unforeseen tax consequences due to further developments affecting our deferred tax assets that could significantly affect our results.
Deferred tax assets, including net operating loss carryforwards, represent future savings of taxes that would otherwise be paid in cash.  At December 31, 2020, we had substantial amounts of net operating loss carryforwards for U.S. federal and state income tax purposes.  Our ability to utilize the deferred tax assets is dependent on the amount of future pre-tax income that we are able to generate through our operations or sale of assets. If management concludes that it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized, a valuation allowance will be recognized in the period that this conclusion is reached. In addition, limitations may exist upon use of these carryforwards in the event that a change in control of the Company occurs.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities as well as processing of revenues and payments.  We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, analyze seismic and drilling information, conduct reservoir modeling and reserves estimation, communicate with employees and business associates, perform compliance reporting and in many other activities related to our business.  Our vendors, service providers, purchasers of our production and financial institutions are also dependent on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased.  Our technologies, systems, networks, and those of our business associates may become the target of cyber-attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release of confidential or protected information, corruption of data or other disruptions of our business operations.  In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
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A cyber-attack involving our information systems and related infrastructure, or that of companies with which we deal, could disrupt our business and negatively impact our operations in a variety of ways, including:
unauthorized access to seismic data, reserves information, strategic information or other sensitive or proprietary information could have a negative impact on our ability to compete for natural gas and oil resources;
unauthorized access to personal identifying information of property lessors, working interest partners, employees and vendors, which could expose us to allegations that we did not sufficiently protect that information;
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;
a cyber-attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt our major development projects; and
a cyber-attack on a third party gathering, pipeline or rail service provider could delay or prevent us from marketing our production, resulting in a loss of revenues.
These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability, which could have a material adverse effect on our financial condition, results of operations or cash flows.
To date we have not experienced any material losses or interruptions relating to cyber-attacks; however, there can be no assurance that we will not suffer such losses in the future.  As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets.  Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations.
The widespread outbreak of an illness, pandemic (such as COVID-19) or any other public health crisis may have material adverse effects on our financial position, results of operations or cash flows.
In December 2019, COVID-19 was reported to have surfaced in China. The spread of this virus has caused business disruptions beginning in January 2020, including disruptions in the oil and natural gas industry. In March 2020, the World Health Organization declared the outbreak of COVID-19 to be a pandemic, and the U.S. economy began to experience pronounced effects. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for natural gas, oil, NGLs and other products derived from these commodities, the availability of personnel, equipment and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel, transports and operations. There is uncertainty around the extent and duration of the disruption. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while the Company expects this matter will likely continue to impact its operations, the degree of the adverse financial impact cannot be reasonably estimated at this time.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change, emissions, hydraulic fracturing, seismicity, oil spills and explosions of transmission lines, may lead to regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.  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
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courts.  Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business. In addition, various officials and candidates at the federal, state and local levels, including some presidential candidates, have proposed banning hydraulic fracturing altogether.
Judicial decisions can affect our rights and obligations.
Our ability to develop gas, oil and NGLs depends on the leases and other mineral rights we acquire and the rights of owners of nearby properties.  We operate in areas where judicial decisions have not yet definitively interpreted various contractual provisions or addressed relevant aspects of property rights, nuisance and other matters that could be the source of claims against us as a developer or operator of properties.  Although we plan our activities according to our expectations of these unresolved areas, based on decisions on similar issues in these jurisdictions and decisions from courts in other states that have addressed them, courts could resolve issues in ways that increase our liabilities or otherwise restrict or add costs to our operations.
Common stockholders will be diluted if additional shares are issued.
We endeavor to create value for our stockholders on a per share basis. From time to time we have issued stock to raise capital for our business, including significant offerings of new shares in 2015, 2016 and 2020.  We also issue restricted stock, options and performance share units to our employees and directors as part of their compensation.  In addition, we may issue additional shares of common stock, additional notes or other securities or debt convertible into common stock, to extend maturities or fund capital expenditures.  If we issue additional shares of our common stock in the future, it may have a dilutive effect on our current outstanding stockholders.
Anti-takeover provisions in our organizational documents and under Delaware law may impede or discourage a takeover, which could cause the market price of our common stock to decline.
We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders, which, under certain circumstances, could reduce the market price of our common stock.  In addition, protective provisions in our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws or the implementation by our Board of Directors of a stockholder rights plan that could deter a takeover.
Risks Related to our Indebtedness and Financing Abilities
A downgrade in our credit rating could negatively impact our cost of and ability to access capital and our liquidity.
Actual or anticipated changes or downgrades in our credit ratings, including any announcement that our ratings are under review for a downgrade, could impact our ability to access debt markets in the future to refinance existing debt or obtain additional funds, affect the market value of our senior notes and increase our borrowing costs.  Such ratings are limited in scope, and do not address all material risks relating to us, but rather reflect only the view of each rating agency of the likelihood we will be able to repay our debt at the time the rating is issued.  An explanation of the significance of each rating may be obtained from the applicable rating agency.  As of February 25, 2021, our long-term issuer ratings were Ba2 by Moody’s, BB- by Standard and Poor’s and BB by Fitch Investor Services.  There can be no assurance that such credit ratings will remain in effect for any given period of time or that such ratings will not be lowered, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment, circumstances so warrant.
Actual downgrades in our credit ratings may also impact our interest costs and liquidity.  The interest rates under certain of our senior notes increases as credit ratings fall. Many of our existing commercial contracts contain, and future commercial contracts may contain, provisions permitting the counterparty to require increased security upon the occurrence of a downgrade in our credit rating.  Providing additional security, such as posting letters of credit, could reduce our available cash or our liquidity under our revolving credit facility for other purposes.  We had $233 million of letters of credit outstanding at December 31, 2020.  The amount of additional financial assurance would depend on the severity of the downgrade from the credit rating agencies, and a downgrade could result in a decrease in our liquidity.
Our current and future levels of indebtedness may adversely affect our results and limit our growth.
At December 31, 2020, we had long-term indebtedness of $3.2 billion.  The terms of the indentures governing our outstanding senior notes, our credit facilities, and the lease agreements relating to our drilling rigs, other equipment and headquarters building, which we collectively refer to as our “financing agreements,” impose restrictions on our ability and, in
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some cases, the ability of our subsidiaries to take a number of actions that we may otherwise desire to take, which may include, without limitation, one or more of the following:
incurring additional debt;
redeeming stock or redeeming certain debt;
making certain investments;
creating liens on our assets; and
selling assets.
The revolving credit facility we entered into in April 2018, as amended (our “2018 credit facility”), contains customary representations, warranties and covenants including, among others, the following covenants:
a prohibition against incurring debt, subject to permitted exceptions;
a restriction on creating liens on assets, subject to permitted exceptions;
restrictions on mergers and asset dispositions;
restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business; and
maintenance of the following financial covenants, commencing with the fiscal quarter ended June 30, 2018:
1.Minimum current ratio of no less than 1.00 to 1.00, whereby current ratio is defined as the Company’s consolidated current assets (including unused commitments under the credit agreement, but excluding non-cash derivative assets) to consolidated current liabilities (excluding non-cash derivative obligations and current maturities of long-term debt).
2.Maximum total net leverage ratio of no greater than 4.00 to 1.00 subsequent to June 30, 2020.  Total net leverage ratio is defined as total debt less cash on hand (up to the lesser of 10% of credit limit or $150 million) divided by consolidated EBITDAX for the last four consecutive quarters.  For purposes of calculating consolidated EBITDAX, the Company can include the Montage consolidated EBITDAX prior to the merger for the same rolling twelve-month period. EBITDAX, as defined in our revolving credit facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs. 
In conjunction with the October 2020 redetermination process, the Company entered into an amendment to the credit agreement governing the 2018 credit facility to, among other matters:
limit the Company's unrestricted cash and cash equivalents to $200 million when loans under the 2018 credit facility are outstanding, subject to certain exceptions; and
increase the applicable rate by 25 basis points on loans outstanding under the 2018 credit facility.
As of December 31, 2020, we were in compliance with all of the covenants of our revolving credit facility in all material respects. Our ability to comply with these financial covenants depends in part on the success of our development program and upon factors beyond our control, such as the market prices for natural gas, oil and NGLs.
Our level of indebtedness and off-balance sheet obligations, and the covenants contained in our financing agreements, could have important consequences for our operations, including:
requiring us to dedicate a substantial portion of our cash flow from operations to required payments, thereby reducing the availability of cash flow for working capital, capital investing and other general business activities;
limiting our ability to obtain additional financing in the future for working capital, capital investing, acquisitions and general corporate and other activities;
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
detracting from our ability to successfully withstand a downturn in our business or the economy generally.
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Any significant reduction in the borrowing base under our revolving credit facility may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.
The amount we may borrow under our revolving credit facility is capped at the lower of the total of our bank commitments and a “borrowing base” determined from time to time by the lenders based on our reserves, market conditions and other factors.  As of December 31, 2020, the borrowing base and total aggregate commitments were $2.0 billion, which was most recently reaffirmed as of November 2020.  The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on our natural gas, oil and NGL reserves and other factors.  As of December 31, 2020, we had $700 million of outstanding borrowings under our revolving credit facility, and we expect to borrow under that facility in the future.  As of December 31, 2020, we had $233 million of letters of credit issued under the credit facility and unused borrowing capacity was approximately $1.1 billion which exceeds our currently modeled needs.  Any significant reduction in our borrowing base as a result of borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow.  Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination or other reasons, we would be required to repay the excess within a brief period.  We may not have sufficient funds to make such repayments.  If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets.  Any such sale could have a material adverse effect on our business and financial results.
Our ability to comply with the covenants and other restrictions in our financing agreements may be affected by events beyond our control, including prevailing economic and financial conditions.
Failure to comply with the covenants and other restrictions could lead to an event of default and the acceleration of our obligations under our senior notes, credit facilities or other financing agreements, and in the case of the lease agreements for drilling rigs, compressors and pressure pumping equipment, loss of use of the equipment.  In particular, the occurrence of risks identified elsewhere in this section, such as declines in commodity prices, increases in basis differentials and inability to access markets, could reduce our profits and thus the cash we have to fulfill our financial obligations.  If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering.  We cannot assure that we will be able to generate sufficient cash flow to pay the interest on our debt, to meet our lease obligations, or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt or obligations.  The terms of our financing agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing.  We cannot assure that any such proposed offering, refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.
Risks Related to Governmental Regulation
Climate change legislation or regulations governing the emissions of greenhouse gases could result in increased operating costs and reduce demand for the natural gas, oil and NGLs we produce, and concern in financial and investment markets over greenhouse gasses and fossil fuel production could adversely affect our access to capital and the price of our common stock.
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources.  Facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis.  EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
The EPA also has adopted rules requiring the monitoring and reporting of greenhouse gas 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.  In May 2016, the EPA finalized additional regulations to control methane and volatile organic compound emissions from certain oil and gas equipment and operations.  However, in September 2020, the EPA finalized further amendments to the standards that removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. Several lawsuits were filed challenging these amendments, and the U.S. Court of Appeals for the D.C. Circuit ordered an administrative stay of these amendments shortly after they were finalized. Although the administrative stay was lifted in October 2020, which brought the amendments into effect, the amendments may be subject to reversal under a new presidential administration.
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Although Congress from time to time has considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years.  In the absence of such federal climate legislation, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap-and-trade programs.  Most of these cap-and-trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved.  These reductions may cause the cost of allowances to escalate significantly over time.
The adoption and implementation of regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or install new equipment to reduce emissions of greenhouse gases associated with our operations.  In addition, these regulatory initiatives could drive down demand for our products by stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels that serve as a major source of greenhouse gas emissions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.  At the same time, new laws and regulations are prompting power producers to shift from coal to natural gas, which is increasing demand.
In December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions (the “Paris Agreement”). The Paris Agreement entered into force in November 2016 after more than 70 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement. In November 2019, the United States formally initiated the process for withdrawing from the Paris Agreement, which resulted in an effective exit date of November 2020. However, in January 2021, the new administration announced that the United States intends to rejoin the Paris Agreement. To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and natural gas industry, or that investors insist on compliance regardless of legal requirements, it could have an adverse effect on our business.
We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our development and production operations and the transportation of our products to market are subject to complex and stringent federal, state and local laws and regulations, including those governing environmental protection, the occupational health and safety aspects of our operations, the discharge of materials into the environment, and the protection of certain plant and animal species.  See “Other – Environmental Regulation” in Item 1 of Part I of this Annual Report for a description of the laws and regulations that affect us.  These laws and regulations require us, our service providers and our customers to obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities.  Environmental regulations may restrict the types, quantities and concentration of materials that may be released into the environment in connection with drilling and production activities, limit or prohibit drilling or transportation activities on certain lands lying within wilderness, wetlands, archeological sites and other protected areas, and impose substantial liabilities for pollution resulting from our operations and those of our service providers and customers.  Moreover, we or they may experience delays in obtaining or be unable to obtain required permits, including as a result of government shutdowns, which may delay or interrupt our or their operations and limit our growth and revenues. In addition, various officials and candidates at the federal, state and local levels, including some presidential candidates, have proposed banning hydraulic fracturing altogether.
Failure to comply with laws and regulations can trigger a variety of administrative, civil and criminal enforcement measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, or the issuance of orders or judgments limiting or enjoining future operations.  Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our own actions.  Moreover, our costs of compliance with existing laws could be substantial and may increase or unforeseen liabilities could be imposed if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.  If we are not able to recover the increased costs through insurance or increased revenues, our business, financial condition, results of operations and cash flows could be adversely affected.
Risks Related to Financial Markets and Uncertainties
Market views of our industry generally can affect our stock price.
Factors described elsewhere, including views regarding future commodity prices, regulation and climate change, can affect the amount investors choose to invest in our industry generally. Recent years have seen a significant reduction in overall investment in exploration and production companies, resulting in a drop in individual companies’ stock prices. Separate from actual and possible governmental action, certain financial institutions have announced policies to cease investing or to divest
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investments in companies, such as ours, that produce fossil fuels, and some banks have announced they no longer will lend to companies in this sector.  To date these represent small fractions of overall sources of equity and debt, but that fraction could grow and thus affect our access to capital.  Moreover, some equity investors are expressing concern over these matters and may prompt companies in our industry to adopt more costly practices even absent governmental action.  Although we believe our practices result in low emission rates for methane and other greenhouse gases as compared to others in our industry, complying with investor sentiment may require modifications to our practices, which could increase our capital and operating expenses.
Volatility in the financial markets or in global economic factors could adversely impact our business and financial condition.
Our business may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are reduced energy demand and lower commodity prices, including due to the possible impact of the coronavirus (COVID-19), increased difficulty in collecting amounts owed to us by our customers, reduced access to credit markets and the risks related to the discontinuation of LIBOR and other reference rates, including increased expenses and litigation and the effectiveness of interest rate hedge strategies.  Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing.  If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
Any changes in U.S. trade policy could trigger retaliatory actions by affected countries, resulting in “trade wars,” in increased costs for materials necessary for our industry along with other goods imported into the United States, which may reduce customer demand for these products if the parties having to pay those tariffs increase their prices, or in trading partners limiting their trade with the United States.  If these consequences are realized, the volume of economic activity in the United States, including growth in sectors that utilize our products, may be materially reduced along with a reduction in the potential export of our products.  Such a reduction may materially and adversely affect commodity prices, our sales and our business.
Risks Related to the Ability of our Hedging Activities to Adequately Manage our Exposure to Commodity and Financial Risk
Our proved natural gas, oil and NGL reserves are estimates that include uncertainties.  Any material changes to these uncertainties or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated.
As described in more detail under “Critical Accounting Policies and Estimates – Natural Gas and Oil Properties” in Item 7 of Part II of this Annual Report, our reserve data represents the estimates of our reservoir engineers made under the supervision of our management, and our reserve estimates are audited each year by Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm.  Reserve engineering is a subjective process of estimating underground accumulations of natural gas, oil and NGLs that cannot be measured in an exact manner.  The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates.  The process relies on interpretations of available geologic, geophysical, engineering and production data.  The extent, quality and reliability of this technical data can vary.  The process also requires certain economic assumptions, some of which are mandated by the SEC, such as using historic natural gas, oil and NGL prices rather than future projections.  Additional assumptions include drilling and operating expenses, capital investing, taxes and availability of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data.
Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate.  Accordingly, initial reserve estimates often vary from the quantities of natural gas, oil and NGLs that are ultimately recovered, and such variances may be material.  Any significant variance could reduce the estimated quantities and present value of our reserves.
You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas, oil and NGL reserves.  In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the preceding 12-month average natural gas, oil and NGL index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties.  Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate.  In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
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Our commodity price risk management and measurement systems and economic hedging activities might not be effective and could increase the volatility of our results.
We currently seek to hedge the price of a significant portion of our estimated production through swaps, collars, floors and other derivative instruments.  The systems we use to quantify commodity price risk associated with our businesses might not always be effective.  Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified.  Furthermore, no single hedging arrangement can adequately address all risks present in a given contract.  For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk.  Therefore, unhedged risks will always continue to exist.
Our use of derivatives, through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results.  Changes in the fair values (gains and losses) of derivatives that qualify as hedges under GAAP to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income.  This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period.  To the extent we cap or lock prices at specific levels, we would also forgo the ability to realize the higher revenues that would be realized should prices increase.
The impact of changes in market prices for natural gas, oil and NGLs on the average prices paid or received by us may be reduced based on the level of our hedging activities.  These hedging arrangements may limit or enhance our margins if the market prices for oil, natural gas or NGLs were to change substantially from the price established by the hedges.  In addition, our hedging arrangements expose us to the risk of financial loss if our production volumes are less than expected.
The implementation of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, including us, which participate in that market.  The Dodd-Frank Act requires the CFTC, the SEC, and other regulatory authorities to promulgate rules and regulations implementing the Dodd-Frank Act.  Although the CFTC has finalized most of its regulations under the Dodd-Frank Act, it continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings.  As a result, it is not possible at this time to predict the ultimate effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations may increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives as a result of the Dodd-Frank Act and the regulations thereunder, 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 capital investing.
In January 2020, the CFTC proposed new amended regulations that would place federal limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In 2016, the CFTC finalized a companion rule on aggregation of positions among entities under common ownership or control.  If finalized, the position limits rule may have an impact on our ability to hedge our exposure to certain enumerated commodities.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and mandatory trading on designated contract markets or swap execution facilities.  The CFTC may designate additional classes of swaps as subject to the mandatory clearing requirement in the future, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing.  The CFTC and prudential banking regulators also adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties.  The margin requirements are currently effective with respect to certain market participants and will be phased in over time with respect to other market participants, based on the level of an entity’s swaps activity.  We expect to qualify for and rely upon an end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge our commercial risks.  We also should qualify for an exception from the uncleared swaps margin requirements.  However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirement to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
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Risks Related to the Merger
Southwestern may not achieve the anticipated benefits of the Merger, and the Merger may disrupt its current plans or operations.
The success of the Merger will depend, in part, on Southwestern’s ability to realize the anticipated benefits and cost savings from combining Southwestern’s and Montage’s businesses, and there can be no assurance that Southwestern and Montage will be able to successfully integrate or otherwise realize the anticipated benefits of the Merger. Difficulties in integrating Southwestern and Montage may result in the combined company performing differently than expected, in operational challenges, or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:
the inability to successfully integrate Montage in a manner that permits the achievement of full revenue, expected cash flows and cost savings anticipated from the Merger;
not realizing anticipated operating synergies;
integrating personnel from the two companies and the loss of key employees;
potential unknown liabilities and unforeseen expenses or delays associated with and following the completion of the Merger;
integrating relationships with customers, vendors and business partners;
performance shortfalls as a result of the diversion of management’s attention caused by completing the Merger and integrating Montage’s operations; and
the disruption of, or the loss of momentum in, Southwestern’s ongoing business or inconsistencies in standards, controls, procedures and policies.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 2.  PROPERTIES
The summary of our oil and natural gas reserves as of fiscal year-end 2020 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed “2020 Proved Reserves by Category and Summary Operating Data” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Annual Report and incorporated by reference into this Item 2. 
The information regarding our proved undeveloped reserves required by Item 1203 of Regulation S-K is included under the heading “Proved Undeveloped Reserves” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Annual Report.
The information regarding delivery commitments required by Item 1207 of Regulation S-K is included under the heading “Sales, Delivery Commitments and Customers” in the “Business – Exploration and Production – Our Operations” in Item 1 of this Annual Report and incorporated by reference into this Item 2.  For additional information about our natural gas and oil operations, we refer you to “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report.  For information concerning capital investments, we refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Investing.”  We also refer you to Item 6, “Selected Financial Data” in Part II of this Annual Report for information concerning natural gas, oil and NGLs produced.
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The information regarding natural gas and oil properties, wells, operations and acreage required by Item 1208 of Regulation S-K is set forth below:
Leasehold acreage as of December 31, 2020
UndevelopedDevelopedTotal
GrossNetGrossNetGrossNet
Northeast Appalachia107,465 89,086 134,449 128,210 241,914 217,296 
Southwest Appalachia610,969 425,702 186,390 146,220 797,359 571,922 
Other:
US – Other Exploration9,652 6,329 5,034 2,263 14,686 8,592 
US – Sand Wash Basin5,898 3,435 14,977 9,974 20,875 13,409 
Total US733,984 524,552 340,850 286,667 1,074,834 811,219 
Canada – New Brunswick (1)
2,518,519 2,518,519 — — 2,518,519 2,518,519 
3,252,503 3,043,071 340,850 286,667 3,593,353 3,329,738 
(1)The exploration licenses for 2,518,519 net acres in New Brunswick, Canada, have been subject to a moratorium since 2015. These licenses expire in March 2021, and we fully impaired our investment in New Brunswick in 2016. We are currently working with Canadian officials to extend our licenses, although we cannot assure that the licenses will be extended past March 2021.
Lease Expirations
The following table summarizes the leasehold acreage expiring over the next three years, assuming successful wells are not drilled to develop the acreage and leases are not extended:
For the years ended December 31,
Net acreage expiring:202120222023
Northeast Appalachia5,861 6,460 6,921 
Southwest Appalachia (1)
36,690 20,149 11,986 
Other:
US – Other Exploration5,683 646 — 
US – Sand Wash Basin3,435 — — 
Canada – New Brunswick (2)
2,518,519 — — 
(1)The leasehold acreage expiring includes 8,907 acres acquired through the Montage Merger that are subject to annual extension options at our sole discretion. Excluding this acreage, of the remaining leasehold acreage expiring, 17,460 net acres in 2021, 6,173 net acres in 2022 and 5,573 net acres in 2023 can be extended for an average 4.9 years.
(2)Exploration licenses were extended through March 2021 but have been subject to a moratorium since 2015. We are currently working with Canadian officials to extend our licenses, although we cannot assure that the licenses will be extended past March 2021. We impaired their value to $0 in 2016.
Producing wells as of December 31, 2020
Natural GasOilTotalGross Wells Operated
GrossNetGrossNetGrossNet
Northeast Appalachia744 668 — — 744 668 677 
Southwest Appalachia1,796 1,487 37 34 1,833 1,521 1,670 
Other14 11 14 
2,548 2,160 43 40 2,591 2,200 2,361 

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The information regarding drilling and other exploratory and development activities required by Item 1205 of Regulation S-K is set forth below:
Exploratory
Productive WellsDry WellsTotal
YearGrossNetGrossNetGrossNet
2020      
Northeast Appalachia— — — — — — 
Southwest Appalachia— — — — — — 
Other— — — — — — 
Total—      
2019      
Northeast Appalachia— — — — — — 
Southwest Appalachia— — — — — — 
Other— — — — — — 
Total— — — — — — 
2018      
Northeast Appalachia— — — — — — 
Southwest Appalachia— — — — — — 
Fayetteville Shale (1)
— — — — — — 
Other— — — — — — 
Total— — — — — — 
(1)The Fayetteville Shale E&P assets were sold in December 2018.
Development
Productive WellsDry WellsTotal
YearGrossNetGrossNetGrossNet
2020      
Northeast Appalachia45.0 44.4 — — 45.0 44.4 
Southwest Appalachia55.0 44.6 — — 55.0 44.6 
Total100.0 89.0 — — 100.0 89.0 
2019      
Northeast Appalachia44.0 41.7 — — 44.0 41.7 
Southwest Appalachia69.0 53.5 — — 69.0 53.5 
Total113.0 95.2 — — 113.0 95.2 
2018      
Northeast Appalachia60.0 59.5 — — 60.0 59.5 
Southwest Appalachia76.0 59.3 — — 76.0 59.3 
Fayetteville Shale (1)
2.0 1.8 — — 2.0 1.8 
Total138.0 120.6 — — 138.0 120.6 
(1)The Fayetteville Shale E&P assets were sold in December 2018.
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The following table presents the information regarding our present activities required by Item 1206 of Regulation S-K:
Wells in progress as of December 31, 2020
GrossNet
Drilling:  
Northeast Appalachia16.0 15.6 
Southwest Appalachia14.0 13.6 
Total30.0 29.2 
Completing:  
Northeast Appalachia10.0 10.0 
Southwest Appalachia2.0 1.8 
Total12.0 11.8 
Drilling & Completing:  
Northeast Appalachia26.0 25.6 
Southwest Appalachia16.0 15.4 
Total42.0 41.0 

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The information regarding oil and gas production, production prices and production costs required by Item 1204 of Regulation S-K is set forth below:
Production, Average Sales Price and Average Production Cost
For the years ended December 31,
202020192018
Natural Gas
Production (Bcf):
Northeast Appalachia473 459 459 
Southwest Appalachia221 150 105 
Fayetteville Shale (1)
— — 243 
Total694 609 807 
Average realized gas price, excluding derivatives ($/Mcf):
Northeast Appalachia$1.37 $2.10 $2.54 
Southwest Appalachia$1.27 $1.62 $2.58 
Fayetteville Shale (1)
$— $— $2.21 
Total$1.34 $1.98 $2.45 
Average realized gas price, including derivatives ($/Mcf):
$1.70 $2.18 $2.35 
Oil
Production (MBbls):
Southwest Appalachia5,124 4,673 3,355 
Other17 23 52 
Total5,141 4,696 3,407 
Average realized oil price, excluding derivatives ($/Bbl):
Southwest Appalachia$29.18 $46.86 $56.71 
Other$37.24 $53.66 $62.01 
Total$29.20 $46.90 $56.79 
Average realized oil price, including derivatives ($/Bbl):
$46.91 $49.56 $56.07 
NGL
Production (MBbls):
Southwest Appalachia25,923 23,611 19,679 
Other27 
Total25,927 23,620 19,706 
Average realized NGL price, excluding derivatives ($/Bbl):
Southwest Appalachia$10.24 $11.59 $17.89 
Other$11.50 $7.61 $28.12 
Total$10.24 $11.59 $17.91 
Average realized NGL price, including derivatives ($/Bbl)
$11.15 $13.64 $17.23 
Total Production (Bcfe)
Northeast Appalachia473 459 459 
Southwest Appalachia407 319 243 
Fayetteville Shale (1)
— — 243 
Other— — 
Total (2)
880 778 946 
Lease Operating Expense
Cost per Mcfe, excluding ad valorem and severance taxes:
Northeast Appalachia$0.86 $0.85 $0.81 
Southwest Appalachia$1.00 $1.02 $1.08 
Fayetteville Shale (1)
$— $— $0.98 
Total$0.93 $0.92 $0.93 
(1)The Fayetteville Shale E&P assets and associated reserves were sold in December 2018.
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(2)Approximately 878 Bcfe, 776 Bcfe and 698 Bcfe for the years ended December 31, 2020, 2019 and 2018, respectively, were produced from the Marcellus Shale formation. Approximately 243 Bcfe for the year ended December 31, 2018 was produced from the Fayetteville Shale.
During 2020, we were required to file Form 23, “Annual Survey of Domestic Oil and Gas Reserves,” with the U.S. Department of Energy.  The basis for reporting reserves on Form 23 is not comparable to the reserve data included in “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report.  The primary differences are that Form 23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties of which we are the operator.
Title to Properties
We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry.  Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties.  Prior to acquiring undeveloped properties, we endeavor to perform a title investigation that is thorough but less vigorous than that we endeavor to conduct prior to drilling, which is consistent with standard practice in the oil and natural gas industry.  Generally, before we commence drilling operations on properties that we operate, we conduct a title examination and perform curative work with respect to significant defects that we identify.  We believe that we have performed title review with respect to substantially all of our active properties that we operate.
ITEM 3.  LEGAL PROCEEDINGS 
We are subject to various litigation, claims and proceedings that arise in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic incidents, pollution, contamination, encroachment on others’ property or nuisance.  We accrue for such items when a liability is both probable and the amount can be reasonably estimated.  It is not possible at this time to estimate the amount of any additional loss, or range of loss that is reasonably possible, but based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows, for the period in which the effect of that outcome becomes reasonably estimable.  Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.  If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. 
We are also subject to laws and regulations relating to the protection of the environment.  Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated.  Management believes any future remediation or other compliance related costs will not have a material effect on our financial position or results of operations. 
See “Litigation” in Note 10 to the consolidated financial statements included in this Annual Report for further details on our current legal proceedings.
ITEM 4.  MINE SAFETY DISCLOSURES
Our sand mining facility in Arkansas, which previously supported our Fayetteville Shale operations, is subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977.  Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Annual Report.
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PART II
ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange (the “NYSE”) under the symbol “SWN.”  On February 25, 2021, the closing price of our common stock trading under the symbol “SWN” was $4.22 and we had 2,269 stockholders of record.
We currently do not pay dividends on our common stock, and we do not anticipate paying any cash dividends in the foreseeable future. All decisions regarding the declaration and payment of dividends and stock repurchases are at the discretion of our Board of Directors and will be evaluated regularly in light of our financial condition, earnings, growth prospects, funding requirements, applicable law and any other factors that our Board of Directors deems relevant.
Information required by Item 5 of Part II with respect to equity compensation plans will be included under the caption Equity Compensation Plans in our Proxy Statement relating to our 2021 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before May 18, 2021, and is incorporated herein by reference.
Issuer Purchases of Equity Securities
The table below sets forth information with respect to purchases of our common stock made by us or on our behalf during the quarter ended December 31, 2020:
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Period
Total Number of Shares Purchased (1)
Average Price Paid per Share
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
Maximum Dollar Value
of Shares that May Yet
Be Purchased Under the
Plans or Programs