For the fiscal year ended December 31, 2020

~~SECURITIES AND EXCHANGE COMMISSION~~

Delaware

71-0205415

~~Washington, D.C. 20549~~

~~Form 10-K~~

~~[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934~~

~~For the fiscal year ended~~ ~~December 31, 2017~~

~~Commission file number~~ ~~001-08246~~

~~Southwestern Energy Company~~

~~(Exact name of registrant as specified in its charter)~~

~~Delaware~~

~~71-0205415~~

(State or other jurisdiction of

~~(I.R.S. Employer~~

incorporation or organization)

(I.R.S. Employer Identification No.)

(Address of principal executive offices)(Zip Code)

Securities registered pursuant to Section 12(b) of the Act:

~~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 class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, Par Value $0.01

SWN

New 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.

~~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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes☒ No☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

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 filer ☒

☒

Accelerated filer ☐

☐

Non-accelerated filer ☐

☐

Smaller reporting company ☐

☐

Emerging ~~Growth Company~~ 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.


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 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 $3,061,637,340 based on the New York Stock Exchange – Composite Transactions closing price on June 30, 2017 of $6.08. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.
~~As of February 27, 2018, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 587,063,366~~
~~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 22, 2018 are incorporated by reference into Part III of this Form 10-K.

Table of Contents

Index to Financial Statements

SOUTHWESTERN ENERGY COMPANY

ANNUAL REPORT ON FORM 10-K

For Fiscal Year Ended December 31, 2020

TABLE OF CONTENTS


~~SOUTHWESTERN ENERGY COMPANY~~					Page
~~ANNUAL REPORT ON FORM 10-K~~ PART I
~~For Fiscal Year Ended December 31, 2017~~ Item 1.			Business		4

~~TABLE OF CONTENTS~~
				~~Page~~
~~PART I~~
~~Item 1.~~	~~Business~~	3
	Glossary of Certain Industry Terms	23 25
Item 1A.			Risk Factors		28 29
Item 1B.			Unresolved Staff Comments		39 41
Item 2.			Properties		39 41
Item 3.			Legal Proceedings		43 46
Item 4.			Mine Safety Disclosures		43 46

PART II
Item 5.			Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		44 47
			~~Stock Performance Graph~~		45
Item 6.			Selected Financial Data		46 47
Item 7. 7.			Management’s Discussion and Analysis of Financial Condition and Results of Operations		48
			Overview		48
			Results of Operations		50 51
			Liquidity and Capital Resources		57 59
			Critical Accounting Policies and Estimates		62 64
			Cautionary Statement about Forward-Looking Statements		66 68
Item 7A.			Quantitative and Qualitative Disclosures about Market Risk		67 69
Item 8.			Financial Statements and Supplementary Data		68 71
			Index to Consolidated Financial Statements		68 71
Item 9.			Changes Inin and Disagreements With Accountants on Accounting and Financial Disclosure		~~112~~ 130
Item 9A.			Controls and Procedures		~~112~~ 130
Item 9B.			Other Information		~~112~~ 130

PART III
Item 10.			Directors, Executive Officers and Corporate Governance		~~112~~ 131
Item 11.			Executive Compensation		~~113~~ 131
Item 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		~~113~~ 132
Item 13.			Certain Relationships and Related Transactions, and Director Independence		~~113~~ 132
Item 14.			Principal Accounting Fees and Services		~~113~~ 132

PART IV
Item 15.			Exhibits, Financial Statement Schedules		~~113~~ 132
Item 16.			Form 10-K Summary		~~113~~ 132

EXHIBIT INDEX					~~115~~

Table of Contents

Index to Financial Statements

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, ~~on Form 10-K,~~ 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.

Table of Contents

Index to Financial Statements

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, ~~gathering~~oil and ~~marketing.~~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 ~~was~~is incorporated in ~~Arkansas in 1929 and reincorporated in~~ Delaware, ~~in 2006,~~ 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 ~~Conway~~Tunkhannock, Pennsylvania, Morgantown, West Virginia, and ~~Damascus, Arkansas; Tunkhannock, Pennsylvania; and Jane Lew, West Virginia.~~

Zanesville, Ohio.

Our Business Strategy

We aim to deliver sustainable and ~~assured~~ industry-leading returns through excellence in exploration and production and ~~midstream~~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:

Our formula, “The Right People doing the Right Things, wisely investing the cash flow from our underlying Assets will create ~~Value~~+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 to invest only from our net cash flow (supplemented in 2017 by a portion of proceeds from our equity issuance in 2016 that we previously earmarked for capital investment), protect our projected cash flows through hedging and continue to ensure strong liquidity while de-levering the Company.

~~Increasing Margins~~. We apply strong technical, operational, commercial and marketing skills to reduce cost, improve the productivity of our wells and pursue commercial arrangements that extract greater value from them. We believe our demonstrated ability to improve margins, especially by levering the scale of our large assets, gives us a competitive advantage as we move into the future.

•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.

~~Exercising Capital Discipline.~~ We prepare an economic analysis for our drilling programs and other investments based upon the expected net present value added for each dollar to be invested, which we refer to as Present Value Index, or PVI. We target creating an average of at least a 1.3 PVI in our projects using a 10% discount rate. Our actual PVI results are utilized to help determine the allocation of our future capital investments and are reflected in our management compensation. This disciplined investment approach governs our investment decisions at all times, including the current lower-price commodity market.

•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.

~~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 commercial and marketing expertise.

•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.

~~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.

•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.

Table of Contents

Index to Financial Statements

~~The Hydrocarbon Value Chain~~. We often expand our activities vertically when we believe this will enhance our margins or otherwise provide us competitive advantages. For example, we developed and operate the largest gathering system in the Fayetteville Shale area and currently are investing in a water transportation project in West Virginia. We operate drilling rigs and own a sand mine capable of providing a low cost proppant in hydraulic fracturing. These activities help protect our margin, minimize the risk of unavailability of these resources from third parties, diversify our cash flows and capture additional value.

~~The Next Chapter of Unconventionals.~~Our company grew dramatically in the 2000s by harnessing and enhancing the newfound combination of hydraulic fracturing and horizontal drilling technologies. 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.

•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.

~~Innovative Environmental Solutions and Policy Formation.~~•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.~~

In early 2016, we faced significant challenges due to a rapid and dramatic fall in natural gas prices, which reduced our revenues and margins. We implemented the first phase of strategic initiatives, which were designed to stabilize the Company financially. We suspended drilling and completion activities, reduced our workforce and revised and extended the maturity of our ~~debt while assuring liquidity~~activities. We work extensively with governmental, non-governmental and industry stakeholders to ~~pursue our activities.~~

~~When the first phase of these activities was complete, we resumed development activities~~develop responsible and ~~entered the next phase, focusing on improving the performance of our large asset portfolio, applying the principles described above.~~ 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 ~~2017,~~2020 we executed on ~~this part~~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 ~~business strategy by:~~

~~Demonstrating financial discipline by investing within our announced plan of cash flow plus the remaining portion of the proceeds from our 2016 equity offering earmarked for this purpose;~~

outstanding senior notes for $72 million, recognizing a gain on the extinguishment of debt of $35 million; and

~~Investing only in those projects that meet our rigorous economic hurdles at strip pricing;~~

•Publishing our 7th Annual Corporate Responsibility report for 2019 (available at www.swn.com). Key environmental highlights include:

~~Enhancing margins through renegotiation of transportation and processing contracts and expansion of firm pipeline capacity portfolio to maximize realized prices;~~

◦We reported the lowest greenhouse gas intensity among our Appalachian peers in the annual Environmental Health and Safety Survey;

Improving debt maturity schedule through successful $1.15 billion debt issuance, leaving only $92 million in bonds maturing prior to 2022 and no significant other debt maturities expected before December 2020;

◦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

Delivering operational excellence with improved well productivity and economics from enhanced completion techniques, initiation of water infrastructure projects, optimization of surface equipment and managing reservoir drawdown; 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.

~~Significantly expanding our proved reserve quantities across our portfolio through our successful drilling program and improved operational performance as well as improved commodity prices.~~

~~In February 2018, we announced~~Note that the ~~next phase of strategic steps, designed to reposition our portfolio, sharpen our focus~~information on our ~~highest return assets, strengthen~~website is not incorporated by reference into this filing.

The bulk of our ~~balance sheet and enhance financial performance. These initiatives include:~~

~~Actively pursuing strategic alternatives for the Fayetteville Shale E&P and related Midstream gathering assets;~~

~~Identifying and implementing structural, process and organizational changes to further reduce costs; and~~

~~Utilizing funds realized from the foregoing to reduce debt, supplement Appalachian Basin development capital, potentially return capital to shareholders, and for general corporate purposes.~~

~~Our predominant~~ operations, which we refer to as ~~Exploration~~“Exploration and ~~Production~~Production” (“E&P”), are focused on the finding and development of natural gas, oil and ~~natural gas liquid (“NGL”)~~NGL reserves. We are also focused on creating and capturing additional value through our ~~natural gas gathering and~~ marketing ~~segment,~~business, which we refer to as ~~Midstream.~~

“Marketing.”

Table of Contents

Index to Financial Statements

~~Exploration~~

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 and~~States. We are currently focused on the development of unconventional natural gas reservoirs located in Pennsylvania, Ohio and West ~~Virginia and Arkansas.~~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, ~~and~~ southwest Pennsylvania and Ohio (herein referred to as “Southwest Appalachia”) are ~~also~~ focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas, oil and NGL ~~reservoirs, and our operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale.~~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 ~~“Appalachian Basin.” We have smaller holdings~~impact of ceiling test impairments, operating income (loss) decreased $322 million compared to the same period in ~~Colorado and Louisiana along~~2019 primarily due to lower margins associated with ~~other areas~~decreased commodity pricing.

•Our cash flow from operations was $372 million in ~~which we are testing potential new resources. We also have drilling rigs located~~2020, compared to $781 million in ~~Pennsylvania, West Virginia and Arkansas and provide certain oilfield products and services, principally serving our~~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 ~~operations.~~

volumes.

Our E&P segment recorded operating income of $549 million in 2017, compared to an operating loss of $2.4 billion in 2016. The operating loss in 2016 was primarily the result of $2.3 billion of non-cash impairments of natural gas and oil properties due to decreased commodity prices. Excluding the 2016 impairments, our E&P segment operating income increased $632 million in 2017 from 2016 primarily due to a $673 million increase in revenues, partially offset by a $41 million increase in operating expenses due primarily to increased gathering and transportation fees resulting from a shift in our production growth to the Appalachian Basin.

Cash flow from operations from our E&P segment was $985 million in 2017, compared to $297 million in 2016. Our cash flow from operations increased in 2017 as the effects of higher realized prices and increased production volumes more than offset increased operating expenses.

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 and we can do so more efficiently or cost-effectively.~~activities. This vertical integration lowers our ~~net~~ 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. ~~Among others, these~~These services ~~have included~~include drilling, ~~hydraulic fracturing,~~completions and water management and ~~movement, and the mining of sand used as proppant for certain of our well completions.~~

movement. As of December 31, ~~2017,~~2020, we ~~had~~operated a ~~total~~fleet of ~~seven re-entry~~drilling rigs and leased two ~~leased~~ pressure pumping spreads with a total capacity of ~~approximately~~ 72,000 horsepower. These ~~services~~assets provide us greater flexibility to align our operational activities with commodity prices. In ~~2017,~~2020, we provided drilling ~~services~~rigs for all of our ~~134~~98 drilled ~~wells and were able to reduce our drilling costs on average by approximately 11%, as compared to recent years.~~wells. In ~~late 2017,~~addition, we ~~reinitiated our hydraulic fracturing~~provided completions services ~~and are currently~~ utilizing one pressure pumping spread in Southwest Appalachia. ~~The majority of~~

Our Proved Reserves


	For the years ended December 31,
	2020				2019
Proved reserves: (Bcfe)
Appalachia	11,989				12,720
Other	1				1
Total proved reserves	11,990				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 gas	76		%		68		%
Proved developed	68		%		50		%

Percent of E&P operating revenues generated by natural gas sales	69		%		71		%

(1)Our existing tax attributes, including net operating losses and remaining depreciable tax basis related to our ~~wells~~natural gas and oil properties, more than offset our future net operating income, resulting in ~~2017 were completed utilizing third-party hydraulic fracturing services who were offering lower costs.~~

~~Our Proved Reserves~~

no tax effect to our PV-10 calculation for the year ended December 31, 2020.

For the years ended December 31,

2017

2016

2015
Proved reserves (Bcfe)

14,775

5,253

6,215
Prices used

Natural gas (per Mcf)
$
2.98

$
2.48

$
2.59
Oil (per Bbl)
$
47.79

$
39.25

$
46.79
NGL (per Bbl)
$
14.41

$
6.74

$
6.82

PV-10:

Pre-Tax (in millions)
$
5,784

$
1,665

$
2,417
PV of Taxes (in millions)

(222)

–

–
After-Tax (in millions)
$
5,562

$
1,665

$
2,417

Percent of estimated proved reserves that are:

Natural gas

75%

93%

95%
Proved developed

54%

99%

93%

Percent of operating revenues generated by natural gas sales

85%

89%

93%

Table of Contents

Index to Financial Statements

~~Because our proved reserves are primarily natural gas, our~~

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 ~~natural gas~~respective commodity price used in our reserve and after-tax PV-10 calculations.

Our reserves increased in 2017, compared to 2016, primarily through extensions, discoveries and other additions in the Appalachian Basin along with increases in both price and performance revisions across our portfolio.

•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.

The decrease in our reserves in 2016 compared to 2015 was primarily due to downward price revisions, associated with decreased commodity prices, and our production in 2016, partially offset by upward performance revisions in the Appalachian Basin and the Fayetteville Shale.

•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.

~~The increase in our after-tax PV-10 value in 2017 compared to 2016 was primarily due to higher reserve levels, including a significantly larger percentage of oil and NGL reserves.~~

•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 decrease in our after-tax PV-10 value in 2016 compared to 2015 was primarily due to lower reserve levels.~~

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:

~~We operate approximately 99% of our reserves, based on the pre-tax PV-10 value of our proved developed producing reserves, and our reserve life index was approximately 16.5 years at year-end 2017.~~


	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 ~~2017~~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 ~~year-end 2016~~existing tax attributes, including net operating losses and ~~2015 after-tax PV-10 computations did not have future income taxes because our~~remaining depreciable tax basis ~~in the associated~~related to our natural gas and oil properties, ~~exceeded expected pre-tax cash inflows, and thus do not differ from~~more than offset our future net operating income, resulting in no tax effect to our PV-10 calculation for the ~~pre-tax values.~~

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”~~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~~“Our proved natural gas, oil and NGL reserves are ~~estimates.~~estimates that include uncertainties. Any material ~~inaccuracies in our reserve estimates~~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.

Table of Contents

Index to Financial Statements

The following table provides an overall and categorical summary of our natural gas, oil and NGL reserves, as of ~~fiscal~~ year-end ~~2017~~2020 based on average ~~fiscal~~ year prices, and our well count, net acreage and PV-10 as of December 31, ~~2017,~~2020, and sets forth ~~2017~~2020 annual information related to production and capital investments for each of our operating areas:

2017 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA

Appalachia

Fayetteville

Northeast

Southwest

Shale

Other (1)

Total
Estimated Proved Reserves:

Natural Gas (Bcf):

Developed (Bcf)

3,007

833

3,135

4

6,979
Undeveloped (Bcf)

1,119

2,484

544

–

4,147

4,126

3,317

3,679

4

11,126
Crude Oil (MMBbls):

Developed (MMBbls)

–

14.2

–

0.3

14.5
Undeveloped (MMBbls)

–

51.1

–

–

51.1

–

65.3

–

0.3

65.6
Natural Gas Liquids (MMBbls):

Developed (MMBbls)

–

141.9

–

0.3

142.2
Undeveloped (MMBbls)

–

400.2

–

–

400.2

–

542.1

–

0.3

542.4
Total Proved Reserves (Bcfe) (2):

Developed (Bcfe)

3,007

1,770

3,135

8

7,920
Undeveloped (Bcfe)

1,119

5,192

544

–

6,855

4,126

6,962

3,679

8

14,775
Percent of Total

28%

47%

25%

0%

100%

Percent Proved Developed

73%

25%

85%

100%

54%
Percent Proved Undeveloped

27%

75%

15%

0%

46%

Production (Bcfe)

395

183

316

3

897
Capital Investments (in millions) (3)
$
489

$
547

$
114

$
41

$
1,191
Total Gross Producing Wells (4)

983

364

4,191

20

5,558
Total Net Producing Wells (4)

516

255

2,921

17

3,709

Total Net Acreage

191,226

290,291

917,842

386,304
(5)

1,785,663
Net Undeveloped Acreage

87,927

219,709

424,858

369,236
(5)

1,101,730

PV-10:

Pre-Tax (in millions) (6)
$
2,085

$
1,718

$
1,978

$
3

$
5,784
PV of Taxes (in millions) (6)

80

66

76

–

222
After-Tax (in millions) (6)
$
2,005

$
1,652

$
1,902

$
3

$
5,562
Percent of Total

36%

30%

34%

0%

100%
Percent Operated (7)

99%

100%

99%

100%

99%

~~(1)~~

~~Other consists primarily of properties in Canada, Colorado and Louisiana.~~

~~(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.


2020 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA

	Appalachia
	Northeast			Southwest			Other (1)				Total
Estimated proved reserves:
Natural gas (Bcf):
Developed	3,668			2,674			—				6,342
Undeveloped	1,248			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):
Developed	3,668			4,534			1				8,203
Undeveloped	1,248			2,539			—				3,787
	4,916			7,073			1				11,990
Percent of total	41		%	59		%	—		%		100		%

Percent proved developed	75		%	64		%	100		%		68		%
Percent proved undeveloped	25		%	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 wells	668			1,521			11				2,200

Total net acreage	217,296			571,922			22,001			(5)	811,219
Net undeveloped acreage	89,086			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 total	47		%	53		%	0%				100		%
Percent operated (8)	98		%	100		%	97		%		97		%

~~(3)~~

~~Total and Other capital investments excludes $57 million related to our E&P service companies, of which $37 million related to water infrastructure.~~

(1)Other reserves and acreage consists primarily of properties in Colorado.

~~(4)~~

~~Represents producing wells, including 400 wells in which we only have an overriding royalty interest in Northeast Appalachia, used in the December 31, 2017 reserves calculation.~~

(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.

~~(5)~~

~~Excludes exploration licenses for 2,518,519 net acres in New Brunswick, Canada, which have been subject to a moratorium since 2015.~~

(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.

~~(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.

(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.

~~(7)~~

~~Based upon pre-tax PV-10 of proved developed producing activities.~~

(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.

Table of Contents

Index to Financial Statements

(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:

2018

2019

2020
Northeast Appalachia

15,731

10,852

4,953
Southwest Appalachia (1)

12,552

14,247

12,456
Fayetteville Shale (2)

262

859

743
Other:

US – Other Exploration

62,583

104,798

16,212
US – Brown Dense

83,023

5,850

3,196
US – Sand Wash Basin

4,998

4,435

1,000
Canada – New Brunswick (3)

–

–

–

~~(1)~~

~~Of this acreage, 2,666 net acres in 2018, 5,907 net acres in 2019 and 1,850 net acres in 2020 can be extended for an average of 5.9 years.~~

~~(2)~~

~~Excludes 158,231 net acres held on federal lands which are currently suspended by the Bureau of Land Management.~~


	For the years ended December 31,
Net acreage expiring:	2021		2022	2023
Northeast Appalachia	5,861	(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 Basin	3,435		—	—
Canada – New Brunswick (3)	2,518,519		—	—

~~(3)~~

~~Exploration licenses for 2,518,519 net acres were extended through 2021 but have been subject to a moratorium since 2015.~~

(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~~“Our proved natural gas, oil and NGL reserves are ~~estimates.~~estimates that include uncertainties. Any material ~~inaccuracies in our reserve estimates~~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.

Table of Contents

Index to Financial Statements

Proved Undeveloped Reserves

Presented below is a summary of changes in our proved undeveloped reserves for ~~2015, 2016~~2019 and ~~2017:~~

CHANGES IN PROVED UNDEVELOPED RESERVES

Appalachia

Fayetteville

(Bcfe)

Northeast

Southwest

Shale

Other (1)

Total
December 31, 2014

1,598

1,481

1,716

1

4,796
Extensions, discoveries and other additions

138

4

34

–

176
Performance and production revisions (2)

513

158

62

–

733
Price revisions

(1,447)

(1,413)

(1,357)

–

(4,217)
Developed

(488)

(226)

(330)

–

(1,044)
Disposition of reserves in place

–

–

–

(1)

(1)
Acquisition of reserves in place

–

–

–

–

–
December 31, 2015

314

4

125

–

443
Extensions, discoveries and other additions

–

–

25

–

25
Performance and production revisions (2)

204

–

(1)

–

203
Price revisions

(303)

(4)

(67)

–

(374)
Developed

(181)

–

(39)

–

(220)
Disposition of reserves in place

–

–

–

–

–
Acquisition of reserves in place

–

–

–

–

–
December 31, 2016

34

–

43

–

77
Extensions, discoveries and other additions (3)

1,100

5,186

543

–

6,829
Performance and production revisions (2)

–

6

(14)

–

(8)
Price revisions

2

–

1

–

3
Developed

(17)

–

(29)

–

(46)
Disposition of reserves in place

–

–

–

–

–
Acquisition of reserves in place

–

–

–

–

–
December 31, 2017

1,119

5,192

544

–

6,855

~~(1)~~

~~Other includes properties principally in Colorado and Louisiana along with Ark-La-Tex properties divested in May 2015.~~

2020:

~~(2)~~

~~Primarily due to changes associated with the analysis of updated data collected in the year and decreases related to current year production.~~


CHANGES IN PROVED UNDEVELOPED RESERVES

	Appalachia		Total
(in Bcfe)	Northeast	Southwest







December 31, 2018	1,039	5,325	6,364
Extensions, discoveries and other additions	677	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, 2019	1,267	5,033	6,300
Extensions, discoveries and other additions	474	—	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 place	203	1,018	1,221
December 31, 2020	1,248	2,539	3,787

~~(3)~~

~~The 2017 PUD additions are primarily associated with the increase in commodity prices.~~

~~Table~~(1)Primarily due to changes associated with the analysis of ~~Contents~~

~~Index~~updated data collected in the year and decreases related to ~~Financial Statements~~

current year production.

As of December 31, 2017, we had 6,855 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 2017, we invested $23 million in connection with converting 46 Bcfe, or 60%, of our proved undeveloped reserves as of December 31, 2016 into proved developed reserves and added 6,829 Bcfe of proved undeveloped reserve additions, primarily in the Appalachian Basin. The significant increase in our proved undeveloped reserve additions in 2017 was the result of adding new undeveloped locations throughout the year through our successful drilling program, improved operational performance and increased commodity pricing across our portfolio.

(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.

As of December 31, 2016, we had 77 Bcfe of proved undeveloped reserves. During 2016, we invested $103 million in connection with converting 220 Bcfe, or 50%, of our proved undeveloped reserves as of December 31, 2015 into proved developed reserves and added 25 Bcfe of proved undeveloped reserve additions in the Fayetteville Shale. As a result of the commodity price environment in 2016, we had downward price revisions of 374 Bcfe which were slightly offset by a 203 Bcfe increase due to performance revisions.

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, 2015, we had 443 Bcfe of proved undeveloped reserves. During 2015, we invested $869 million in connection with converting 1,044 Bcfe, or 22%, of our proved undeveloped reserves as of December 31, 2014 into proved developed reserves and added 176 Bcfe of proved undeveloped reserve additions in the Appalachian Basin and the Fayetteville Shale. As a result of the depressed commodity price environment in 2015, we had downward price revisions of 4,217 Bcfe which were slightly offset by a 733 Bcfe increase due to performance revisions.

•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, ~~2017~~2020 proved reserves included ~~1,375~~2,437 Bcfe of proved undeveloped reserves from ~~330~~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 ~~$124~~$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.

Table of Contents

Index to Financial Statements

We expect that the development costs for our proved undeveloped reserves of ~~6,855~~3,787 Bcfe as of December 31, ~~2017~~2020 will require us to invest an additional ~~$4.2~~$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 ~~current~~ 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~~“Natural gas, oil and ~~natural gas liquids~~NGL prices greatly affect our ~~business, including our~~ revenues and thus profits, liquidity, growth, ability to repay our debt and the value of our assets” and ~~“Significant~~“Significant capital ~~expenditures are~~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 ~~recent years, the Appalachian Basin has provided the majority~~2020, we replaced 84% of our production volumes with 741 Bcfe of proved reserve ~~additions. In 2017,~~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 ~~undeveloped~~natural gas, oil and NGL reserves infor the Appalachian Basin increased by approximately 6.3 Tcfe, as compared to 2016, primarily due to improved commodity pricing. Our proved developed reserves in the Appalachian Basin increased by approximately 1.2 Tcfe in 2017, as compared to 2016, primarily due to our successful drilling program. Over the past three years, Northeast Appalachia has contributed 790 Bcf, 81 Bcf and 202 Bcf in 2017, 2016 and 2015, respectively,year ended December 31, 2020:


	Appalachia		Other (1)	Total
(in Bcfe)	Northeast	Southwest
December 31, 2019	4,837	7,883	1	12,721
Net revisions
Price revisions	(389)	(3,981)	—	(4,370)
Performance and production revisions	46	1,378	—	1,424
Total net revisions	(343)	(2,603)	—	(2,946)
Extensions, discoveries and other additions
Proved developed	198	69	—	267
Proved undeveloped	474	—	—	474
Total reserve additions	672	69	—	741
Production	(473)	(407)	—	(880)
Acquisition of reserves in place	223	2,131	—	2,354
Disposition of reserves in place	—	—	—	—
December 31, 2020	4,916	7,073	1	11,990

(1)Other includes properties outside of our reserve additions as a result of successful development activity. Additionally, we added 419 Bcfe, 157 Bcfe and 84 Bcfe of reserves in 2017, 2016 and 2015, respectively, as a result of our drilling program in Southwest Appalachia. ~~We expect our drilling programs in the Appalachian Basin to continue to be the primary source of our reserve additions in the future; however, our~~

Our ability to add reserves depends upon many factors that are beyond our control. We refer you to the risk factors ~~“Significant~~“Significant capital ~~expenditures are~~investment is required to replace our reserves and conduct our business” and ~~“If~~“If we are not able to replace reserves, weour production levels and thus our revenues and profits may ~~not be able to grow or sustain production.~~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.

Table of Contents

Index to Financial Statements

Our O~~perations~~

Operations

Northeast Appalachia

Northeast Appalachia represented ~~44%~~54% of our total ~~2017~~2020 net production and ~~28%~~41% of our total reserves as of December 31, ~~2017.~~2020. In ~~2017,~~2020, our reserves in Northeast Appalachia increased by ~~2,552~~79 Bcf, which included net additions of ~~1,890~~672 Bcf, ~~net upward price revisions~~acquisitions of ~~903~~223 Bcf and net upward performance revisions of ~~154~~46 Bcf, partially offset by net downward price revisions of 389 Bcf and production of ~~395~~473 Bcf. As of December 31, ~~2017,~~2020, we had approximately ~~191,226~~217,296 net acres in Northeast Appalachia and had ~~spud or acquired 645 operated~~a total of 677 wells ~~538 of which were~~ on ~~production.~~production that we operated. Below is a summary of Northeast Appalachia’s operating results for the latest ~~three~~two years:


	For the years ended December 31,									For the years ended December 31,
	2017			2016		2015				2020				2019
Acreage									Acreage
Net undeveloped acres		87,927	(1)		146,096		174,826		Net undeveloped acres	89,086		(1)		53,435
Net developed acres		103,299			99,709		95,509		Net developed acres	128,210				120,559
Total net acres		191,226			245,805		270,335		Total net acres	217,296				173,994

Net Production (Bcf)		395			350		360		Net Production (Bcf)	473				459

Reserves									Reserves
Reserves (Bcf)		4,126			1,574		2,319		Reserves (Bcf)	4,916				4,837
Locations:									Locations:
Proved developed		983			820		767
Proved developed producing (2)									Proved developed producing (2)	744				695
Proved developed non-producing(3)		25			39		23		9				11
Proved undeveloped		100			2		36		Proved undeveloped	57				82
Total locations		1,108			861		826		Total locations	810				788

Gross Operated Well Count Summary									Gross Operated Well Count Summary
Spud or acquired		58			32		177	(2)
Drilled									Drilled	49				39
Completed		77			33		92		Completed	44				44
Wells to sales		83			24		100		Wells to sales	45				44

Capital Investments (in millions)									Capital Investments (in millions)
Exploratory and development drilling, including workovers	$	420		$	160	$	472
Drilling and completions, including workovers									Drilling and completions, including workovers	$	321			$	314
Acquisition and leasehold		14			3		172		Acquisition and leasehold	9				13
Seismic and other		13			2		8		Seismic and other	9				5
Capitalized interest and expense		42			39		58		Capitalized interest and expense	23				33
Total capital investments	$	489		$	204	$	710		Total capital investments	$	362			$	365

Average completed well cost (in millions)	$	5.9		$	5.3	$	5.4		Average completed well cost (in millions)	$	6.8			$	7.3
Average lateral length (feet)		6,185			6,142		5,403		Average lateral length (feet)	10,765				9,029

(1)Our undeveloped acreage position as of December 31, ~~2017~~2020 had an average royalty interest of 15%. ~~The decrease~~

(2)Excludes 587 and 516 wells as of December 31, 2020 and 2019, respectively, in ~~our net undeveloped acres~~which we have only an overriding royalty interest.

(3)Excludes 27 and 3 wells as of December 31, 2020 and 2019, respectively, in ~~2017~~which we have only an overriding royalty interest.

For 2020 as compared to ~~2016 is~~2019:

•Our average completed well cost per foot decreased primarily due to ~~leasehold expirations in areas we did not plan on developing.~~

~~(2) Includes 86 horizontal~~increased lateral lengths and ~~2 vertical acquired wells.~~

operational execution.

Our proved undeveloped reserve locations increased significantly in 2017, as compared to 2016, primarily through our successful drilling program in less developed areas and improved realized commodity pricing.

~~Our average completed well cost increased in 2017, as compared to 2016, primarily due to tighter hydraulic fracturing spacing and increased activity in delineation areas.~~

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 ~~“Midstream”~~“Marketing” in Item 1 of Part I of this Annual Report for a discussion of our gathering and transportation arrangements for Northeast Appalachia production.

Table of Contents

Index to Financial Statements

Southwest Appalachia

Southwest Appalachia represented ~~20%~~46% of our total ~~2017~~2020 net production and ~~47%~~59% of our total reserves as of December 31, ~~2017.~~2020. In ~~2017,~~2020, our reserves in Southwest Appalachia ~~increased~~decreased by ~~6,285~~810 Bcfe, ~~which included~~as net ~~additions of 5,605 Bcfe, net upward~~downward price revisions of ~~738~~3,981 Bcfe and ~~125~~production of 407 Bcfe were only partially offset by acquisitions of 2,131 Bcfe, net upward performance revisions ~~partially offset by production~~ of ~~183~~1,378 Bcfe and net additions of 69 Bcfe. As of December 31, ~~2017,~~2020, we had approximately ~~290,291~~571,922 net acres in Southwest Appalachia and had a total of ~~360~~1,670 wells on production that we operated. Below is a summary of Southwest Appalachia’s operating results for the latest ~~three~~two years:

For the years ended December 31,

2017

2016

2015
Acreage

Net undeveloped acres (1)

219,709
(2)

252,470

193,582
Net developed acres (1)

70,582

69,093

231,516
Total net acres

290,291

321,563

425,098

Net Production (Bcfe)

183

148

143

Reserves

Reserves (Bcfe)

6,962

677

611
Locations:

Proved developed

364

306
(3)

1,028
Proved developed non-producing

37

44
(3)

400
Proved undeveloped

559

–

1
Total locations

960

350
(3)

1,429

Gross Operated Well Count Summary

Spud or acquired

55

17

48
Completed

50

17

38
Wells to sales

57

18

47

Capital Investments (in millions)

Exploratory and development drilling, including workovers
$
353

$
111

$
248
Acquisition and leasehold

59

18

409
Seismic and other

4

1

2
Capitalized interest and expense

131

158

198
Total capital investments
$
547

$
288

$
857

Average completed well cost (in millions) (4)
$
7.4
(5)
$
5.4
(5)
$
6.9
Average lateral length (feet) (4)

7,451
(5)

5,275
(5)

6,985

~~(1)~~

~~A divestiture of shallow legacy assets, in which we retained the Marcellus and Utica geologic intervals, resulted in a reclassification of acreage from developed to undeveloped in 2016.~~

~~(2)~~

~~Our undeveloped acreage position as of December 31, 2017 had an average royalty interest of 14%.~~


	For the years ended December 31,
	2020			2019
Acreage
Net undeveloped acres	425,702		(1)	205,222
Net developed acres	146,220			82,471
Total net acres	571,922			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 undeveloped	151			376
Total locations	2,146			920

Gross Operated Well Count Summary
Drilled	49			66
Completed	52			72
Wells to sales	55			69

Capital Investments (in millions)
Drilling and completions, including workovers	$	360		$	516
Acquisition and leasehold	28			42
Seismic and other	1			3
Capitalized interest and expense	121			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

~~(3)~~

~~Includes the impact of legacy assets divested in 2016.~~

(1)Our undeveloped acreage position as of December 31, 2020 had an average royaltyinterest of 15%.

~~(4)~~

~~Includes wells only drilled by SWN.~~

(2)Approximately 405 Bcfe and 317 Bcfe for the years ended December 31, 2020 and 2019, respectively, were produced from the Marcellus Shale formation.

~~(5)~~

~~Excludes one Utica delineation well in 2017 and one in 2016, respectively.~~

(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.

~~Our average completed well cost increased in 2017, as compared to 2016, primarily due to longer lateral lengths, tighter hydraulic fracturing spacing and increased proppant volumes.~~

(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.

Table of Contents

Index to Financial Statements

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 ~~“Midstream”~~“Marketing” within Item 1 of Part I of this Annual Report for a discussion of our gathering and transportation arrangements for Southwest Appalachia production.

~~Table of Contents~~

~~Index to Financial Statements~~

~~Fayetteville Shale~~

The Fayetteville Shale represented 35% of our total 2017 net production and 25% of our total reserves as of December 31, 2017. In 2017, our reserves in the Fayetteville Shale increased by 682 Bcf, which included net reserve additions of 591 Bcf, 358 Bcf of net upward revisions due to well performance and net upward price revisions of 49 Bcf, partially offset by production of 316 Bcf. As of December 31, 2017, we held leases for approximately 917,842 net acres in the Fayetteville Shale and had 4,698 wells on production, 4,033 which were operated by us and 665 were outside-operated wells. Below is a summary of the Fayetteville Shale’s operating results for the latest three years:

For the years ended December 31,

2017

2016

2015
Acreage

Net undeveloped acres (1) (2)

424,858
(3)

426,717

459,312
Net developed acres (1)

492,984

491,818

498,329
Total net acres

917,842

918,535

957,641

Net Production (Bcf)

316

375

465

Reserves

Reserves (Bcf)

3,679

2,997

3,281
Locations:

Proved developed

4,191

4,217

4,268
Proved developed non-producing

304

311

231
Proved undeveloped

234

13

61
Total locations

4,729

4,541

4,560

Gross Operated Well Count Summary

Spud or acquired

6

4

155
Completed

23

34

262
Wells to sales

25

43

260

Capital Investments (in millions)

Exploratory and development drilling, including workovers
$
82

$
63

$
484
Acquisition and leasehold

1

2

4
Seismic and other

9

–

8
Capitalized interest and expense

22

21

69
Total capital investments
$
114

$
86

$
565

Average completed well cost (in millions)
$
4.2

$
3.2

$
2.8
Average lateral length (feet)

6,609

5,717

5,729

~~(1)~~

A divestiture of shallow legacy Arkoma assets in 2015, in which we retained the geologic interval from the top of the upper Fayetteville Formation down to the base of the Chattanooga Formation, resulted in a reclassification of acreage from developed to undeveloped.

~~(2)~~

~~Includes 226,312, 227,656 and 202,156 net undeveloped acres in the Arkoma Basin as of December 31, 2017, 2016 and 2015, respectively.~~

Other

~~(3)~~

~~Our undeveloped acreage position as of December 31, 2017 had an average royalty interest of 13%.~~

~~Our proved undeveloped reserve locations increased significantly in 2017, as compared to 2016, primarily due to improved realized commodity pricing.~~

~~Our average completed well cost increased in 2017, as compared to 2016, primarily due to longer lateral lengths and increased activity in the deeper Moorefield zone.~~

~~Table of Contents~~

~~Index to Financial Statements~~

Of the acreage we hold in the Fayetteville Shale, the Ozark Highlands Unit accounts for 158,231 acres and lies entirely within the Ozark National Forest. Following the commencement of two court actions, which were subsequently consolidated, alleging deficiencies in the Environmental Impact Statement issued in connection with the grant of the leases by the Bureau of Land Management (BLM) in the Ozark National Forest, the BLM discontinued approval of operational permits in the forest, including permits to drill, pending resolution of the litigation. Although the case was dismissed in May 2017, the BLM is not issuing drilling permits. If and when permit issuance resumes, the leases will expire unless, within nine months, we commence drilling or resume rental payments. At year-end 2017, after excluding our acreage in the conventional Arkoma Basin and the federal acreage we hold in the Ozark Highlands Unit, approximately 99% of our 533,299 total net leasehold acres remaining in the Fayetteville Shale was held by production. For more information about our acreage and well count, we refer you to ~~“Properties”~~ in ~~Item 2~~ ~~of Part I of this Annual Report. We also refer you to the risk factor~~ ~~“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”~~ in ~~Item 1A~~ ~~of Part I of this Annual Report.~~

~~In February 2018, we announced an initiative to actively pursue strategic alternatives for the Fayetteville Shale E&P and related Midstream gathering assets.~~

~~Other~~

Excluding 2,518,519 acres in New Brunswick, Canada, which have been subject to a government-imposed drilling moratorium since 2015, we held ~~369,236~~9,764 net undeveloped acres for the potential development of new resources as of December 31, ~~2017.~~2020 in areas outside of Appalachia. This compares to ~~492,389~~27,334 net undeveloped acres held at year-end ~~2016 and 1,142,856 net undeveloped acres held at year-end 2015,~~2019, excluding the New Brunswick acreage.

We limited our activities in areas beyond our assets in ~~the Appalachian Basin~~Appalachia during 2020 and ~~the Fayetteville Shale during 2017, 2016 and 2015~~2019 as a result of the commodity price environment as we focused our capital allocation on these more ~~proven development~~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. In March 2010, we successfully bid for~~Brunswick, Canada. We currently hold exclusive licenses ~~from the Department of Natural Resources of New Brunswick~~ to search and conduct an exploration program covering 2,518,519 net acres in ~~the province in order to test new hydrocarbon basins.~~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, ~~the Company~~we requested and ~~was~~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. ~~Given~~

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 ~~development,~~Annual Report for more information on the Merger.

During 2019, we ~~recognized an impairment of $39 million, net of tax,~~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)	2020		2019
E&P Capital Investments by Type
Exploratory and development drilling, including workovers	$	692	$	838
Acquisition of properties	37		55
Seismic expenditures	—		3
Water infrastructure project	9		35
Other	17		21
Capitalized interest and expenses	144		186
Total E&P capital investments	$	899	$	1,138

E&P Capital Investments by Area
Northeast Appalachia	$	362	$	365
Southwest Appalachia	510		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 ~~investment~~water infrastructure project.

•The decrease in ~~New Brunswick in~~2020 E&P capital investing, as compared to the ~~second quarter of 2016.~~

~~Acquisitions and Divestitures~~

~~In September 2016, we sold approximately 55,000 net acres in West Virginia for approximately $401 million. As of December 2015, these assets included approximately 11 Bcfe of proved reserves.~~

~~In May 2015, we sold conventional oil and gas assets located in East Texas and~~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 ~~Arkoma Basin for approximately $211 million. As of December 2014, these assets included approximately 184 Bcf of proved reserves.~~

In April 2015, we sold our gathering assets located in Bradford and Lycoming counties in northeast Pennsylvania for approximately $489 million. The assets included approximately 100 miles of natural gas gathering pipelines with nearly 600 million cubic feet per day of capacity.

In January 2015, we acquired approximately 46,700 net acres in northeast Pennsylvania for $270 million. As part of this transaction, we also received firm transportation capacity of 260 million cubic feet per day predominately onremaining proceeds from the ~~Millennium pipeline.~~

In December 2014, we acquired approximately 413,000 net acres in West Virginia and southwest Pennsylvania with plans to target the Marcellus, Utica and Upper Devonian Shales for approximately $5.0 billion. Additionally, in January 2015, we acquired an additional approximate 30,000 net acres in this area for $357 million.

Fayetteville Shale sale.

Table of Contents

Index to Financial Statements

~~Capital Investments~~

For the years ended December 31,
(in millions)
2017

2016

2015
E&P Capital Investments by Type

Exploratory and development drilling, including workovers
$
878

$
358

$
1,226
Acquisition and leasehold

86

23

607
Seismic expenditures

7

1

6
Drilling rigs, sand facility, water infrastructure and other

65

2

40
Capitalized interest and other expenses

212

239

379
Total E&P capital investments
$
1,248

$
623

$
2,258

E&P Capital Investments by Area

Northeast Appalachia
$
489

$
204

$
710
Southwest Appalachia

547

288

857
Fayetteville Shale

114

86

565
Other

98

45

126
Total E&P capital investments
$
1,248

$
623

$
2,258
•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.

The significant increase in 2017 E&P capital investing, as compared to 2016, resulted from the resumption of activity following our decision to suspend drilling activity in the first half of 2016 due to an unfavorable commodity price environment. We began increasing activity in the second half of 2016 as forward pricing improved.

•Of the 42 wells in progress at year-end, 26 and 16 were located in Northeast Appalachia and Southwest Appalachia, respectively.

~~The significant decrease in 2016 E&P capital investing, as compared to 2015, was the result of suspending drilling activity in the first half of 2016 due to an unfavorable commodity price environment.~~

~~In 2017, we drilled 134 wells (120 of which were spud in 2017), completed 151 wells, placed 166 wells to sales and had 92 wells in progress at year-end.~~

~~Of the 92 wells in progress at year-end, 52 and 40 were located in Northeast Appalachia and Southwest Appalachia, respectively, and 19 of these wells were waiting on pipeline or production facilities.~~

We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital ~~Investments”~~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 ~~2018.~~

2021.

Sales, Delivery ~~Commitmen~~tsCommitments 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,				For the years ended December 31,
	2017	2016	2015		2020	2019
Average net daily production (MMcfe/day)	2,456	2,391	2,675	Average net daily production (MMcfe/day)	2,403	2,133
Production:				Production:
Natural gas (Bcf)	797	788	899	Natural gas (Bcf)	694	609
Oil (MBbls)	2,327	2,192	2,265	Oil (MBbls)	5,141	4,696
NGLs (MBbls)	14,245	12,372	10,702	NGLs (MBbls)	25,927	23,620
Total production (Bcfe)	897	875	976	Total production (Bcfe)	880	778

The increase in production in 2017 resulted primarily from a 45 Bcf increase in net production from our Northeast Appalachia properties and a 35 Bcfe increase in net production from our Southwest Appalachia properties, partially offset by a decrease of 59 Bcf from our Fayetteville Shale properties.

•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.

The decrease in production in 2016 resulted primarily from normal declines in production from existing wells that were not fully offset by production from new wells, given our reduced drilling activities. In particular, we experienced a 90 Bcf decrease in net production from our Fayetteville Shale properties, a 10 Bcf decrease in net production from our Northeast Appalachia properties and a 6 Bcfe decrease in other properties, which was partially offset by a 5 Bcfe increase in net production from our Southwest Appalachia properties.

Average Realized Prices


	For the years ended December 31,
	2020			2019
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 derivatives	26		%	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.

Table of Contents

Index to Financial Statements

For the years ended December 31,
Average realized price per unit:
2017

2016

2015
Natural gas sales, excluding derivatives (per Mcf)
$
2.23

$
1.59

$
1.91
Effect of settled gain (loss) on derivatives (per Mcf)

(0.04)

0.05

0.46
Natural gas sales, including derivatives (per Mcf)
$
2.19

$
1.64

$
2.37

Oil sales (per Bbl)
$
43.12

$
31.20

$
33.25

NGL sales, excluding derivatives (per Bbl)
$
14.46

$
7.46

$
6.80
Effect of settled gain (loss) on derivatives (per Bbl)

0.02

–

–
NGL sales, including derivatives (per Bbl)
$
14.48

$
7.46

$
6.80

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 ~~natural gas,~~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. ~~Our policies prohibit speculation with derivatives and~~We limit derivative agreements to counterparties with appropriate credit ~~standings.~~

standings, and our policies prohibit speculation.

As of December 31, ~~2017,~~2020, we had the following commodity price derivatives in place on our targeted future production:


					For the years ended December 31,
	For the years ended December 31,				2021	2022	2023
Financial protection on production as of December 31, 2017:	2018	2019	2020
Natural gas (Bcf)	489	201	–	Natural gas (Bcf)	751	378	87
Oil (MBbls)				Oil (MBbls)	6,631	2,155	878
Ethane (MBbls)	183	–	–	Ethane (MBbls)	6,473	1,710	—
Propane (MBbls)	183	–	–	Propane (MBbls)	6,974	2,120	—
Normal Butane (MBbls)				Normal Butane (MBbls)	2,004	667	—
Natural Gasoline (MBbls)				Natural Gasoline (MBbls)	1,936	643	—

As of February ~~27, 2018,~~25, 2021, we had the following commodity price derivatives in place on our targeted 2020 and future production:


					For the years ended December 31,
	For the years ended December 31,				2021	2022	2023
Financial protection on production as of February 27, 2018:	2018	2019	2020
Natural gas (Bcf)	566	216	–	Natural gas (Bcf)	761	454	103
Oil (MBbls)				Oil (MBbls)	6,631	2,850	878
Ethane (MBbls)	183	–	–	Ethane (MBbls)	6,560	1,893	—
Propane (MBbls)	1,353	–	–	Propane (MBbls)	7,149	2,727	—
Normal Butane (MBbls)				Normal Butane (MBbls)	2,092	794	—
Natural Gasoline (MBbls)				Natural Gasoline (MBbls)	2,021	765	—

We intend to ~~financially protect pricing~~use derivatives to limit the impact of price volatility on a large portion of expected future production volumes ~~designed~~ to ~~assure~~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 ~~Risks,~~Risk,” for further information regarding our derivatives and risk management as of December 31, ~~2017.~~

2020.

During ~~2017,~~2020, the average price we received for our natural gas production, excluding the impact of derivatives and including the cost of transportation, was approximately ~~$0.88~~$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, ~~2017,~~2020, we have ~~partially mitigated~~entered into physical sales arrangements to limit the ~~volatility~~impact of basis ~~differentials by protecting basis~~volatility on approximately ~~182~~217 Bcf and 7065 Bcf of our ~~2018~~2021 and 2019 expected natural gas production, respectively, through physical sales arrangements at a basis differential to NYMEX natural gas price of approximately ($0.25) per MMBtu and ($0.31) per MMBtu for 2018 and 2019, respectively.

~~We have also financially protected basis on approximately 44 Bcf and less than 1 Bcf of our 2018 and 2019~~2022 expected natural gas production, respectively, at a basis differential to NYMEX natural gas price of approximately ($~~0.48)~~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 ~~2018~~2021, 2022, 2023, 2024 and ~~2019,~~2025, respectively, as of December 31, ~~2017.~~

2020.

We refer you to Note 46 to ~~our~~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, ~~2017,~~2020, we had natural gas delivery commitments of ~~408~~486 Bcf in ~~2018~~2021 and ~~100~~113 Bcf in ~~2019~~2022 under existing agreements. These amounts are well below our expected ~~2018~~2021 natural gas production from Northeast Appalachia and Southwest Appalachia and ~~the Fayetteville Shale and~~ expected ~~2019~~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

~~Table of Contents~~

~~Index to Financial Statements~~

control that may affect our ability to meet our ~~contractual obligations~~delivery commitments other than those discussed in Item 1A ~~“Risk Factors”~~“Risk Factors” of Part I of this Annual Report. We expect to be able to fulfill all of our short-term and long-term ~~contractual obligations~~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.

Customers. Our E&P production is marketed primarily by our ~~Midstream~~Marketing segment. Our customers include major energy companies, utilities and industrial purchasers of natural gas. For the year ended December 31, ~~2017, two subsidiaries of Royal Dutch Shell Plc in aggregate~~2020, one purchaser accounted for ~~approximately 10.3%~~10% of ~~total natural gas, oil and NGL sales.~~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 ~~years~~year ended December 31, ~~2016 and 2015,~~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.

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 ~~sale~~marketing of natural gas, oil and ~~oil, its gathering and transportation (whether we are shipping or operate the transmission facilities)~~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 and operators and developers of gathering and transportation systems.~~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, particularly in the northeastern United States, where potential production levels exceed currently available capacity.~~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 ~~market reforms~~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.

Producing natural gas, oil and ~~oil~~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 ~~December~~ 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, ~~or the CFTC,~~(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.~~

NGLs

Producing and transporting natural gas, oil and ~~oil~~NGLs is also subject to extensive environmental regulation. We refer you to ~~“Other —~~“Other – Environmental Regulation” in Item 1 of Part 1 of this Annual Report and the risk factor ~~“We~~“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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Index to Financial Statements

~~Midstrea~~m

~~Through our affiliated midstream subsidiaries, we~~

We engage in marketing ~~and natural gas gathering~~ activities which primarily support our E&P ~~operations. We~~operations and generate revenue ~~from gathering fees associated with the transportation of natural gas to market and~~ through the marketing of natural gas, oil and NGLs. ~~Our Midstream segment complements our E&P initiatives~~


	For the years ended December 31,
	2020			2019
Marketing revenues (in millions)	$	2,145		$	2,849

Other revenues (in millions)	—			1
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 operations	89		%	79		%
Percent oil and NGL production marketed from affiliated E&P operations	81		%	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 ~~in some areas, competes with other midstream providers~~expenses. In addition, marketing operating loss for ~~unaffiliated business.~~

For the years ended December 31,

2017

2016

2015

Marketing revenues (in millions)
$
2,867

$
2,191

$
2,628

Gathering revenues (in millions)

331

378

491
(1)
Total operating revenues (in millions)

3,198

2,569

3,119

Operating income (in millions)

183

209

583
(2)

Cash flows from operations (in millions)
$
208

$
222

$
540

Capital investments – gathering (in millions)

32

21

58

Natural gas gathered from the Fayetteville Shale (Bcf)

Operated wells (Bcf)

463

558

695

Third-party operated wells (Bcf)

35

42

55

Total volumes gathered in the Fayetteville Shale (Bcf)

498

600

750

Volumes marketed (Bcfe)

1,067

1,062

1,127

Percent natural gas marketed from affiliated E&P operations

96%

93%

97%

Percent oil and NGLs marketed from affiliated E&P operations

63%

65%

60%

~~(1)~~

During 2015, we divested our gathering assets in northeast Pennsylvania and East Texas. The divested gathering assets accounted for $21 million of our gathering revenues for the year ended December 31, 2015.

~~(2)~~

~~Operating income in 2015 includes a $277 million net gain related to the sale of our northeast Pennsylvania and East Texas gathering assets.~~

Operating income from our Midstream segment decreased $26 million in 2017 compared to 2016, primarily due to a $47 million decrease in gas gathering revenues related to a decrease in Fayetteville Shale gathered volumes, and a $3 million decrease in marketing margin, partially offset by a $18 million decrease in operating costs and expenses, primarily related to decreased compression rental and maintenance activities, and a $6 million gainthe year ended December 31, 2019 included a $3 million impairment of non-core gathering assets, a $2 million loss on ~~sale of certain compressor equipment.~~

Excluding the $277 million gain on the 2015 sale of our northeast Pennsylvania and East Texas gathering assets, operating income decreased $97 million in 2016 compared to 2015, primarily due to a 20% decrease in volumes gathered, resulting from lower production volumes in the Fayetteville Shale.

~~Revenues increased in 2017, compared to 2016, as the effect of an increase in the price received for volumes marketed was only partially offset by a decrease in volumes gathered.~~

~~Revenues decreased in 2016, compared to 2015, primarily due to a decrease in the price received for volumes marketed, a decrease in volumes marketed and a decrease in volumes gathered.~~

Cash flow from operations generated by our Midstream segment decreased in 2017, compared to 2016, primarily due to a $26 million decrease operating income, partially offset by a $12 million increase primarily related to timing differences of payables and receivables between the respective periods.

The decrease in cash flow from operations in 2016, compared to 2015, was primarily due to decreased revenues and a decrease related to timing differences of payables and receivables between the respective periods, partially offset by a decrease in operating costs and expenses.

~~Gas Gathering~~

~~Since~~ the sale of ~~our gathering~~operating assets and $1 million in ~~northeast Pennsylvania and Texas~~gas storage gains recorded in ~~2015, our gathering assets are concentrated~~other operating revenues.

•Marketing revenues decreased in 2020, compared to 2019, primarily as a 27% decrease in the ~~Fayetteville Shale~~price received for volumes marketed more than offset a 37 Bcfe increase in ~~Arkansas.~~ Atmarketed 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 end of 2017, we had approximately 2,045 miles of pipe from the individual wellheads to the transmission lines and compression equipment representing in aggregate approximately 377,070 horsepower that had been installed at 58 central point gathering facilities in the Fayetteville Shale. In February 2018, we announced an initiative to actively pursue strategic alternatives for the Fayetteville Shale E&P and related Midstream gathering assets.

respective periods.

Northeast Appalachia. Our transportation portfolio in Northeast Appalachia is ~~highly-diversified and structured to capture improving northeast basis differentials, which we expect to enhance our margins in 2018,~~highly diversified and allows us to access premium city-gate markets as well as ~~deliveries across~~to deliver natural gas from the ~~greater Appalachia~~Appalachian basin area ~~down~~ 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 ~~27, 2018:~~

25, 2021:

(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. ~~Over the next four years, agreements~~Agreements with ET Rover Pipeline LLC and Columbia Pipeline Group, Inc.’s Mountaineer Xpress and Gulf Xpress pipelines ~~will~~ allow us to access high-demand markets along the Gulf Coast while also capturing materially improving in-basin ~~pricing.~~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 ~~exposure~~access to Mont Belvieu pricing. ~~New ethane cracker demand and export capacity is expected~~The table

below details our natural gas firm transportation, firm sales and total takeaway capacity over the next three years as of February ~~27, 2018:~~

25, 2021:

(1)We have extension options and potential contract renewal capacity by restructuring our transportation agreements with Texas Gas Transmission, LLC. The new agreements were approved by the FERC and, effective November 1, 2017, reduced our Fayetteville Lateral volume commitment from 800,000of 76,900 MMBtu per day ~~to 100,000~~for 2022 and 76,900 MMBtu per day from November 2017 to October 2020 at existing rates, restructured firm transportation agreements and demand fees beginning in 2021 on 550,000 MMBtu per day of contracted volumes, reducing annually through 2030, at a rate of approximately $0.10 per MMBtu. Additionally the agreements provided for firm transportation of all volumes between the contracted firm amount up to 800,000 MMBtu per day each year starting in 2021. This amendment of our agreements provides fixed rate, guaranteed long-term takeaway capacity2023 for our Fayetteville production. A competitor of Texas Gas Transmission has sought review of the FERC’s order, and although we cannot predict with certainty the outcome, we do not expect the order to be overturned. The table below details our firm transportation, firm sales and total takeaway capacity over the next three years as of February 27, 2018:

Southwest Appalachia.

For the year ended December 31,
(MMBtu/d)
2018

2019

2020
Firm transportation
1,300,000

1,300,000

1,283,333
Firm sales
–

–

–
Total firm takeaway – Fayetteville Shale
1,300,000

1,300,000

1,283,333

As of December 31, ~~2017,~~2020, our obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately ~~$9.2~~$8.5 billion, ~~$3.0 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 ~~$832~~$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.

~~Table~~In the first quarter of ~~Contents~~

~~Index~~2019, we agreed to ~~Financial Statements~~

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.

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 ~~producers and end-users.~~

customers.

Our marketing customers include major energy companies, utilities and industrial purchasers of natural gas. For the year ended December 31, ~~2017, two subsidiaries of Royal Dutch Shell Plc in aggregate~~2020, one purchaser accounted for ~~approximately 10.3%~~10% of ~~total natural gas, oil and NGL sales.~~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 ~~years~~year ended December 31, ~~2016 and 2015,~~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.

The transportation of natural gas, oil and NGLs is heavily regulated. ~~Interstate pipelines must obtain authorization from~~FERC regulates the ~~FERC to operate in~~rates and the terms and conditions of transportation service provided by interstate ~~commerce,~~natural gas, crude oil and ~~state~~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 ~~FERC currently allows interstate pipelines~~basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to ~~adopt market-based rates; however, in the past the FERC has regulated~~intrastate pipeline ~~tariffs and could do so again in the future. State tariff regulations vary.~~rates, varies from state to state. Currently, all pipelines we own are ~~intrastate.~~

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. ~~In addition, various suppliers~~

The transportation of natural gas and oil is also subject to extensive environmental regulation. We refer you to ~~“Other~~“Other – Environmental Regulation” in Item 1 of Part I of this Annual Report and the risk factor ~~“We~~“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

~~Our other operations have historically consisted of limited real estate development activities and a natural gas vehicles (“NGV”) fueling station in Damascus, Arkansas, which was sold in May 2016.~~

We currently have no significant business activity outside of our E&P and ~~Midstream~~Marketing segments.

~~Environmental Regulation~~

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 ~~costs of~~ clean-up ~~operations~~costs in limited instances arising out of sudden and accidental events, but otherwise we ~~are~~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

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~~Index to Financial Statements~~

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 ~~property~~properties we ~~have sold,~~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, ~~transport,~~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.

~~Certain U.S. Statutes.~~ ~~CERCLA,~~

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 ~~the disposal~~a site ~~or sites~~ where the release occurred, ~~and companies~~as well as persons that transported or disposed, or arranged for the ~~transport~~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

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 ininto 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. ~~In 2017~~Although oil accounted for 2%only 4% of our total production ~~compared to~~in 2020 and 2019 and 2% ~~of our total production for 2016 and less than 1% of our total production for 2015, although~~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. ~~These properties and the wastes disposed on them may be subject to~~Under CERCLA, the ~~Clean~~

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~~Index to Financial Statements~~

~~Water Act,~~CWA, RCRA and analogous state ~~laws. Under such~~ 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 inwe conduct as part of our operations, such as drilling, pumping and the use of vehicles, can ~~release matter subject~~result in emissions to ~~regulation.~~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 ~~few~~several years, there has been an increased focus on the environmental aspects of hydraulic fracturing, ~~practice,~~ 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 ~~NESHAPS~~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

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 ~~current federal~~prior administration ~~has~~ 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.

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. ~~We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations, subject to regulatory restrictions relating to seismicity.~~ 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~~.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.

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 ~~June 2017, President Trump announced that~~November 2019, the United States ~~intends to withdraw~~initiated the year-long process of formally withdrawing from the Paris Agreement, and to seek negotiations either to reenter the Paris Agreement on different terms or a separate agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four year exit process beginning when it took effect in November 2016, which ~~would result~~resulted in an effective exit date of November 2020. ~~The United States’ adherence to~~However, in January 2021, the ~~exit process and/or~~new administration announced that the ~~terms on which the United States may re-enter~~U.S. would be rejoining the Paris ~~Agreement or a separately negotiated agreement are unclear at this time.~~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~~Health and ~~safety.~~ Safety.Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, ~~(“OSHA”)~~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

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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.

~~Employees~~

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

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, ~~2017,~~2020, we had ~~1,575~~900 total ~~employees.~~employees, a decrease of 2% compared to year-end 2019. None of our employees were covered by a collective bargaining agreement at year-end ~~2017.~~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 ~~27, 2018~~25, 2021 about our executive officers, as defined in Rule 3b-7 of the Securities Exchange Act of 1934:

Name

~~Age~~

Age

Officer Position

William J. Way

President and Chief Executive Officer

Michael E. Hancock

Vice President and Chief Financial Officer (Interim)

Clayton A. Carrell

Executive Vice President and Chief Operating Officer

~~J. David Cecil~~

Derek W. Cutright

~~Executive Vice President Corporate Development~~

~~Jennifer E. Stewart~~

~~Senior Vice President and Chief Financial Officer – Interim~~

~~Jennifer N. McCauley~~

Senior Vice President – ~~Administration~~

Southwest Appalachia

John ~~C. Ale~~

P. Kelly

Senior Vice President – Northeast Appalachia

Quentin Dyson

Senior Vice President – Operations Services

Jason Kurtz

Vice President – Marketing and Transportation

Chris Lacy

Vice President, General Counsel and Secretary

~~Jason Kurtz~~

Andy Huggins

Vice President – ~~Marketing~~Business and ~~Transportation~~

Commercial Development

Carina Gillenwater

Vice 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. ~~Cecil~~Cutright was appointed ~~Executive~~Senior Vice President ~~Corporate Development~~of Southwest Appalachia Division in ~~August~~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 ~~Managing Director~~President and ~~Head~~Chief Executive Officer of ~~the North American E&P group of Lazard~~Cantera Energy since 2012.

~~Ms. Stewart~~

Mr. Dyson was appointed Senior Vice President ~~and Chief Financial Officer – Interim~~of Operations Services in ~~June 2017. Prior to serving as the Chief Financial Officer – Interim, she was Senior~~April 2019. He held Vice President ~~Tax~~roles at EP Energy and ~~Treasury. Ms. Stewart joined the Company~~BP before joining SWN in ~~2010~~January 2018 as Vice President ~~Tax.~~

~~Ms. McCauley was appointed Senior Vice President~~ – ~~Administration in April 2016. Prior to that, she served as Senior Vice President – Human Resources since 2009.~~

Mr. Ale was appointed Senior Vice President, General Counsel and Secretary in November 2013. Prior to that, he was Vice President and General Counsel of Occidental Petroleum Corporation since April 2012. Prior to that, he was a partner with Skadden, Arps, Slate, Meagher & Flom LLP since 2002.

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.

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 ~~apply to the~~include indicated terms ~~as used~~ 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.

“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”~~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.~~

(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.

~~(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.

(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.

~~(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.

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~~(iv)~~

~~Provide improved recovery systems.~~

Index to Financial Statements

(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

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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).

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“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”~~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.

“~~NGL~~NGLs” Natural gas ~~liquids.~~

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.

“~~Present Value Index” or “PVI” A measure that is computed for projects by dividing the dollars invested into the PV-10 resulting or expecting to result from the investment by the dollars invested.~~

“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

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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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Index to Financial Statements

ITEM 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual ~~Report on Form 10-K.~~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 ~~2017~~2020 and ~~2016,~~2019, the NYMEX settlement price for natural gas ranged from a low of ~~$1.71~~$1.50 per ~~Mcf~~MMBtu in ~~March 2016~~July 2020 to a high of ~~$3.93~~$3.64 per ~~Mcf~~MMBtu in January ~~2017,~~2019, and during this period our production was ~~89%~~79% and ~~90%~~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 ~~our exploration and production business,~~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 ~~2016,~~2020, we reported non-cash impairment charges on our natural gas and oil properties totaling ~~$2.3 billion,~~$2,825 million, primarily resulting from decreases in trailing 12-month average first-day-of-the-month natural gas prices throughout ~~2016,~~2020, as compared to ~~2015,~~2019, and the non-cash impairment of certain undeveloped leasehold interests. Further non-cash impairments in ~~subsequent~~future periods could occur if the trailing 12-month commodity prices ~~continue to fall~~decrease as compared to the average used in prior periods.

~~In our Midstream segment, lower production by us and others can mean reduced volumes being transported in the gathering systems we operate and thus lower revenues.~~

As of December 31, ~~2017,~~2020, we had ~~$4.4~~$3.2 billion of debt outstanding, consisting principally of ~~$3.2 billion in~~ senior notes maturing in various increments from ~~2020~~2022 to ~~2027~~2028, and ~~$1.2 billion~~$700 million of borrowings under our revolving credit facility, which matures in ~~a term loan due in 2020.~~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~~“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 ~~in the~~

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~~past three years~~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 ~~the middle of 2014~~2015 could significantly increase our revenues, profits and cash flow, which could be used to expand capital investments.

~~Significant~~

Significant capital investment is required to replace our reserves and conduct our business.

Our activities require substantial capital ~~investment.~~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, ~~and~~ acquiring new acreage and a loss of ~~properties and~~existing leased acreage, resulting in a decline in our cash flow from operations and natural gas, oil and NGL production and reserves.

Ifwe are notnot 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 ~~exploration,~~ development, acquisition or ~~acquisition~~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 ~~the Appalachian Basin~~Appalachia or that we will be able to obtain sufficient transportation capacity on economic terms. During the past ~~two~~few years, several planned pipelines intended to service production in the ~~U.S.~~ Northeast United States have ~~been cancelled or had~~experienced delays in their in-service dates ~~delayed~~ 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.

~~A further downgrade~~

We have entered into gathering agreements in ~~our credit rating could negatively impact our cost of~~producing areas 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 further review for a downgrade, could impact our ability to access debt markets in the future, affect the market value of our senior notes and increase our corporate borrowing costs. Such ratings are limited in scope, and do not address all material risksmultiple long-term firm transportation agreements relating to ~~us, but rather reflect only the view of each rating agency at the time the rating is issued of the likelihood we will be able to repay~~natural gas volumes from all our ~~debt. An explanation of the significance of each rating may be obtained from the applicable rating agency.~~producing areas. As of ~~February 27, 2018,~~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 ~~were rated Ba3 by Moody’s, BB- by Standard~~would be required to pay demand or other charges for transportation on pipelines and ~~Poor’s and BB by Fitch Investor Services.~~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 ~~such credit ratings~~these measures will ~~remain in effect for any given period~~recoup the full cost 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 liquidity. 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 $323 million of letters of credit outstanding at December 31, 2017. The amount of additional security would depend on the severity of the

unused transportation.

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~~downgrade from the credit rating agencies, and a downgrade could result in a decrease in our liquidity.~~

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 ~~only if they~~that are projected to generate ~~a PVI of 1.3 or greater, allocating generally to~~ the highest ~~PVI projects.~~combined Internal Rate of Return. Volatility in prices and potential errors in estimating costs, reserves or timing of production of the reserves ~~could~~can result in uneconomic projects or economic projects generating less than ~~1.3 PVI.~~

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.

Leases on approximately 1,864 net acres of our Fayetteville Shale acreage (excluding 158,231 net acres held on federal lands where activity is currently suspended by the Bureau of Land Management) 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.

Approximately ~~31,536~~19,242 and ~~39,255~~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 ~~estimated~~projected to achieve a ~~PVI~~sufficient return or be judged to be the best use of ~~at least 1.3.~~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 ~~operations~~ and ~~midstream operation~~transportation operations can be hazardous and may expose us to liabilities.

~~Exploration~~

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;~~

•injury or loss of life;

~~pollution or other environmental damage;~~

•severe damage to or destruction of property, natural resources or equipment;

~~clean-up responsibilities;~~

•pollution or other environmental damage;

~~regulatory investigations and administrative, civil and criminal penalties; and~~

•clean-up responsibilities;

~~injunctions resulting in limitation or suspension of operations.~~

•regulatory investigations and administrative, civil and criminal penalties; and

•injunctions resulting in limitation or suspension of operations.

For our ~~non-operated~~ properties that we do not operate, we depend on the operator for operational and regulatory compliance.

~~Our midstream~~

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 pipelines, facilities and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism;

~~damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines;~~

•maintenance, repairs, mechanical or structural failures;

~~disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack; and~~

•damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines;

~~leaks of natural gas or ethane as a result of the malfunction of equipment or facilities.~~

~~Table~~•disruption or failure of ~~Contents~~

~~Index~~information technology systems and network infrastructure due to ~~Financial Statements~~

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.

Wehavemade 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.

Ourcurrent and future levels of ~~indebtedness~~indebtedness may adversely affect our results and limit our growth.

At December 31, ~~2017,~~2020, we had long-term indebtedness of ~~$4.4billion, including borrowings of $1.2 billion under our term loan credit agreement.~~$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;~~

•incurring additional debt;

~~making certain investments;~~

•redeeming stock or redeeming certain debt;

~~creating liens on our assets; and~~

•making certain investments;

~~selling assets.~~

•creating liens on our assets; and

~~Under the~~

•selling assets.

The revolving credit facility we entered into in ~~December 2013, we must keep our~~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 atless cash on hand (up to the lesser of 10% of credit limit or ~~below 60%~~$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 ~~total adjusted book capital. This financial covenant with respect to capitalization percentages~~revolving credit facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from ~~certain full cost ceiling~~ 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 ~~our pension~~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 ~~other post-retirement liabilities. Therefore,~~cash equivalents to $200 million when loans under the ~~2013~~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 ~~our adjusted capital structure as of December 31, 2017 was 31% debt and 69% equity. The term loan and revolving credit facility we entered into~~ in ~~June 2016 contain financial covenants that impose certain restrictions on us. In September 2017, we amended the 2016 credit agreement to reflect the following:~~

~~increase the minimum interest coverage ratio to 2.00x commencing with the fiscal quarter ended June 30, 2017 and continued over the life of the 2016 credit facility;~~

modify the minimum liquidity covenant such that either (1) if leverage is less than 4.00x or if the 2016 revolving credit facility has been terminated, there is no minimum liquidity covenant, or (2) we may elect to replace the minimum liquidity covenant with a maximum leverage ratio of no more than 5.50x for the fiscal quarter ending December 31, 2017, 5.00x for the fiscal quarters ending March 31, 2018 and June 30, 2018 and 4.50x thereafter; and

modify the mandatory prepayment and commitment reduction provisions to permit us to retain the first $500 million of net cash proceeds from asset sales that would have otherwise been required to prepay amounts outstanding under the 2016 revolving credit facility and/or reduce commitments under the 2016 revolving credit facility.

~~Although we do not anticipate any violations of our financial covenants, our~~all material respects. Our ability to comply with these financial covenants depends in part on the success of our ~~exploration and~~ development program and upon factors beyond our control, such as the market prices for natural gas, oil and NGLs.

Although the indentures governing our senior notes contain covenants that apply to us, covenants limiting liens and sale and leaseback covenants contain exceptions and limitations that would allow us, pursuant to the terms of the indenture, to create, grant or incur certain liens or security interests. Moreover, the indentures do not contain any limitations on the ability of us or our subsidiaries to incur debt, pay dividends, make investments, or limit the ability of our subsidiaries to make distributions to us. Such activities may, however, be limited by our other financing agreements in certain circumstances.

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;~~

•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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~~limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and~~

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.

~~detracting from our ability to successfully withstand a downturn in our business or the economy generally.~~

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.

~~If we fail~~

Failure to comply with the covenants and other restrictions it could lead to an event of default and the acceleration of our obligations under ~~the~~our senior notes, credit facilities or ~~our~~ 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, ~~a significant or extended decline~~the occurrence of risks identified elsewhere in ~~natural gas, oil or NGL~~this section, such as declines in commodity prices, ~~would~~increases in basis differentials and inability to access markets, could reduce our profits and thus the cash we have ~~a material adverse effect on~~to fulfill our results of operations, our access to capital and the quantities of natural gas, oil and NGLs that we can produce economically. For example, the New York Mercantile Exchange, or NYMEX, natural gas prices traded at a low of $1.71 per Mcf in March 2016 to a high of $3.93 per Mcf in January 2017 based on the settlement price of the monthly contract at expiration.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.

~~We have made significant investments in pipelines and gathering systems and contracts and in oilfield service businesses, including our drilling rigs, pressure pumping equipment and sand mine operations,~~

Risks Related to lower costs and secure inputs for our operations and transportation for our production. If our exploration 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.

Through December 31, 2017, we had invested approximately $1.3 billion in our gas gathering system built for the Fayetteville Shale. We may make further substantial investments in the expansion of this system. Our ability to recover the costs of these investments depends on production from the Fayetteville Shale, and reduced production volumes, whether due to lower drilling activity due to lower prices or failure to produce significant quantities of gas in relevant timeframes, can adversely affect our ability to recover these investments.

We also have entered into gathering agreements in other producing areas and multiple long-term firm transportation agreements relating to natural gas volumes from all our producing areas. As of December 31, 2017, our aggregate demand charge commitments under these firm transportation agreements and gathering agreements were approximately $9.2 billion. If our development programs fail to produce sufficient quantities of natural gas and ethane within expected timeframes, we could be forced to pay demand or other charges for transportation on pipelines and gathering systems that we would not be using.

We also have made significant investments to meet certain of our field services’ needs, including establishing our own drilling rig operation, sand mine and pressure pumping capability. Reductions in our operating plans caused by the current commodity price environment have impacted our ability to fully utilize some of this equipment and has reduced the need for sand and other services. 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.

With current technology, 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

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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 underground injection wells, a predominant method for disposing of waste water from natural gas and oil activities, to cause seismic activity. 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 operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations, subject to regulatory restrictions relating to seismic activity.

~~Our producing properties are concentrated in two regions, the Appalachian Basin and the Fayetteville Shale, making us vulnerable to risks associated with operating in limited geographic areas.~~

Our producing properties are geographically concentrated in the Fayetteville Shale in Arkansas and the Appalachian Basin in Pennsylvania and West Virginia. At December 31, 2017, 75% of our total estimated proved reserves were attributable to properties located in the Appalachian Basin and 25% in the Fayetteville Shale. As a result of this concentration in two primary regions, 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 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.

Our cost of operations is highly dependent on third-party services, and as activity in our industry increases, competition for these services may increase. Similarly, we must have trained, qualified personnel, and as commodity prices rise, competition for this talent also increases. 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 recover faster than prices for natural gas, as natural gas comprises a far greater percentage of our overall production than it does for most of the companies with whom we compete for talent.

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. ~~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.

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.

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 ~~June 2017, President Trump announced that~~November 2019, the United States ~~intends to withdraw~~formally initiated the process for withdrawing from the Paris Agreement, and to seek negotiations either to reenter the Paris Agreement on different terms or a separate agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four year exit process beginning when it took effect in November 2016, which ~~would result~~resulted in an effective exit date of November 2020. ~~The United States’ adherence to~~However, in January 2021, the ~~exit process and/or the terms on which~~new administration announced that the United States ~~may re-enter~~intends to rejoin the Paris ~~Agreement or a separately negotiated agreement are unclear at this time.~~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.

~~Separate from actual~~

We, our service providers and possible governmental action, certain financial institutions have announced policies to cease investing or to divest 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, 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, increased difficulty in collecting amounts owed to us by our customers and reduced access to credit markets. 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.

~~We ar~~eare 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 ~~natural gas and oil exploration~~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 —~~“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 ~~can~~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. In addition,~~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.

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Failure to comply with laws and regulations ~~may~~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

Ourproved natural gas, oil and NGL reserves are ~~estimates.~~estimates that include uncertainties. Any material ~~inaccuracies in our reserve estimates~~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”~~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.~~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~~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 followed or~~ 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.

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~~Index~~ To the extent we cap or lock prices at specific levels, we would also forgo the ability to ~~Financial Statements~~

realize the higher revenues that would be realized should prices increase.

The impact of changes in market prices for ~~oil,~~ 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.

~~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 certain 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.

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 ~~(“OTC”)~~ 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 ~~December 2016,~~January 2020, the CFTC ~~re-proposed~~proposed new ~~rules~~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 and~~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.

~~Certain aspects of the recently passed comprehensive tax reform bill could adversely affect our business and financial condition.~~

On December 22, 2017, President Trump signed into law H.R. 1 (commonly referred to as the “Tax Cuts and Jobs Act,” or the “Tax Reform”), a comprehensive tax reform bill that significantly reforms the Internal Revenue Code of 1986, as amended. The Tax Reform, among other things, contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate, a partial limitation on the deductibility of business interest expense, limitation of the deduction for certain net operating losses to 80% of current year taxable income for tax years 2018 and beyond, an indefinite net operating loss carryforward, immediate deductions for certain new investments instead of deductions for depreciation expense over time and the modification or repeal of many business deductions and credits. We continue to examine the impact of this legislation, and as certain aspects of it are uncertain and subject to future regulations, we note that

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Risks Related to the ~~Tax Reform could adversely affect our business and financial condition.~~

~~Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production~~Merger

Southwestern 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~~not achieve 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;~~

~~elimination of the deduction for certain domestic production activities; and~~

~~extension of the amortization period for certain geological and geophysical expenditures.~~

~~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, 2017, we had substantial amounts of net operating loss carryforwards for U.S. federal and state income tax purposes. Limitations may exist upon use of these carryforwards in the event that a change in controlanticipated benefits of the ~~Company occurs. Additionally, due to~~Merger, and the ~~Tax Reform’s permanent reduction~~Merger may disrupt its current plans or operations.

The success of the ~~corporate income tax rate, we were required~~Merger will depend, in part, on Southwestern’s ability to ~~write down our deferred tax assets (including our net operating loss carryforwards),~~realize the anticipated benefits and ~~there may be other material adverse effects on our deferred tax assets resulting~~cost savings from ~~the Tax Reform that we have not yet identified.~~

A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. At December 31, 2017, we recorded a valuation allowance against our entire deferred tax asset, including the portion related to the remaining net operating loss carryforwards. This allowance was recorded primarily as a result of cumulative book losses experienced over the three-year period ending December 31, 2016. If we experience additional book losses, we may be required to increase our valuation allowance against our deferred tax assets.

~~Our existing deferred tax asset valuation allowance may also be reversed if significant events occur or market conditions change materially,~~combining Southwestern’s and our current or future earnings are, or are projected to be, significantly higher than we currently estimate. This reversal may result in a significant one-time favorable impact positively affecting our consolidated results of operations for the period of reversalMontage’s businesses, and ~~for the full fiscal year results.~~

~~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. 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 business associates, including vendors, service providers, purchasers of our production, and financial institutions are also dependent on digital technology.

A cyber-attack involving our information systems and related infrastructure, or that of our business associates, 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~~

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~~information could have a negative impact on our ability to compete for natural gas and oil resources;~~

~~unauthorized access to personal identifying information of royalty owners, 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.~~

~~To date we have not experienced any material losses relating to cyber-attacks; however,~~ there can be no assurance that weSouthwestern and Montage will ~~not suffer such losses~~be able to successfully integrate or otherwise realize the anticipated benefits of the Merger. Difficulties in integrating Southwestern and Montage may result in the ~~future. As cyber threats continue~~combined company performing differently than expected, in operational challenges, or in the failure to ~~evolve, we~~realize anticipated expense-related efficiencies. Potential difficulties that may be ~~required~~encountered in the integration process include, among others:

•the inability to ~~expend significant additional resources to continue to modify or enhance our protective measures or to investigate~~successfully integrate Montage in a manner that permits the achievement of full revenue, expected cash flows and ~~remediate any information security vulnerabilities.~~

~~Terrorist activities could materially and adversely affect our business and results of operations.~~

~~Terrorist attacks~~cost savings anticipated from the Merger;

•not realizing anticipated operating synergies;

•integrating personnel from the two companies and the ~~threat~~loss of ~~terrorist attacks, whether domestic~~key employees;

•potential unknown liabilities and unforeseen expenses or ~~foreign attacks,~~delays associated with and following the completion of the Merger;

•integrating relationships with customers, vendors and business partners;

•performance shortfalls as ~~well as military or other actions taken in response to these acts, could cause instability in~~a result of the ~~global financial~~diversion of management’s attention caused by completing the Merger and ~~energy markets. Continued hostilities in the Middle East~~integrating Montage’s operations; 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~~loss of momentum in, Southwestern’s ongoing business or ~~an indirect casualty of an act of terrorism,~~inconsistencies in standards, controls, procedures and ~~in turn, could materially and adversely affect our business and results of operations.~~

~~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 hydraulic fracturing, seismicity, oil spills and explosions of natural gas 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 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.

~~Common stockholders will be diluted if additional shares are issued.~~

From time to time we have issued stock to raise capital for our business, including significant offerings of new shares in 2015 and 2016. 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.

policies.

~~Table of Contents~~

~~Index to Financial Statements~~

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. ~~PROPERTIES~~

PROPERTIES

The summary of our oil and natural gas reserves as of fiscal year-end ~~2017~~2020 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed ~~“2017~~“2020 Proved Reserves by Category and Summary Operating Data” in ~~“Business~~“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~~“Proved Undeveloped Reserves” in ~~“Business~~“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,~~“Sales, Delivery Commitments and Customers” in the ~~“Business~~“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”~~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 ~~Investments.~~Investing.” We also refer you to Item 6,~~, “Selected~~ “Selected Financial ~~Data”~~Data” in Part II of this Annual Report for information concerning natural gas, oil and NGLs produced.

Table of Contents

Index to Financial Statements

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, ~~2017~~

Undeveloped

Developed

Total

Gross

Net

Gross

Net

Gross

Net
Northeast Appalachia
113,298

87,927

108,422

103,299

221,720

191,226
Southwest Appalachia
443,328

219,709

100,244

70,582

543,572

290,291
Fayetteville Shale (1)
504,484

424,858

849,280

492,984

1,353,764

917,842
Other:

US – Other Exploration
534,265

202,911

–

–

534,265

202,911
US – Brown Dense
131,043

97,234

7,604

6,377

138,647

103,611
US – Sand Wash Basin
97,120

69,091

15,028

10,691

112,148

79,782
Canada – New Brunswick (2)
2,518,519

2,518,519

–

–

2,518,519

2,518,519

4,342,057

3,620,249

1,080,578

683,933

5,422,635

4,304,182

~~(1)~~

~~Fayetteville Shale gross acres includes additional developable lands as a result of Arkansas Oil & Gas Commission Integration Orders.~~

2020

~~(2)~~

Undeveloped Developed Total
Gross Net Gross Net Gross Net
Northeast Appalachia 107,465 89,086 134,449 128,210 241,914 217,296
Southwest Appalachia 610,969 425,702 186,390 146,220 797,359 571,922
Other:
US – Other Exploration 9,652 6,329 5,034 2,263 14,686 8,592
US – Sand Wash Basin 5,898 3,435 14,977 9,974 20,875 13,409
Total US 733,984 524,552 340,850 286,667 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.~~

~~Table of Contents~~

~~Index~~ to ~~Financial Statements~~

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:

~~(1)~~

~~Of this acreage, 2,666 net acres in 2018, 5,907 net acres in 2019 and 1,850 net acres in 2020 can be extended for an average of 5.9 years.~~

~~(2)~~

~~This excludes 158,231 net acres held on federal lands which are currently suspended by the Bureau of Land Management.~~


	For the years ended December 31,
Net acreage expiring:	2021	2022	2023
Northeast Appalachia	5,861	6,460	6,921
Southwest Appalachia (1)	36,690	20,149	11,986
Other:
US – Other Exploration	5,683	646	—
US – Sand Wash Basin	3,435	—	—
Canada – New Brunswick (2)	2,518,519	—	—

~~(3)~~

~~Exploration licenses for 2,518,519 net acres were extended through 2021 but have been subject to a moratorium since 2015.~~

(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, ~~2017~~

2020

Natural Gas

Oil

Total

Gross Wells

Gross

Net

Gross

Net

Gross

Net

Operated
Appalachia:

Northeast
600

531

–

–

600

531

538
Southwest
387

272

–

–

387

272

360
Fayetteville Shale
4,698

3,243

–

–

4,698

3,243

4,033
Other
10

7

14

14

24

21

22

5,695

4,053

14

14

5,709

4,067

4,953


	Natural Gas		Oil		Total		Gross Wells Operated
	Gross	Net	Gross	Net	Gross	Net
Northeast Appalachia	744	668	—	—	744	668	677
Southwest Appalachia	1,796	1,487	37	34	1,833	1,521	1,670
Other	8	5	6	6	14	11	14
	2,548	2,160	43	40	2,591	2,200	2,361

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Index to Financial Statements

The information regarding drilling and other exploratory and development activities required by Item 1205 of Regulation S-K is set forth below:

Exploratory

Productive Wells

Dry Wells

Total
Year

Gross

Net

Gross

Net

Gross

Net
2017

Appalachia:

Northeast

–

–

–

–

–

–
Southwest

–

–

–

–

–

–
Fayetteville Shale

–

–

–

–

–

–
Other

1.0

1.0

–

–

1.0

1.0
Total

1.0

1.0

–

–

1.0

1.0
2016

Appalachia:

Northeast

1.0

1.0

–

–

1.0

1.0
Southwest

–

–

–

–

–

–
Fayetteville Shale

–

–

–

–

–

–
Other

–

–

–

–

–

–
Total

1.0

1.0

–

–

1.0

1.0
2015

Appalachia:

Northeast

1.0

1.0

–

–

1.0

1.0
Southwest

–

–

–

–

–

–
Fayetteville Shale

–

–

–

–

–

–
Other

2.0

2.0

–

–

2.0

2.0
Total

3.0

3.0

–

–

3.0

3.0


	Exploratory
	Productive Wells		Dry Wells		Total
Year	Gross	Net	Gross	Net	Gross	Net
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 Wells		Dry Wells		Total
Year	Gross	Net	Gross	Net	Gross	Net
2020
Northeast Appalachia	45.0	44.4	—	—	45.0	44.4
Southwest Appalachia	55.0	44.6	—	—	55.0	44.6
Total	100.0	89.0	—	—	100.0	89.0
2019
Northeast Appalachia	44.0	41.7	—	—	44.0	41.7
Southwest Appalachia	69.0	53.5	—	—	69.0	53.5
Total	113.0	95.2	—	—	113.0	95.2
2018
Northeast Appalachia	60.0	59.5	—	—	60.0	59.5
Southwest Appalachia	76.0	59.3	—	—	76.0	59.3
Fayetteville Shale (1)	2.0	1.8	—	—	2.0	1.8
Total	138.0	120.6	—	—	138.0	120.6

(1)The Fayetteville Shale E&P assets were sold in December 2018.

Table of Contents

Index to Financial Statements

Development

Productive Wells

Dry Wells

Total
Year

Gross

Net

Gross

Net

Gross

Net
2017

Appalachia:

Northeast

83.0

80.8

–

–

83.0

80.8
Southwest

57.0

43.6

–

–

57.0

43.6
Fayetteville Shale

25.0

24.1

–

–

25.0

24.1
Other

–

–

–

–

–

–
Total

165.0

148.5

–

–

165.0

148.5
2016

Appalachia:

Northeast

23.0

22.9

–

–

23.0

22.9
Southwest

18.0

13.4

–

–

18.0

13.4
Fayetteville Shale

43.0

35.2

–

–

43.0

35.2
Other

–

–

–

–

–

–
Total

84.0

71.5

–

–

84.0

71.5
2015

Appalachia:

Northeast

99.0

98.5

–

–

99.0

98.5
Southwest

63.0

36.6

–

–

63.0

36.6
Fayetteville Shale

265.0

209.4

–

–

265.0

209.4
Other

–

–

–

–

–

–
Total

427.0

344.5

–

–

427.0

344.5

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, ~~2017~~

2020

Gross

Net
Drilling:

Appalachia:

Northeast
42.0

42.0
Southwest
23.0

18.3
Fayetteville Shale
−

−
Other
–

–
Total
65.0

60.3
Completing:

Appalachia:

Northeast
10.0

10.0
Southwest
17.0

12.7
Fayetteville Shale
−

−
Other
–

–
Total
27.0
(1)
22.7
Drilling & Completing:

Appalachia:

Northeast
52.0

52.0
Southwest
40.0

31.0
Fayetteville Shale
−

−
Other
–

–
Total
92.0

83.0


	Gross	Net
Drilling:
Northeast Appalachia	16.0	15.6
Southwest Appalachia	14.0	13.6
Total	30.0	29.2
Completing:
Northeast Appalachia	10.0	10.0
Southwest Appalachia	2.0	1.8
Total	12.0	11.8
Drilling & Completing:
Northeast Appalachia	26.0	25.6
Southwest Appalachia	16.0	15.4
Total	42.0	41.0

~~(1)~~

~~Includes 19 gross wells that are waiting on pipeline or production facilities.~~

Table of Contents

Index to Financial Statements

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,							For the years ended December 31,
	2017		2016		2015			2020		2019		2018
Natural Gas							Natural Gas
Production (Bcf):							Production (Bcf):
Northeast Appalachia		395		350		360	Northeast Appalachia	473		459		459
Southwest Appalachia		85		62		67	Southwest Appalachia	221		150		105
Fayetteville Shale		316		375		465
Other		1		1		7
Fayetteville Shale (1)							Fayetteville Shale (1)	—		—		243

Total		797		788		899	Total	694		609		807

Average realized gas price per Mcf, excluding derivatives:
Average realized gas price, excluding derivatives ($/Mcf):							Average realized gas price, excluding derivatives ($/Mcf):
Northeast Appalachia	$	2.11	$	1.34	$	1.62	Northeast Appalachia	$	1.37	$	2.10	$	2.54
Southwest Appalachia		2.28		1.71		1.92	Southwest Appalachia	$	1.27	$	1.62	$	2.58
Fayetteville Shale		2.35		1.80		2.12
Fayetteville Shale (1)							Fayetteville Shale (1)	$	—	$	—	$	2.21
Total	$	2.23	$	1.59	$	1.91	Total	$	1.34	$	1.98	$	2.45

Average realized gas price per Mcf, including derivatives	$	2.19	$	1.64	$	2.37
Average realized gas price, including derivatives ($/Mcf):							Average realized gas price, including derivatives ($/Mcf):	$	1.70	$	2.18	$	2.35

Oil							Oil
Production (MBbls):							Production (MBbls):
Southwest Appalachia		2,228		2,041		2,036	Southwest Appalachia	5,124		4,673		3,355
Other		99		151		229	Other	17		23		52
Total		2,327		2,192		2,265	Total	5,141		4,696		3,407

Average realized oil price per Bbl:
Average realized oil price, excluding derivatives ($/Bbl):							Average realized oil price, excluding derivatives ($/Bbl):
Southwest Appalachia	$	42.93	$	30.59	$	31.80	Southwest Appalachia	$	29.18	$	46.86	$	56.71
Other		47.38		39.44		46.21	Other	$	37.24	$	53.66	$	62.01
Total	$	43.12	$	31.20	$	33.25	Total	$	29.20	$	46.90	$	56.79

Average realized oil price, including derivatives ($/Bbl):							Average realized oil price, including derivatives ($/Bbl):	$	46.91	$	49.56	$	56.07

NGL							NGL
Production (MBbls):							Production (MBbls):
Southwest Appalachia		14,193		12,317		10,640	Southwest Appalachia	25,923		23,611		19,679
Other		52		55		62	Other	4		9		27
Total		14,245		12,372		10,702	Total	25,927		23,620		19,706

Average realized NGL price per Bbl, excluding derivatives:
Average realized NGL price, excluding derivatives ($/Bbl):							Average realized NGL price, excluding derivatives ($/Bbl):
Southwest Appalachia	$	14.42	$	7.41	$	6.76	Southwest Appalachia	$	10.24	$	11.59	$	17.89
Other		26.38		17.33		14.51	Other	$	11.50	$	7.61	$	28.12
Total	$	14.46	$	7.46	$	6.80	Total	$	10.24	$	11.59	$	17.91

Average realized NGL price, including derivatives ($/Bbl)							Average realized NGL price, including derivatives ($/Bbl)	$	11.15	$	13.64	$	17.23

Total Production (Bcfe)							Total Production (Bcfe)
Northeast Appalachia		395		350		360	Northeast Appalachia	473		459		459
Southwest Appalachia		183		148		143	Southwest Appalachia	407		319		243
Fayetteville Shale		316		375		465
Fayetteville Shale (1)							Fayetteville Shale (1)	—		—		243
Other		3		2		8	Other	—		—		1
Total		897		875		976
Total (2)							Total (2)	880		778		946

Average Production Cost
Lease Operating Expense							Lease Operating Expense
Cost per Mcfe, excluding ad valorem and severance taxes:							Cost per Mcfe, excluding ad valorem and severance taxes:
Northeast Appalachia	$	0.75	$	0.76	$	0.71	Northeast Appalachia	$	0.86	$	0.85	$	0.81
Southwest Appalachia		1.07		1.05		1.39	Southwest Appalachia	$	1.00	$	1.02	$	1.08
Fayetteville Shale		0.97		0.89		0.91
Fayetteville Shale (1)							Fayetteville Shale (1)	$	—	$	—	$	0.98
Total	$	0.90	$	0.87	$	0.92	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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Index to Financial Statements

(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 ~~2017,~~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”~~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.

~~Table of Contents~~

~~Index to Financial Statements~~

~~Miles of Pipe~~

~~As of December 31, 2017, our Midstream segment had 2,045 miles and 16 miles of pipe in its gathering systems located in Arkansas and Louisiana, respectively.~~

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. ~~Substantially all our Fayetteville Shale properties are subject to liens securing the credit facility we entered into in 2016.~~ 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, ~~and~~employment matters, traffic incidents, pollution, contamination, encroachment on others’ property or nuisance. ~~Management~~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 ~~such~~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.~~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 accrue for such items when a liability is both probable and the amount can be reasonably estimated.~~

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”~~“Litigation” in Note 810, ~~“Commitments and Contingencies”~~ in 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, ~~in support of our E&P business are~~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.

Table of Contents

Index to Financial Statements

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 ~~27, 2018,~~25, 2021, the closing price of our common stock trading under the symbol “SWN” was ~~$3.69~~$4.22 and we had ~~3,202~~2,269 stockholders of record. ~~The following table presents, for each of the periods indicated, the high and low reported sales prices for our common stock trading under the symbol “SWN” as reported on the NYSE:~~

Range of Market Prices
Quarter Ended

2017

2016

2015

High

Low

High

Low

High

Low
March 31

$
10.68

$
7.20

$
9.90

$
5.30

$
28.02

$
21.46
June 30

$
8.94

$
5.47

$
15.45

$
7.55

$
29.61

$
22.40
September 30

$
6.39

$
5.00

$
15.59

$
11.42

$
22.84

$
11.84
December 31

$
6.72

$
4.90

$
14.40

$
9.14

$
13.90

$
5.00

We currently do not pay dividends on our common ~~stock.~~

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, ~~2017:~~

2020:

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
October 2017

10,717

$
5.85

n/a

n/a
November 2017

–

$
–

n/a

n/a
December 2017

232,025

$
6.19

n/a

n/a
Total fourth-quarter 2017:

242,742

$
6.17

n/a

n/a


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

October 2020	—	$	—	n/a	n/a
November 2020	—	$	—	n/a	n/a
December 2020	9,961	$	3.02	n/a	n/a
Total fourth-quarter 2020:	9,961	$	3.02	n/a

(1)Reflects shares retired by us to satisfy applicable tax withholding obligations due on employee stock plan share issuances. ~~All changes in common stock in treasury in 2017 were due to purchases and sales of shares held on behalf of participants in a non-qualified deferred compensation supplemental retirement savings plan.~~

Recent Sales of Unregistered Equity Securities

We did not sell any unregistered equity securities during ~~2017, 2016 or 2015. See~~ ~~Item 12~~, ~~“Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,”~~ ~~in Part III of this Annual Report for information regarding our equity compensation plans as of December 31, 2017.~~

2020.

ITEM 6. SELECTED FINANCIAL DATA

None.

Table of Contents

Index to Financial Statements

~~STOCK PERFORMANCE~~ ~~GRAPH~~

The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and our peer group. Our peer group consists of Anadarko Petroleum Corporation, Apache Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Co., Concho Resources Inc., Continental Resources Inc., Denbury Resources Inc., Devon Energy Corporation, EOG Resources, Inc., EQT Corporation, Newfield Exploration Company, Noble Energy, Inc., Pioneer Natural Resources Co., QEP Resources, Inc., Range Resources Corporation, Sandridge Energy, Inc., SM Energy Company, Ultra Petroleum Corp., Whiting Petroleum Corporation and WPX Energy, Inc. The chart assumes that the value of the investment in our common stock and each index was $100 at December 31, 2012, and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance:

12/31/12

12/31/13

12/31/14

12/31/15

12/31/16

12/31/17
Southwestern Energy Company
$
100

$
118

$
82

$
21

$
32

$
17
S&P 500 Index

100

132

151

153

171

208
Peer Group

100

132

112

74

108

97

~~Table of Contents~~

~~Index to Financial Statements~~

~~ITEM 6.~~ ~~SELECTED FINANCIAL DATA~~

The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2017. This information and the notes thereto are derived from our consolidated financial statements. We refer you to “~~Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data~~.”

2017

2016

2015

2014

2013

(in millions except shares, per share, stockholder data and percentages)
Financial Review

Operating revenues:

Exploration and production

$
2,086

$
1,413

$
2,074

$
2,862

$
2,404
Midstream

3,198

2,569

3,119

4,358

3,347
Intersegment revenues

(2,081)

(1,546)

(2,060)

(3,182)

(2,380)

3,203

2,436

3,133

4,038

3,371
Operating costs and expenses:

Marketing purchases – midstream

976

864

852

980

782
Operating and general and administrative expenses

904

839

935

648

519
Restructuring charges

–

78

–

–

–
Depreciation, depletion and amortization

504

436

1,091

942

787
Impairment of natural gas and oil properties

–

2,321

6,950

–

–
Gain on sale of assets, net

(6)

–

(283)

–

–
Taxes, other than income taxes

94

93

110

95

79

2,472

4,631

9,655

2,665

2,167
Operating income (loss)

731

(2,195)

(6,522)

1,373

1,204

Interest expense, net

135

88

56

59

42

Gain (loss) on derivatives

422

(339)

47

139

26
Loss on early extinguishment of debt

(70)

(51)

–

–

–
Other income (loss), net

5

1

(30)

(4)

2

Income (loss) before income taxes

953

(2,672)

(6,561)

1,449

1,190
Provision (benefit) for income taxes:

Current

(22)

(7)

(2)

21

(11)
Deferred

(71)

(22)

(2,003)

504

497

(93)

(29)

(2,005)

525

486

Net income (loss)

1,046

(2,643)

(4,556)

924

704
Mandatory convertible preferred stock dividend

108

108

106

–

–
Participating securities – mandatory convertible preferred stock

123

–

  –

–

–
Net income (loss) attributable to common stock

$
815

$
(2,751)

$
(4,662)

$
924

$
704

Net cash provided by operating activities

$
1,097

$
498

$
1,580

$
2,335

$
1,909
Net cash used in investing activities

$
(1,252)

$
(162)

$
(1,638)

$
(7,288)

$
(2,216)
Net cash provided by (used in) financing activities

$
(352)

$
1,072

$
20

$
4,983

$
277

Common Stock Statistics

Earnings per share:

Net income (loss) attributable to common stockholders – Basic

$
1.64

$
(6.32)

$
(12.25)

$
2.63

$
2.01
Net income (loss) attributable to common stockholders – Diluted

$
1.63

$
(6.32)

$
(12.25)

$
2.62

$
2.00
Book value per average diluted share

$
3.95

$
2.11

$
6.00

$
13.23

$
10.32
Market price at year-end

$
5.58

$
10.82

$
7.11

$
27.29

$
39.33
Number of stockholders of record at year-end

3,216

3,292

3,415

3,271

3,259
Average diluted shares outstanding

500,804,297

435,337,402

380,521,039

352,410,683

351,101,452

~~Table of Contents~~

~~Index to Financial Statements~~

2017

2016

2015

2014

2013
Capitalization (in millions)

Total debt
$
4,391

$
4,653

$
4,705

$
6,957

$
1,940
Total equity

1,979

917

2,282

4,662

3,622
Total capitalization
$
6,370

$
5,570

$
6,987

$
11,619

$
5,562
Total assets
$
7,521

$
7,076

$
8,086

$
14,915

$
8,037
Capitalization ratios:

Debt

69%

84%

67%

60%

35%
Equity

31%

16%

33%

40%

65%

Capital Investments (in millions) (1)

Exploration and production

1,248

623

2,258

7,254

2,052
Midstream services

32

21

167

144

158
Other

13

4

12

49

25

$
1,293

$
648

$
2,437

$
7,447

$
2,235

Exploration and Production

Natural gas:

Production (Bcf)

797

788

899

766

656
Average realized price per Mcf, including derivatives
$
2.19

$
1.64

$
2.37

$
3.72

$
3.65
Average realized price per Mcf, excluding derivatives
$
2.23

$
1.59

$
1.91

$
3.74

$
3.17
Oil:

Production (MBbls)

2,327

2,192

2,265

235

138
Average price per barrel
$
43.12

$
31.20

$
33.25

$
79.91

$
103.32
NGL:

Production (MBbls)

14,245

12,372

10,702

231

50
Average price per barrel, including derivatives
$
14.48

$
7.46

$
6.80

$
15.72

$
43.63
Average price per barrel, excluding derivatives
$
14.46

$
7.46

$
6.80

$
15.72

$
43.63
Total production (Bcfe)

897

875

976

768

657

Lease operating expenses per Mcfe
$
0.90

$
0.87

$
0.92

$
0.91

$
0.86
General and administrative expenses per Mcfe
$
0.22
(2)
$
0.22
(3)
$
0.21

$
0.24

$
0.24
Taxes, other than income taxes per Mcfe
$
0.10

$
0.10
(4)
$
0.10

$
0.11

$
0.10
Proved reserves at year-end:

Natural gas (Bcf)

11,126

4,866

5,917

9,809

6,974
Oil (MMBbls)

65.6

10.5

8.8

37.6

0.4
NGLs (MMBbls)

542.4

53.9

40.9

118.7

–
Total reserves (Bcfe)

14,775

5,253

6,215

10,747

6,976

Midstream Services

Volumes marketed (Bcfe)

1,067

1,062

1,127

904

786
Volumes gathered (Bcf)

499

601

799

963

900

~~(1)~~

Capital investments include an increase of $43 million for 2016, a decrease of $33 million for 2015, an increase $155 million for 2014, and a decrease of $25 million for 2013, related to the change in accrued expenditures between years. There was no impact to 2017.

~~(2)~~

~~Excludes $5 million of legal settlements for 2017.~~

~~(3)~~

~~Excludes $83 million of restructuring and other one-time charges for 2016.~~

~~(4)~~

~~Excludes $3 million of restructuring charges for 2016.~~

~~Table of Contents~~

~~Index to Financial Statements~~

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSOF OPERATIONS

Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. In many cases you can identify forward-looking statements by words such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “target” or similar words. Unless required to do so under the federal securities laws, the Company does not undertake to update, revise or correct any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “Cautionary Statement about Forward-Looking Statements.”

~~OVERVIEW~~

OVERVIEW

Background

Southwestern Energy Company (including its subsidiaries, collectively, ~~“we”, “our”, “us”,~~“we,” “our,” “us,” “the Company” or “Southwestern”) is an independent energy company engaged in natural gas, oil and ~~NGL~~NGLs exploration, development and production, which we refer to as “E&P.” We are also focused on creating and capturing additional value through our ~~natural gas gathering and~~ marketing ~~businesses,~~business, which we ~~refer to as “Midstream.”~~call “Marketing”. We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the lower 48 United States.

~~Exploration and Production~~.

E&P. Our primary business is the exploration for and production of natural gas, oil and NGLs, with our ~~current~~ongoing operations focused on the development of unconventional natural gas reservoirs located in Pennsylvania, Ohio and West ~~Virginia and Arkansas.~~Virginia. Our operations in northeast Pennsylvania, which we refer to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Our operations in West Virginia, Ohio and southwest Pennsylvania, which we refer to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. ~~Our operations~~Collectively, our properties in ~~Arkansas~~Pennsylvania, Ohio and West Virginia are ~~primarily focused on an unconventional natural gas reservoir known~~herein referred to as ~~the Fayetteville Shale. We have smaller holdings in Colorado and Louisiana, along with other areas in which we are testing potential new resources.~~“Appalachia.” We also have drilling rigs located in ~~Pennsylvania, West Virginia and Arkansas,~~Appalachia, and we provide certain oilfield products and services, principally serving our E&P ~~operations.~~

~~Midstream~~operations though vertical integration.

On November 13, 2020, we closed on our Agreement and Plan of Merger (the “Merger agreement”) with Montage Resources Corporation (“Montage”) pursuant to which Montage merged with and into Southwestern, with Southwestern continuing as the surviving company (the “Merger”). ~~Through~~The Merger expanded our ~~affiliated midstream subsidiaries, we engage~~footprint in ~~natural gas gathering activities in Arkansas~~Appalachia by supplementing our Northeast Appalachia and ~~Louisiana. These activities primarily support our E&P~~Southwest Appalachia operations and ~~generate revenue from fees associated with~~by expanding our operations into Ohio. See Note 3 to the ~~gathering~~consolidated financial statements of ~~natural gas.~~this Annual Report for more information on the Merger.

Marketing. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil, and NGLs primarily produced in our E&P operations.

~~In 2017,~~

Focus in 2020. We entered 2020 with a continued focus on optimizing our cost structure, maximizing margins in each of our core areas of business while further developing our knowledge of our asset base and looking for strategic transactions that take advantage of our core strengths. The recent Merger and the associated expected cost and operational synergies is a reflection of this strategy. While COVID-19 brought challenges of lower demand for certain of our products resulting in lower oil and NGL pricing (discussed below), we ~~focused~~exercised our capital and operational agility by quickly shifting our investments to our higher return natural gas assets. We remained committed to our focus on creating sustainable value with the goal of generating cash flow above and beyond our operational needs, while at the same time maintaining our leading position as stewards of the environment. We continued to protect our financial strength through bond repurchases at a discount as well as a robust derivative program designed to ensure certain cash flow levels by reducing our exposure to commodity price volatility.

Lower natural gas, oil and NGL prices present challenges to our industry and our Company, as do changes in laws, regulations and investor sentiment and other key factors described under “Risk Factors” in Item 1A of this Annual Report. During the year ended December 31, 2020, the economic impact of the COVID-19 pandemic and related governmental and societal measures (discussed below), along with the disagreements between OPEC and Russia on production levels, caused oil prices to decrease significantly in the first and second quarters of 2020. While oil pricing partially recovered late in the second quarter and continued to improve toward the end of the year, gains on our ~~core strategies~~settled derivatives offset a large portion of ~~capital discipline, operational and technical excellence, margin expansion, strengthening~~ the ~~balance sheet and risk management. Our 2017 capital investment program was fully funded from our operating cash flows, supplemented by~~impact of the ~~remaining proceeds from our July 2016 equity issuance. We made technological advances~~overall decline in drilling precision and completion optimization that enhanced well productivity and economics, resulting in improved returns. We improved our debt maturity profile, leaving approximately $92 million in bond debt due priorprices. Although we currently expect to ~~2022 with no significant other debt maturities expected before December 2020, and added to our~~maintain a robust rolling three-year derivative portfolio, ~~protecting approximately 489 Bcf and 201 Bcf of our forecasted 2018 and 2019 natural gas production, respectively, from price volatility through the use of commodity derivatives.~~

there can be no

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Index to Financial Statements

assurance that we will be able to add derivative positions to cover our expected production at favorable prices. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7 A and Note 6 - Derivatives and Risk Management, in the consolidated financial statements included in this Annual Report for further details.

Market Conditions and Commodity Prices

During 2020, we did not experience any material impact to our ability to operate or market our production due to the direct or indirect impacts of the COVID-19 pandemic. In early March 2020, we instituted additional health measures at our facilities and banned nonessential travel. In mid-March, in advance of state and local governments restricting business operations and imposing “stay-at-home” directives in Pennsylvania, West Virginia and Texas (where our operations and offices are located), we notified employees that those whose work does not require a physical presence should work from home. In late September 2020, based on the totality of the relevant data in each community, we reinstituted a phased return program of office-based employees, and we have instituted additional measures designed to prevent the possible spread of the virus, including social distancing and appropriate personal protective equipment. The U.S. Department of Homeland Security classifies individuals engaged in and supporting exploration for and production of natural gas, oil and NGLs as “essential critical infrastructure workforce,” and to date, state and local governments have followed this guidance and exempted these activities from business closures. Should this situation change, our access to supplies or workers to drill, complete and operate wells could be materially and adversely affected.

Beginning late in the first quarter and extending through most of 2020, decreased transportation, manufacturing and general economic activity levels prompted by governmental and societal actions to COVID-19 reduced the demand for refined products such as gasoline, distillate and jet fuel and other refined products, as well as NGLs. Reduced demand, along with geopolitical events such as the disagreements between OPEC and Russia on production levels, caused a significant decline in oil and NGL pricing late in the first quarter of 2020. Although WTI prices for oil were 31% lower in 2020, as compared to 2019, our average realized price received for oil, including the impact of our derivatives, was only 5% lower in 2020, compared to the previous year. We recognized an additional $0.36 per Mcf on our gas production through our derivative program for the year ended December 31, 2020, an increase of $0.16 per Mcf over the prior year, which partially offset a $0.55 decrease in the NYMEX price over the same period.

Late in the second quarter of 2020 and extending into the fourth quarter of 2020, certain states and local governments began the process of loosening restrictions, allowing businesses to reopen and lifting stay-at-home orders. In addition, OPEC and other countries instituted oil production curtailments. During this same period, oil and NGL prices have improved from historic lows in April due to lower industry-wide production levels and increased export demand, respectively. Further, although the reduced production of natural gas associated with oil wells dampened the effect of lower natural gas demand early in the second quarter, high natural gas storage inventories and lower LNG demand for U.S. cargoes led to a natural gas price decline late in the second quarter. During the third quarter of 2020, as more clarity emerged regarding the projected path for European natural gas storage, global LNG prices rallied substantially and signaled a resumption of U.S. LNG exports beginning in late September 2020. In addition, the recovery of U.S. natural gas production was less robust than most market estimates, which kept storage balances below capacity through the end of the injection season in October 2020. As a result of these events, the demand and related pricing for natural gas have improved from earlier in the year, and we continue to mitigate pricing risk for all of our commodities through our proactive derivative program.

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 uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the effectiveness of the vaccines and 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. We will continually monitor our 2021 capital investment program to take into account these changed conditions and proactively adjust our activities and plans. Therefore, while this continued matter could potentially disrupt our operations, the degree of the potentially adverse financial impact cannot be reasonably estimated at this time.

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Index to Financial Statements

Recent Financial and Operating Results

Significant operating and financial highlights for ~~2017~~2020 include:

Total Company

Net income attributable to common stock of $816 million, or $1.63 per diluted share, improved substantially from a net loss attributable to common stock of $2,751 million, or ($6.32) per diluted share, in 2016.

~~Net cash provided by operating activities of $1,097 million was up 120% from $498 million in 2016.~~

~~Total capital investing of $1,293 million was up 100% from $648 million in 2016.~~

~~We retired the remaining outstanding balance of $316 million of our near-term senior notes due 2017 and 2018.~~

We extended the maturities on our debt profile by issuing approximately $1.15 billion in senior notes due 2026 and 2027 and using the net proceeds to repurchase $758 million of our senior notes due 2020 and to repay the outstanding balance of $327 million on our 2015 Term Loan.

~~Exploration~~•Completion of the Merger with Montage on November 13, 2020, acquiring approximately 1,375 producing wells and ~~Production~~

approximately 320,000 net acres.

~~E&P segment operating income of $549 million improved substantially from an operating loss of $2,404 million in 2016.~~

•Completion of a public offering of 63,250,000 shares of common stock at $2.50 per share with net proceeds of approximately $152 million after underwriting discounts and offering expenses.

~~Year-end reserves of 14,775 Bcfe increased 181% from 5,253 Bcfe at the end of 2016.~~

•Closed an offering of $350 million aggregate principal amount of 8.375% senior notes due 2028 with net proceeds of $345 million after underwriting discounts and offering expenses.

~~Total net production from our Appalachian Basin of 578 Bcfe was up 16% from 498 Bcfe in 2016.~~

•Net loss of $3,112 million, or ($5.42) per diluted share, was down from a net income of $891 million, or $1.65 per diluted share, in 2019. The decrease in 2020 was primarily due to $2,825 million of non-cash full cost ceiling test impairments, an $818 million change in deferred tax provision and lower margins associated with reduced commodity prices.

~~Realized NGL prices increased 94% from 2016.~~

•Operating loss was $2,871 million for the year ended December 31, 2020, compared to an operating income of $270 million in 2019, primarily due to a $2,825 million non-cash full cost ceiling test impairment in 2020. Excluding the non-cash impairment, operating loss of $46 million decreased $316 million as increased natural gas and liquids production, lower depreciation, depletion and amortization and general and administrative expense were more than offset by reduced commodity prices along with merger-related expenses.

•Net cash provided by operating activities of $528 million decreased 45% from $964 million in 2019 as an improvement in settled derivatives and the impact of higher production was more than offset by lower commodity prices and an increase in operating expenses associated with higher liquids production, along with decreases in capitalized interest expense and working capital.

•Total capital invested of $899 million decreased 21% from $1,140 million in 2019.

E&P

•E&P segment operating loss was $2,864 million in 2020, compared to an operating income of $283 million in 2019. The decrease in 2020 was primarily due to non-cash full cost ceiling impairments of $2,825 million in 2020 and reduced commodity prices.

•Year-end reserves of 11,990 Bcfe decreased 731 Bcfe, or 6%, from 12,721 Bcfe at the end of 2019, as 2,354 Bcfe of acquired reserves, 1,424 Bcfe of positive performance revisions and 741 Bcfe of additions were more than offset by 4,370 Bcfe of downward price revisions and 880 Bcfe of production.

•Total net production of 880 Bcfe, which was comprised of 79% natural gas, 17% NGLs and 4% oil, increased 13% from 778 in 2019, and our liquids production increased 10% over the same period.

•Excluding the effect of derivatives, our realized natural gas price of $1.34 per Mcf, realized oil price of $29.20 per barrel and realized NGL price of $10.24 per barrel decreased 32%, 38% and 12%, respectively, from 2019. Our weighted average realized price excluding the effect of derivatives of $1.53 per Mcfe decreased 30% from the same period in 2019.

•The E&P segment invested $899 million in capital; drilling 98 wells, completing 96 wells and placing 100 wells to sales.

Outlook

In ~~February 2018,~~2021, we announced several strategic steps to reposition our portfolio, sharpen our focus on our highest return assets, strengthen our balance sheet and enhance financial performance. These initiatives include:

~~Actively pursuing strategic alternatives for the Fayetteville Shale E&P and related Midstream gathering assets;~~

~~Identifying and implementing structural, process and organizational changes to further reduce costs; and~~

~~Utilizing funds realized from the foregoing to reduce debt, supplement Appalachian Basin development capital, potentially return capital to shareholders, and for general corporate purposes.~~

We expect to continue to exercise capital discipline in our investment program by ~~aligning our 2018 capital~~ investing ~~program with our expected~~below cash flow from operations, net of changes in working ~~capital. We will also look~~capital, in a focused effort to generate free cash flow. In addition, we expect to continue maintaining our robust hedging program, looking for ~~opportunities~~ways to ~~maximize~~optimize our cost structure and maximizing margins in each core area of our business ~~and~~while further ~~develop~~developing our knowledge of our asset base. By carrying out these objectives, we expect to generate additional free cash flow, which we intend to use to further strengthen our balance sheet. We remain committed to our focus on optimizing our portfolio by concentrating our efforts on our highest return investment opportunities. We believe that ~~2018~~we and our industry will continue to ~~be a challenging year for our business~~face challenges due to the ~~commodity price environment and continued~~ uncertainty of natural gas, oil and NGL prices in the United ~~States.~~

States, changes in laws, regulations and investor sentiment, and other key factors described above under “Risk Factors.”

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Index to Financial Statements

RESULTS OF OPERATIONS

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense, gain (loss) on derivatives, gain (loss) on early extinguishment of debt and income ~~tax expense~~taxes are discussed on a consolidated basis.

~~Exploration~~

We have applied the Securities and ~~Production~~

For the years ended December 31,
(in millions)
2017

2016

2015
Revenues
$
2,086

$
1,413

$
2,074
Impairment of natural gas and oil properties

–

2,321

6,950
Operating costs and expenses

1,537

1,496
(1)

2,228
Operating income (loss)
$
549

$
(2,404)

$
(7,104)

Gain (loss) on derivatives, settled (2)
$
(27)

$
36

$
206

~~(1)~~

~~Includes $86 million of restructuring and other one-time charges for the year ended December 31, 2016.~~

Exchange Commission’s recently adopted FAST Act Modernization and Simplification of Regulation S-K, which limits the discussion to the two most recent fiscal years. This discussion and analysis deals with comparisons of material changes in the consolidated financial statements for fiscal 2020 and fiscal 2019. For the comparison of fiscal 2019 and fiscal 2018, see “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our 2019 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on February 27, 2020.

~~(2)~~

~~Represents the gain (loss) on settled commodity derivatives, and includes $5 million amortization of premiums paid related to certain call options for the year ended December 31, 2017.~~

E&P


	For the years ended December 31,
(in millions)	2020			2019
Revenues	$	1,348	(1)	$	1,703	(2)
Operating costs and expenses	4,212		(3)	1,420		(4)
Operating income (loss)	$	(2,864)		$	283

Gain on derivatives, settled (5)	$	362		$	180

(1)Includes $5 million related to gas balancing for the year ended December 31, 2020.

(2)Includes $2 million in third-party water sales for the year ended December 31, 2019.

(3)Includes $2,825 million of non-cash full-cost ceiling test impairments, $41 million in Montage merger-related expenses, $16 million of restructuring charges and $5 million of non-cash, non-full cost pool impairments for the year ended December 31, 2020.

(4)Includes $11 million of restructuring charges and $13 million of non-cash, non-full cost pool asset impairments for the year ended December 31, 2019.

(5)Includes $11 million and $1 million amortization of premiums paid related to certain natural gas settled derivatives for the years ended December 31, 2020 and 2019, respectively.

Operating Income

E&P segment operating income for years ended December 31, 2016 and 2015 includes impairments of natural gas and oil properties of $2.3 billion and $7.0 billion, respectively. Excluding the 2016 impairment, our E&P segment operating income increased $632 million for year ended December 31, 2017, compared to the same period in 2016, primarily due to a $673 million increase in revenues, partially offset by a $41 million increase in operating costs.

•E&P segment operating loss for the year ended December 31, 2020 was $2,864 million compared to an operating income of $283 million for the year ended December 31, 2019. Excluding $2,825 million of non-cash full cost ceiling test impairments recorded in 2020, our E&P segment operating loss was $39 million for the year ended December 31, 2020. This decrease is primarily due to lower margins associated with decreased commodity pricing.

Excluding the 2016 and 2015 impairments, our E&P segment operating income increased $71 million for the year ended December 31, 2016, compared to the same period in 2015, as a $661 million decrease in revenues was more than offset by a $732 million decrease in operating costs.

Revenues

~~Revenues~~

The following illustrate the effects on sales revenues associated with changes in commodity prices and production volumes:

For the years ended December 31,

Natural

(in millions except percentages)

Gas

Oil

NGLs

Total
2016 sales revenues

$
1,252

$
69

$
92

$
1,413
Changes associated with prices

507

28

100

635
Changes associated with production volumes

16

4

14

34
2017 sales revenues

$
1,775

$
101

$
206

$
2,082
Increase from 2016

42%

46%

124%

47%

For the years ended December 31,

Natural

(in millions except percentages)

Gas

Oil

NGLs

Total
2015 sales revenues

$
1,923

$
76

$
73

$
2,072
Changes associated with prices

(459)
(1)

(5)

11

(453)
Changes associated with production volumes

(212)

(2)

8

(206)
2016 sales revenues

$
1,252

$
69

$
92

$
1,413
Increase (decrease) from 2015

(35%)

(9%)

26%

(32%)

~~(1)~~

Includes $209 million of gains associated with settled derivatives designated for hedge accounting, which were presented on the 2015 consolidated statements of operations as gas sales. There were no derivatives designated for hedge accounting in 2017 or 2016.


	For the years ended December 31,
(in millions except percentages)	Natural Gas			Oil			NGLs			Total
2019 sales revenues (1)	$	1,207		$	220		$	274		$	1,701
Changes associated with prices	(447)			(91)			(36)			(574)
Changes associated with production volumes	168			21			27			216
2020 sales revenues (2)	$	928		$	150		$	265		$	1,343
Decrease from 2019	(23)		%	(32)		%	(3)		%	(21)		%

In addition to the sales revenues detailed above, our E&P segment had $4 million of other operating revenues, primarily related to water sales to third-party operators for the year ended December 31, 2017, and

(1)Excludes $2 million ~~of gathering~~in other operating revenues for the year ended December 31, ~~2015.~~

2019 related to third-party water sales.

(2)Excludes $5 million in other operating revenues for the year ended December 31, 2020 related to gas balancing.

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Index to Financial Statements

Production Volumes


	For the years ended December 31,						For the years ended December 31,
		Increase/		Increase/							Increase/(Decrease)
	2017	(Decrease)	2016	(Decrease)	2015		2020		2019
Natural Gas (Bcf)						Natural Gas (Bcf)
Northeast Appalachia	395	13%	350	(3%)	360	Northeast Appalachia	473		459		3%
Southwest Appalachia	85	37%	62	(7%)	67	Southwest Appalachia	221		150		47%
Fayetteville Shale	316	(16%)	375	(19%)	465
Other	1	0%	1	(86%)	7	Other	—		—		—%
Total	797	1%	788	(12%)	899	Total	694		609		14%

Oil (MBbls)						Oil (MBbls)
Southwest Appalachia	2,228	9%	2,041	0%	2,036	Southwest Appalachia	5,124		4,673		10%
Other	99	(34%)	151	(34%)	229	Other	17		23		(26)%
Total	2,327	6%	2,192	(3%)	2,265	Total	5,141		4,696		9%

NGL (MBbls)						NGL (MBbls)
Southwest Appalachia	14,193	15%	12,317	16%	10,640	Southwest Appalachia	25,923		23,611		10%
Other	52	(5%)	55	(11%)	62	Other	4		9		(56)%
Total	14,245	15%	12,372	16%	10,702	Total	25,927		23,620		10%

Production volumes by area (Bcfe):						Production volumes by area (Bcfe):
Northeast Appalachia	395	13%	350	(3%)	360	Northeast Appalachia	473		459		3%
Southwest Appalachia	183	24%	148	3%	143	Southwest Appalachia	407		319		28%
Fayetteville Shale	316	(16%)	375	(19%)	465
Other	3	50%	2	(75%)	8	Other	—		—		—%
Total	897	3%	875	(10%)	976
Total (1)						Total (1)	880		778		13%

Production percentage:						Production percentage:
Natural gas						Natural gas	79	%	78	%
Oil						Oil	4	%	4	%
NGL						NGL	17	%	18	%

Production volumes for our E&P segment increased by 22 Bcfe for the year ended December 31, 2017, compared to the same period in 2016, as increased production volumes from Northeast and Southwest Appalachia more than offset decreased natural gas production volumes in the Fayetteville Shale.

(1)Approximately 878 Bcfe and 776 Bcfe for the years ended December 31, 2020 and 2019, respectively, were produced from the Marcellus Shale formation.

E&P segment production volumes decreased 101 Bcfe for the year ended December 31, 2016, compared to the same period in 2015, as decreased natural gas production volumes in the Fayetteville Shale and Northeast Appalachia more than offset increased production volumes from Southwest Appalachia.

•Production volumes for our E&P segment increased 102 Bcfe for the year ended December 31, 2020, compared to the same period in 2019, primarily due to a 28% increase in production volumes in Southwest Appalachia.

•Oil and NGL production increased 9% and 10%, respectively, for the year ended December 31, 2020, compared to 2019.

Commodity Prices

The price we expect to receive for our production is a critical factor in determining the capital investments we make to develop our properties. Commodity prices fluctuate due to a variety of factors we ~~cannot~~can neither control ornor predict, including increased supplies of natural gas, oil or NGLs due to greater exploration and development activities, weather conditions, political and economic events such as the response to the COVID-19 pandemic, and competition from other energy sources. These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price environments and adjust the pace of our activity ~~to invest within cash flows~~ in order to maintain appropriate liquidity and financial flexibility.

For the years ended December 31,

Increase/

Increase/

Average realized price per unit:
2017

(Decrease)

2016

(Decrease)

2015
Natural gas sales, excluding derivatives (per Mcf)
$
2.23

40%

$
1.59

(17%)

$
1.91
Effect of settled gain (loss) on derivatives (per Mcf)

(0.04)

(180%)

0.05

(89%)

0.46
Natural gas sales, including derivatives (per Mcf)
$
2.19

34%

$
1.64

(31%)

$
2.37

Oil sales (per Bbl)
$
43.12

38%

$
31.20

(6%)

$
33.25

NGL sales, excluding derivatives (per Bbl)
$
14.46

94%

$
7.46

10%

$
6.80
Effect of settled gain (loss) on derivatives (per Bbl)

0.02

100%

–

0%

–
NGL sales, including derivatives (per Bbl)
$
14.48

94%

$
7.46

10%

$
6.80

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Index to Financial Statements

Our average price realized for natural gas production, including the effect of derivatives, increased for the year ended December 31, 2017, compared to the same period in 2016, due to a $0.64 per Mcf increase in the average realized price, excluding derivatives, partially offset by a $0.09 per Mcf decrease associated with our settled derivatives.


	For the years ended December 31,
	2020			2019			Increase/ (Decrease)
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1)	$	2.08		$	2.63		(21)%
Discount to NYMEX (2)	(0.74)			(0.65)			14%
Average realized gas price, excluding derivatives ($/Mcf)	$	1.34		$	1.98		(32)%
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		(22)%

Oil Price:
WTI oil price ($/Bbl)	$	39.40		$	57.03		(31)%
Discount to WTI	(10.20)			(10.13)			1%
Average oil price, excluding derivatives ($/Bbl)	$	29.20		$	46.90		(38)%
Gain on settled derivatives ($/Bbl)	17.71			2.66
Average oil price, including derivatives ($/Bbl)	$	46.91		$	49.56		(5)%

NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)	$	10.24		$	11.59		(12)%
Gain on settled derivatives ($/Bbl)	0.91			2.05
Average realized NGL price, including derivatives ($/Bbl)	$	11.15		$	13.64		(18)%
Percentage of WTI, excluding derivatives	26		%	20		%

Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)	$	1.53		$	2.18		(30)%
Including derivatives ($/Mcfe)	$	1.94		$	2.42		(20)%

The average price realized for our crude oil production increased by $11.92 per Bbl for the year ended December 31, 2017, compared to the same period in 2016. We did not use derivatives to financially protect our 2017, 2016 or 2015 oil production.

(1)Based on last day settlement prices from monthly futures contracts.

Our average price realized for NGL production, including the effect of derivatives, increased for the year ended December 31, 2017, compared to the same period in 2016, due to a $7.00 per Bbl increase in the average realized price, excluding derivatives, and a $0.02 per Mcf increase associated with our settled derivatives. We did not use derivatives to financially protect our 2016 or 2015 NGL production.

(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.

~~Our E&P segment receives~~

We receive a sales price for our natural gas at a discount to average monthly NYMEX settlement prices based on heating content of the gas, locational basis differentials and transportation and fuel charges. Additionally, we receive a sales price for our oil and NGLs at a difference to average monthly West Texas Intermediate settlement and Mont Belvieu NGL composite prices, respectively, due to a number of factors including product quality, composition and types of NGLs sold, locational basis differentials and transportation and fuel charges.

Excluding the impact of derivatives, the average price received for our natural gas production for the year ended December 31, 2017 of $2.23 per Mcf was approximately $0.88 per Mcf lower than the average monthly NYMEX settlement price, primarily due to locational basis differentials and transportation charges. In comparison, the average price received for our natural gas production for the same period in 2016 of $1.59 per Mcf was approximately $0.87 per Mcf lower than the average monthly NYMEX settlement price.

We regularly enter into various ~~hedging~~derivatives and other financial arrangements with respect to a portion of our projected natural gas, oil and NGL production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to Item 7A,Quantitative and Qualitative Disclosures about Market Risk, of this Annual Report, Note 46 to the consolidated financial statements included in this Annual Report, and our derivative risk factor for additional discussion about our derivatives and risk management activities.

As of December 31, 2017, we have protected basis on approximately 182 Bcf and 70 Bcf of our 2018 and 2019 expected natural gas production, respectively, through physical sales arrangements at a basis differential to NYMEX natural gas price of approximately ($0.25) per MMBtu and ($0.31) per MMBtu for 2018 and 2019, respectively.

We have also financially protected basis on approximately 44 Bcf and less than 1 Bcf of our 2018 and 2019 expected natural gas production, respectively, through the use of derivatives at a basis differential to NYMEX natural gas price of approximately ($0.48) per MMBtu and ($0.59) per MMBtu for 2018 and 2019, respectively.

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~~As of December 31, 2017 we have also financially protected 489 Bcf and 201 Bcf of our 2018 and 2019 expected natural gas production, respectively, to limit our exposure to NYMEX price fluctuations.~~

Index to Financial Statements

The table below presents the amount of our future production in which the impact of basis volatility has been limited as of December 31, 2020:


	Volume (Bcf)	Basis Differential
Basis Swaps – Natural Gas
2021	219	$	(0.21)
2022	139	(0.33)
2023	47	(0.45)
2024	11	(0.60)
2025	4	(0.59)
Total	420

Physical NYMEX Sales Arrangements – Natural Gas
2021	217	$	(0.24)
2022	65	(0.35)
2023	40	(0.37)
2024	18	(0.47)
2025	12	(0.50)
Total	352

In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of December 31, 2020:


	2021	2022	2023
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	—
Total financial protection on future production (Bcfe)	895	422	92

We refer you to Note 46 of the consolidated financial statements included in this Annual Report for additional details about our derivative instruments.

Operating Costs and Expenses


	For the years ended December 31,
(in millions except percentages)	2020			2019			Increase/(Decrease)
Lease operating expenses	$	815		$	722		13%
General & administrative expenses	108		(1)	150		(2)	(28)%
Montage merger-related expenses	41			—			100%
Restructuring charges	16			11			45%
Taxes, other than income taxes	54			62			(13)%
Full cost pool amortization	333			439			(24)%
Non-full cost pool DD&A	15			23			(35)%
Impairments	2,830			13			(62)%

Total operating costs	$	4,212		$	1,420		197%

(1)Includes $1 million of legal settlement charges for the year ended December 31, 2020.

(2)Includes a $6 million residual value guarantee shortfall payment to the previous lessor of our headquarters building and $6 million of legal settlement charges for the year ended December 31, 2019.

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Index to Financial Statements

~~Operating Costs~~


	For the years ended December 31,
Average unit costs per Mcfe:	2020			2019			Increase/(Decrease)
Lease operating expenses (1)	$	0.93		$	0.92		1%
General & administrative expenses	$	0.12	(2)	$	0.18	(3)	(33)%
Taxes, other than income taxes	$	0.06		$	0.08		(25)%
Full cost pool amortization	$	0.38		$	0.56		(32)%

(1)Includes post-production costs such as gathering, processing, fractionation and ~~Expenses~~

For the years ended December 31,

Increase/

Increase/

(in millions except percentages)
2017

(Decrease)

2016

(Decrease)

2015
Lease operating expenses
$
809

6%

$
761

(15%)

$
899
General & administrative expenses

202

(1%)

204

(1%)

207
Taxes, other than income taxes

86

1%

85

(15%)

100
Restructuring charges

–

(100%)

75

100%

–
Full cost pool amortization

405

23%

329

(66%)

980
Non-full cost pool DD&A

35

(17%)

42

(13%)

48
Gain on sale of assets

–

0%

–

(100%)

(6)
Total operating costs
$
1,537

3%

$
1,496

(33%)

$
2,228

For the years ended December 31,

Increase/

Increase/

Average unit costs per Mcfe:
2017

(Decrease)

2016

(Decrease)

2015
Lease operating expenses
$
0.90

3%

$
0.87

(5%)

$
0.92
General & administrative expenses
$
0.22
(1)
0%

$
0.22
(2)
5%

$
0.21
Taxes, other than income taxes
$
0.10

0%

$
0.10
(3)
0%

$
0.10
Full cost pool amortization
$
0.45

18%

$
0.38

(62%)

$
1.00

~~(1)~~

~~Excludes $5 million of legal settlements for the year ended December 31, 2017.~~

compression.

~~(2)~~

~~Excludes $83 million of restructuring and other one-time charges for the year ended December 31, 2016.~~

(2)Excludes $41 million in Montage merger-related expenses $16 million in restructuring charges and $1 million in legal settlement charges for the year ended December 31, 2020.

~~(3)~~

~~Excludes $3 million of restructuring charges for the year ended December 31, 2016.~~

(3)Excludes $11 million in restructuring charges, a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $6 million of legal settlement charges for the year ended December 31, 2019.

Lease Operating Expenses

Lease operating expenses per Mcfe increased $0.03 for the year ended December 31, 2017, compared to the same period of 2016, primarily due to increased transportation and gas processing costs, as our production growth shifts toward the Appalachian basin.

•Lease operating expenses per Mcfe increased $0.01 for the year ended December 31, 2020, compared to 2019, as an increase in liquids production, which includes processing fees, was only partially offset by a decrease related to temporarily reduced gathering and transportation rates in Southwest Appalachia that became effective late in the second quarter of 2020.

Lease operating expenses per Mcfe decreased $0.05 for the year ended December 31, 2016, compared to the same period of 2015, primarily due to successful renegotiations of our existing gathering and processing rates in our Southwest Appalachia operations and decreased workover activity and contract services.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2017 decreased $2 million, compared to the same period in 2016, as decreased personnel costs were mostly offset by increased legal and information technology charges. The legal charges relate mostly to settlement of litigation and costs of trying a class action in Arkansas.

•General and administrative expenses in 2020 included $1 million in legal settlement charges. 2019 included a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $6 million in legal settlement charges. Excluding these amounts, general and administrative expenses decreased $31 million for the year ended December 31, 2020, compared to 2019, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.

On a per Mcfe basis, excluding certain one-time charges of $5 million and $11 million in 2017 and 2016, respectively, general and administrative expenses per Mcfe remained flat for the year ended December 31, 2017, compared to the same period of 2016, as a slight increase in expenses was offset by a 3% increase in production volumes.

•On a per Mcfe basis, excluding restructuring, Montage merger-related expenses, legal settlement charges and the residual value guarantee short-fall payment, general and administrative expenses per Mcfe decreased by $0.06 for the year ended December 31, 2020, compared to 2019, due to a 28% decrease in expenses and a 13% increase in production volumes.

Excluding the one-time charge of $11 million in 2016, general and administrative expenses per Mcfe increased slightly for the year ended December 31, 2016, compared to the same period of 2015, as a $14 million decrease in personnel costs was more than offset by a 10% decrease in production volumes.

Montage Merger-Related Expenses

•Montage merger-related expenses for the year ended December 31, 2020 included $18 million in bank, legal and consulting fees; $17 million in employee severance and related costs; and $5 million related to the settlement of contracts inherited from Montage that had no future value to our ongoing business. We refer you to Note 3 of the consolidated financial statements included in this Annual Report for additional details about the Merger.

Restructuring Charges

In January 2016, as a result of lower anticipated drilling activity due to a prolonged depressed commodity price environment, we announced a workforce reduction of approximately 1,100 employees. The $75 million one-time restructuring charge consisted of $72 million in general and administrative expenses and $3 million in taxes, other than income taxes.

•In February 2020, employees were notified of a workforce reduction plan as a result of a strategic realignment of our organizational structure. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. We also recognized additional severance costs in the fourth quarter of 2020 related to continued organizational restructuring. For the year ended December 31, 2020, we recognized a total restructuring expense of $16 million primarily related to cash severance, including payroll taxes.

•As of December 31, 2020, a $3 million liability for restructuring charges to be paid in 2021 has been recorded.

See Note 2 of the consolidated financial statements included in this Annual Report for additional details about our restructuring charges.

Taxes, Other than Income Taxes

•Taxes other than income taxes per Mcfe may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes and fluctuations in commodity prices. Taxes, other than income taxes, per Mcfe decreased $0.02 per Mcfe for the year ended December 31, 2020, compared to the same period in 2019, primarily due to lower commodity pricing and lower effective tax rates in Southwest Appalachia.

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Index to Financial Statements

~~Taxes, Other than Income Taxes~~

Taxes other than income taxes per Mcfe may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes and fluctuations in commodity prices.

Full Cost Pool Amortization

Our full cost pool amortization rate increased $0.07 per Mcfe for the year ended December 31, 2017, as compared to the same period in 2016. The increase in the average amortization rate resulted primarily from the addition of future development costs associated with proved undeveloped reserves recognized as a result of improved commodity prices.

•Our full cost pool amortization rate decreased $0.18 per Mcfe for the year ended December 31, 2020, as compared to 2019. The average amortization rate decreased primarily as a result of the impact of $2,825 million in non-cash full cost ceiling test impairments recorded in 2020.

•No impairment expense was recorded for the year ended December 31, 2020 in relation to our recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, we determined that the fair value of the properties acquired at the closing of the Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021 as long as we can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, we are required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Merger was based on forward strip natural gas and oil pricing existing at the date of the Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Merger. The properties acquired in the Merger have an unamortized cost at December 31, 2020 of $1,087 million. Had we not received the waiver from the SEC, the impairment charge recorded would have been an additional $539 million for the year ended December 31, 2020.

•The amortization rate is impacted by the timing and amount of reserve additions and the future development costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from non-cash full cost ceiling impairments, proceeds from the sale of properties that reduce the full cost pool, and the levels of costs subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of future reserve changes.

Unevaluated costs excluded from amortization were $1.8 billion at December 31, 2017, compared to $2.1 billion and $3.7 billion at December 31, 2016 and 2015, respectively. The unevaluated costs excluded from amortization decreased, as compared to 2016, as the evaluation of previously unevaluated properties totaling $749 million in 2017 was only partially offset by the impact of $461 million of unevaluated capital invested during the same period.

•Unevaluated costs excluded from amortization were $1,472 million at December 31, 2020 compared to $1,506 million at December 31, 2019. The unevaluated costs excluded from amortization decreased, as compared to 2019, as the evaluation of previously unevaluated properties totaling $262 million in 2020 was only partially offset by the impact of $228 million of unevaluated capital invested, which included $90 million for Montage properties acquired during the same period.

See ““Supplemental Oil and Gas ~~Disclosures”~~Disclosures” in Item 8 of Part II of this Annual Report for additional information regarding our unevaluated costs excluded from amortization.

~~Midstream~~

For the years ended December 31,

Increase/

Increase/

(in millions except percentages)
2017

(Decrease)

2016

(Decrease)

2015
Marketing revenues
$
2,867

31%

$
2,191

(17%)

$
2,628
Gas gathering revenues

331

(12%)

378

(23%)

491
Marketing purchases

2,824

32%

2,145

(16%)

2,566
Operating costs and expenses (1)

197

(8%)

215

(13%)

247
Gain on sale of assets, net

6

100%

–

(100%)

277
Operating income
$
183

(12%)

$
209

(64%)

$
583

Volumes marketed (Bcfe)

1,067

0%

1,062

(6%)

1,127
Volumes gathered (Bcf)

499

(17%)

601

(25%)

799

Percent marketed from affiliated E&P operations

96%

93%

97%
Percent oil and NGLs marketed from affiliated E&P operations

63%

65%

60%
Impairments

~~(1)~~

~~Includes $3 million of restructuring charges for the year ended December 31, 2016.~~

•We recognized $2,825 million in non-cash full cost ceiling test impairments for the year ended December 31, 2020 primarily due to decreased commodity pricing over the prior 12 months. Additionally, we recognized a $5 million impairment to non-core assets.

Operating income from our Midstream segment decreased $26 million for the year ended December 31, 2017, compared to the same period in 2016, primarily due to a $47 million decrease in gas gathering revenues and a $3 million decrease in marketing margin, partially offset by an $18 million decrease in operating costs and expenses and a $6 million gain on the sale of certain compressor equipment.

•During the year ended December 31, 2019, we recognized non-cash impairments of $13 million associated with non-core E&P assets.

Operating income for the year ended December 31, 2015 includes a $277 million net gain on the sale of our northeastern Pennsylvania and East Texas gathering assets. Excluding the net gain on sale, operating income decreased $97 million for the year ended December 31, 2016, compared to the same period in 2015, primarily due to a $113 million decrease in gas gathering revenues and a $16 million decrease in marketing margin, partially offset by a $32 million decrease in operating costs and expenses.

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Index to Financial Statements

~~The margin generated from marketing activities was $43 million, $46 million and $62 million for the years ended December 31, 2017, 2016 and 2015, respectively.~~

Marketing

~~Margins~~


	For the years ended December 31,
(in millions except percentages)	2020			2019			Increase/(Decrease)
Marketing revenues	$	2,145		$	2,849		(25)%

Other operating revenues	—			1			(100)%
Marketing purchases	2,129			2,833			(25)%
Operating costs and expenses	23			25			(8)%
Impairments	—			3			(100)%
Loss on sale of assets, net	—			2			(100)%
Operating income (loss)	$	(7)		$	(13)		(46)%

Volumes marketed (Bcfe)	1,138			1,101			3%


Percent natural gas production marketed from affiliated E&P operations	89		%	79		%
Affiliated E&P oil and NGL production marketed	81		%	61		%

Operating Loss

•Marketing operating loss decreased $6 million for the year ended December 31, 2020, compared to 2019, as 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. Additionally, marketing operating loss for 2020 included a $2 million decrease in operating costs and expenses. For the year ended December 31, 2020, the marketing margin remained flat, compared to the prior year.

•The margin generated from marketing activities was $16 million for both years ended December 31, 2020 and 2019, respectively.

Marketing margins are driven primarily by volumes marketed and may fluctuate depending on the prices paid for commodities, related cost of transportation and the ultimate disposition of those commodities. Increases and decreases in ~~marketing~~ revenues due to changes in commodity prices and volumes marketed are largely offset by corresponding changes in ~~marketing~~ purchase expenses. ~~We enter into derivative contracts~~Efforts to optimize the cost of our transportation can result in greater expenses and therefore lower marketing margins.

Revenues

•Revenues from ~~time to time with respect to~~ our ~~natural gas~~ marketing activities ~~to provide margin protection. For more information about our derivatives and risk management activities, we refer you to~~ ~~Item 7A~~ ~~of Part II of this Annual Report and~~ ~~Note 4~~ ~~to the consolidated financial statements.~~

~~Revenues~~

Revenues from our marketing activities increased $676 million for the year ended December 31, 2017, compared to the same period in 2016, primarily due to a 30% increase in the price received for volumes marketed and a 5 Bcfe increase in the volumes marketed.

For the year ended December 31, 2016, revenues from our marketing activities decreased $437 million, compared to the same period in 2015, primarily due to a 12% decrease in the price received for volumes marketed and a 65 Bcfe decrease in volumes marketed.

~~The consecutive decreases in gas gathering revenues for the years ended December 31, 2017 and 2016 primarily resulted from decreasing volumes gathered in the Fayetteville Shale.~~

~~Operating Costs and Expenses~~

The consecutive decreases in operating costs and expenses for the years ended December 31, 2017 and 2016, respectively, primarily resulted from reduced compression and personnel costs due to lower activity levels as a result of decreasing volumes gathered in the Fayetteville Shale.

~~Restructuring Charges~~

In January 2016, we announced a 40% workforce reduction, which was substantially concluded by the end of March 2016. In April 2016, we also partially restructured executive management. Affected employees were offered a severance package that included a one-time cash payment depending on length of service and, if applicable, accelerated vesting of outstanding stock-based equity awards. As a result of the workforce reduction and executive management restructuring, we recognized restructuring charges of $78decreased $704 million for the year ended December 31, ~~2016.~~

~~Interest Expense~~

2020, compared to 2019, as a 27% decrease in the price received for volumes marketed more than offset a 37 Bcfe increase in the volumes marketed.

For the years ended December 31,

Increase/

Increase/

(in millions except percentages)
2017

(Decrease)

2016

(Decrease)

2015
Gross interest expense:

Senior notes
$
177

(3%)

$
183

1%

$
181
Credit arrangements

62

44%

43

126%

19
Amortization of debt costs

9

(36%)

14

(77%)

60
Total gross interest expense

248

3%

240

(8%)

260
Less: capitalization

(113)

(26%)

(152)

(25%)

(204)
Net interest expense
$
135

53%

$
88

57%

$
56
Operating Costs and Expenses

Interest expense related to our senior notes decreased for the year ended December 31, 2017, as compared to the same period in 2016, as a decrease in interest expense related to the gradual redemption of our 7.50% Senior Notes due in February 2018, which began in July 2016 and completed in May 2017, was only partially offset by increased interest expense which resulted from the issuance of new senior notes in September 2017.

•Marketing operating costs and expenses decreased $2 million for the year ended December 31, 2020, compared to the year ended December 31, 2019, primarily due to decreased general and administrative expenses associated with decreased personnel costs and the implementation of cost reduction initiatives.

Interest expense related to our credit arrangements increased for the years ended December 31, 2017 and 2016, as compared to the same periods in 2016 and 2015, respectively, due to increased outstanding borrowings and higher interest rates.

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Index to Financial Statements

Amortization of debt costs for the year ended December 31, 2015 include a $47 million charge for unamortized fees associated with the repayment of our short-term bridge facility in the first quarter of 2015, as this temporary facility was replaced with permanent financing.

Consolidated

The decreases in capitalized interest for the years ended December 31, 2017 and 2016, as compared to the same periods in 2016 and 2015, respectively, were primarily due to the continued evaluation of a portion of our Southwest Appalachia assets.

Interest Expense

The increase in interest expense related to our senior notes for the year ended December 31, 2016, as compared to the same period in 2015, was primarily due to an increase in our cost of debt of 175 basis points that became effective in July 2016 as a result of downgrades by Moody’s and S&P on our 2018, 2020 and 2025 Senior Notes.


	For the years ended December 31,
(in millions except percentages)	2020		2019		Increase/ (Decrease)
Gross interest expense:
Senior notes	$	155	$	155	—%
Credit arrangements	16		11		45%
Amortization of debt costs	11		8		38%
Total gross interest expense	182		174		5%
Less: capitalization	(88)		(109)		(19)%
Net interest expense	$	94	$	65	45%

•Interest expense related to our senior notes remained flat for the year ended December 31, 2020, as compared to 2019, as the interest savings from the repurchase of $107 million and $114 million of our outstanding senior notes in the first half of 2020 and the second half of 2019, respectively, was offset by the interest associated with the August 2020 public offering of $350 million aggregate principal amount of our 8.375% Senior Notes due 2028.

•Capitalized interest decreased $21 million for the year ended December 31, 2020, compared to 2019, due to the evaluation of natural gas and oil properties over the past twelve months.

•Capitalized interest decreased as a percentage of gross interest expense for the year ended December 31, 2020 as compared to 2019 primarily due to a larger percentage decrease in our unevaluated natural gas and oil properties balance as compared to the smaller percentage decrease in our gross interest expense over the same period.

Gain (Loss) on Derivatives


	For the years ended December 31,							For the years ended December 31,
(in millions)	2017		2016		2015
(in millions)							(in millions)	2020		2019
Gain (loss) on unsettled derivatives	$	451	$	(373)	$	(155)	Gain (loss) on unsettled derivatives	$	(138)	$	94
Gain (loss) on settled derivatives (1)		(29)		34		202
Total gain (loss) on derivatives (1)	$	422	$	(339)	$	47
Gain on settled derivatives							Gain on settled derivatives	362		180
Total gain on derivatives							Total gain on derivatives	$	224	$	274

~~(1)~~

Includes $5 million amortization of premiums paid related to certain call options for the year ended December 31, 2017, which is included in gain (loss) on derivatives on the consolidated statement of operations.

We refer you to Note 46 to the consolidated financial statements included in ~~the~~this Annual Report for additional details about our gain (loss) on derivatives.

~~Loss~~

Gain (Loss) on Early Extinguishment of Debt

In September 2017, we used the net proceeds of approximately $1.1 billion from our September 2017 senior notes offering to repurchase approximately $758 million of our 2020 Senior Notes and to repay the remaining $327 million principal amount outstanding of our 2015 Term Loan. We recognized a loss of $59 million for the redemption of these senior notes which included $53 million of premiums paid.

•In 2020, we recorded a gain on early extinguishment of debt of $35 million as a result of our repurchase of $107 million in aggregate principal amount of our outstanding senior notes for $72 million.

~~In the first half of 2017, we redeemed the remaining $276 million principal amount outstanding of our 2018 Senior Notes, recognizing a loss of $11 million.~~

During the third quarter of 2016, we used proceeds from our $1,247 million July 2016 equity offering to purchase and retire $700 million of our outstanding senior notes due in the first quarter of 2018 and retire $375 million of our $750 million term loan entered into in November 2015. We recognized a loss of $51 million for the redemption of these senior notes, which included $50 million of premiums paid.

For the years ended December 31,
(in millions except percentages)
2017

2016

2015
Income tax expense (benefit)
$
(93)

$
(29)

$
(2,005)
Effective tax rate

(10%)

1%

31%

The income tax benefits recognized for the year ended December 31, 2017 primarily resulted from changes in federal tax legislation enacted under the Tax Cuts and Jobs Act (Tax Reform) which will allow us to recover certain alternative minimum tax credit carryovers, along with the expiration of a portion of our uncertain tax provision.

Our low effective tax rate is the result of our recognition of a valuation allowance that reduced the deferred tax asset primarily related to our current net operating loss carryforward, as well as changes to the deferred tax rate enacted under the recent Tax Reform. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.


	For the years ended December 31,
(in millions except percentages)	2020			2019
Income tax expense (benefit)	$	407		$	(411)
Effective tax rate	(15)		%	(86)		%

•As of the first quarter of 2019, we had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted income, we concluded that it was more likely than not that the deferred tax asset would be realized and released substantially all of the valuation allowance. This resulted in a discrete tax benefit of $411 million being recorded for the year ended December 31, 2019. However, due to commodity price declines during 2020 and the write-down of the current value of our natural gas and oil properties, in addition to other negative evidence, we concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense of $408 million for the increase in our valuation allowance in the first quarter of 2020. The net change in valuation allowance is reflected as a component of income tax expense. We also continue to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate.

We refer you to Note 11 to the consolidated financial statements included in this Annual Report for additional discussion about our income taxes.

We depend primarily on funds generated from our operations, our 2018 credit facility, our cash and cash equivalents balance ~~our $809 million revolving credit facilities~~ and capital markets as our primary sources of liquidity. ~~Although~~In October 2020, the banks participating in our 2018 credit facility reaffirmed our elected borrowing base and aggregate commitments to be $1.8 billion. Upon the closing of the Merger in November 2020 and satisfaction of related conditions, the elected borrowing base and total aggregate commitments increased from $1.8 billion to $2.0 billion, the maximum permitted lien amount based on provisions in certain of our senior notes indentures. As of February 25, 2021, we ~~have financial flexibility with~~had approximately $1.3 billion of total available liquidity, which exceeds our ~~cash balance~~currently modeled needs, and ~~the ability to draw on our revolving credit facilities as necessary,~~looking forward in 2021, we ~~continue to be~~remain committed to our ~~capital discipline~~ strategy of ~~investing within our~~free cash flow ~~from operations net~~generation through capital discipline. We refer you to Note 9 to the consolidated financial statements included in this Annual Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of ~~changes in working capital, supplemented in 2017 by the remaining proceeds from the July 2016 equity issuance.~~

our 2018 credit facility and related covenant requirements.

Our cash flow from operating activities is highly dependent upon our ability to sell and the sales prices that we receive for our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. See "Market Conditions and Commodity Prices" in the Overview section of Item 7 in Part II for additional discussion about current and potential future market conditions. The sales price we receive for our production is also influenced by our commodity ~~hedging activities. See “Risk Factors” in~~ ~~Item 1A, “Quantitative and Qualitative Disclosures about Market Risks” in~~ ~~Item 7A~~ ~~and~~ ~~Note 4, “Derivatives and Risk Management” in the consolidated financial statements for further details.~~

derivative program. Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. ~~At December 31, 2017,~~In 2020, $362 million in realized gains on derivatives have offset a large portion of the impact of lower commodity prices, and although we ~~had NYMEX price derivatives~~are continually adding additional derivative positions for portions of our expected 2021, 2022 and 2023 production, there can be no assurance that we will be able to add derivative positions to cover the remainder of our expected production at favorable prices. See “Risk Factors” in ~~place on 489 Bcf~~Item 1A, “Quantitative and ~~201 Bcf on our targeted 2018~~Qualitative Disclosures about Market Risk” in Item 7A and ~~2019 natural gas production, respectively,~~Note 6 in the consolidated financial statements included in this Annual Report for ~~protection against a decrease in natural gas prices. We also had commodity derivatives in place on 183 MBbls of both our targeted 2018 ethane and propane production.~~

further details.

Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to settle the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities.

Our short-term cash flows are also dependent on the timely collection of receivables from our customers and joint interest ~~partners.~~owners. We actively manage this risk through credit management activities and, through the date of this filing, have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers and joint interest ~~partners~~owners could adversely impact our cash flows.

Due to these ~~above~~ factors, we are unable to forecast with certainty our future level of cash flow from operations. Accordingly, we expect to adjust our discretionary uses of cash depending upon available cash flow. Further, we may from time to time seek to retire, rearrange or amend some or all of our outstanding debt or debt agreements through cash purchases, and/or exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Credit Arrangements and Financing Activities

~~We have taken substantial steps~~

In April 2018, we replaced our credit facility entered into in ~~managing our debt maturities and liquidity in 2017. These steps, discussed in further detail below, had the effect~~2016 with a new revolving credit facility (the "2018 credit facility") with a group of ~~extending maturities on total debt outstanding by reducing the~~banks that, as amended, has a maturity date of April 2024. The 2018 credit facility has an aggregate maximum revolving credit amount of ~~debt, net~~$3.5 billion and, in October 2020, the banks participating in our 2018 credit facility reaffirmed the borrowing base to be $1.8 billion, which also reflected our aggregate commitments. Upon the closing of the Merger in November 2020, the borrowing base and total aggregate commitments were increased from $1.8 billion to $2.0 billion. The borrowing base is subject to redetermination at least twice a year, in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investment and operating costs. On October 8, 2020, we entered into an amendment to the credit agreement governing the 2018 credit facility to, among other matters, limit our unrestricted cash and cash equivalents ~~coming due prior~~ to ~~2022 from $1,261~~$200 million aswhen loans under the 2018 credit facility are outstanding, subject to certain exceptions, and to increase the applicable rate by 25 basis points on loans outstanding under the 2018 credit facility. The 2018 credit facility is secured by substantially all of ~~December 31, 2016~~our assets, including most of our subsidiaries. The permitted lien provisions in certain senior note indentures currently limit liens securing indebtedness to ~~$367 million as~~the greater of ~~December 31, 2017.~~

$2.0 billion or 25% of

In November 2017, we solicited and received consent to amend certain restrictive covenants contained in the indentures governing our 2022 Notes and 2025 Notes. These amendments conform certain covenants of the 2022 Notes and 2025 Notes to all other series of senior notes.

~~In October 2017, we retired $40 million principal amount outstanding of our 2017 Senior Notes.~~

In September 2017, we completed a public offering of $650 million aggregate principal amount of our 7.50% Senior Notes due 2026 and $500 million aggregate principal amount of our 7.75% Senior Notes due 2027, with net proceeds from the offering totaling approximately $1.1 billion after underwriting discounts and offering expenses.

The proceeds from the September 2017 offering were used to repurchase $758 million of our 4.05% Senior Notes due 2020 and to repay the remaining $327 million principal amount outstanding of the term loan we borrowed in November 2015.

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Index to Financial Statements

~~Also in September 2017, we entered into Amendment No. 1 to~~adjusted consolidated net tangible assets. We may utilize the credit agreement we entered into in June 2016 providing a $1,191 million secured term loan and $743 million unsecured revolving facility. This amendment provides greater flexibility to our minimum liquidity covenant and allows us to retain the first $500 million of net cash proceeds from asset sales that would have otherwise been required to be used for further debt reduction.

~~During the first half of 2017, we redeemed the remaining $276 million principal amount outstanding of our~~ 2018 ~~Senior Notes.~~

~~The revolving~~ credit facility ~~component~~in the form of ~~our June 2016 credit agreement provides borrowing capacity~~loans and letters of $743 million and matures in December 2020. The maturity date will accelerate to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 million of our senior notes due in January 2020.credit. As of December 31, ~~2017,~~2020, we ~~have repurchased and refinanced approximately $758~~had $700 million ofborrowings on our ~~4.05% Senior Notes due 2020. The~~ revolving credit facility ~~we entered into~~and $233 million in ~~December 2013, as reduced~~outstanding letters of credit. We refer you to Note 9 to the consolidated financial statements included in ~~June 2016, provides borrowing capacity~~this Annual Report for additional discussion of ~~$66 million and matures in December 2018.~~ our revolving credit facility.

As of December 31, ~~2017, there were no borrowings under either revolving credit facility; however, there was $323 million in letters of credit outstanding against the 2016 revolving credit facility.~~

~~As of December 31, 2017,~~2020, we were in compliance with all of the covenants ofcontained in the ~~term loan and~~credit agreement governing our revolving credit ~~facilities. Although we do not anticipate any violations of the financial covenants, our~~facility. Our ability to comply with ~~these~~financial covenants ~~is dependent upon~~in future periods depends, among other things, on the success of our ~~exploration and~~ development program and upon other factors beyond our control, such as the market demand and prices for natural gas and liquids. We refer you to Note 79 of the consolidated financial statements included in this Annual Report for additional discussion of the covenant requirements of our ~~term loan and~~2018 revolving credit ~~facilities.~~

At February 27, 2018, we had a long-term issuer credit rating of Ba3 by Moody’s, a long-term debt rating of BB- by S&P and a long-term issuer default rating of BB by Fitch Ratings. Any downgrades in our public debt ratings by Moody’s or S&P could increase our cost of funds and decrease our liquidity under our revolving credit facilities.

facility.

The credit status of the financial institutions participating in our revolving credit ~~facilities~~facility could adversely impact our ability to borrow funds under the revolving credit ~~facilities.~~facility. Although we believe all of the lenders under the ~~facilities~~facility have the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us. We refer you to Note 79 of to the consolidated financial statements included in this Annual Report for additional discussion of our revolving credit ~~facilities.~~

facility.

Our exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as Administrative Agent, and Southwestern. The alternative rate will be based on the prevailing market convention and is expected to be the Secured Overnight Financing Rate (or “SOFR”).

In contemplation of the Merger with Montage, in August 2020, we completed a public offering of $350 million aggregate principal amount of our 2028 Notes, with net proceeds from the offering totaling approximately $345 million after underwriting discounts and offering expenses.

In August 2020, we completed a public offering of 63,250,000 shares of our common stock with an offering price to the public of $2.50 per share. Net proceeds, after deducting underwriting discounts and offering expenses, were approximately $152 million. The proceeds from the common stock offering, in conjunction with the issuance of the 2028 Notes and additional borrowings on our revolving credit facility were used to fund a redemption of $510 million aggregate principal amount of Montage Notes in connection with the closing of the Merger.

In 2020, we repurchased $6 million of our 4.10% Senior Notes due 2022, $36 million of our 4.95% Senior Notes due 2025, $21 million of our 7.50% Senior Notes due 2026 and $44 million of our 7.75% Senior Notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.

In the second half of 2019, we repurchased $35 million of our 4.95% Senior Notes due 2025, $11 million of our 7.50% Senior Notes due 2026 and $16 million of our 7.75% Senior Notes due 2027, and recognized an $8 million gain on extinguishment of debt. Additionally, in December 2019, we retired the remaining $52 million principal of our 4.05% Senior Notes due 2020. We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our senior notes.

Because of the focused work on refinancing and repayment of our debt during the last three years, only $207 million, or 7%, of our outstanding debt balance as of December 31, 2020 is scheduled to become due prior to 2024.

At February 25, 2021, we had a long-term issuer credit rating of Ba2 by Moody’s (rating and stable outlook affirmed on April 2, 2020), a long-term debt rating of BB- by S&P (rating affirmed and outlook upgraded to stable on October 15, 2020) and a long-term issuer default rating of BB by Fitch Ratings (rating affirmed and outlook upgraded to stable on January 29, 2021). In April 2020, S&P downgraded our bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% in July 2020. The first coupon payment to the bondholders at the higher interest rate was January 2021. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively.

Cash Flows


	For the years ended December 31,							For the years ended December 31,
(in millions)	2017		2016		2015		(in millions)	2020		2019
Net cash provided by operating activities	$	1,097	$	498	$	1,580	Net cash provided by operating activities	$	528	$	964
Net cash (used in) investing activities		(1,252)		(162)		(1,638)
Net cash used in investing activities							Net cash used in investing activities	(881)		(1,045)
Net cash provided by (used in) financing activities		(352)		1,072		20	Net cash provided by (used in) financing activities	361		(115)

Net cash provided by operating activities increased 120% or $599 million for the year ended December 31, 2017, compared to the same period in 2016, primarily due to an increase in revenues resulting from increased realized commodity prices and a 3% increase in production volumes.

For the year ended December 31, 2016, net cash provided by operating activities decreased 68% or $1,082 million, compared to the same period in 2015, primarily due to a decrease in revenues resulting from a 31% decrease in realized natural gas prices and a 10% decrease in production volumes.

Net cash generated from operating activities provided 85% of our cash requirements for capital investments for the year ended December 31, 2017, compared to net cash from operating activities providing 77% and 63% of our cash requirements for capital investments for the same periods in 2016 and 2015, respectively, reflecting our commitment to our capital discipline strategy of investing within our cash flow from operations net of changes in working capital, supplemented by the remaining proceeds from the 2016 equity issuance and asset sales.

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Index to Financial Statements

Cash Flow from Operations


	For the years ended December 31,
(in millions)	2020		2019
Net cash provided by operating activities	$	528	$	964
Add back (subtract): changes in working capital	77		(69)
Net cash provided by operating activities, net of changes in working capital	$	605	$	895

•Net cash provided by operating activities decreased 45% or $436 million for the year ended December 31, 2020, compared to the same period in 2019, primarily due to a $574 million decrease resulting from lower commodity prices, a $146 million decreased impact of working capital, an $85 million increase in operating costs and a $29 million increase in interest expense. The decreases were partially offset by a $216 million increase associated with increased production and a $182 million increase in our settled derivatives.

•Net cash generated from operating activities, net of changes in working capital, provided 67% of our cash requirements for capital investments for the year ended December 31, 2020, compared to providing 79% of our cash requirements for capital investments for the same period in 2019.

Cash Flow from Investing Activities

For the years ended December 31,
(in millions)
2017

2016

2015
Cash flows from investing activities:

Additions to properties and equipment
$
1,268

$
593

$
2,377
Adjustments for capital investments:

Changes in capital accruals

–

43

(33)
Other non-cash adjustments to properties and equipment

25

12

93
Total capital investing
$
1,293

$
648

$
2,437
•Total E&P capital investing decreased $239 million for the year ended December 31, 2020, compared to the same period in 2019, due to a $197 million decrease in direct E&P capital investing, a $21 million decrease in capitalized internal costs and a $21 million decrease in capitalized interest.

For the years ended December 31,

Increase/

Increase/

(in millions except percentages)
2017

(Decrease)

2016

(Decrease)

2015
Capital investing:

E&P (1)

1,248

623

1,725
Acquisitions

–

–

642
Midstream Services

32

21

58
Other

13

4

12
Total capital investing
$
1,293

100%

$
648

(74%)

$
2,437
•The decrease in capitalized interest for the year ended December 31, 2020, as compared to the same period in 2019, was primarily due to the evaluation of natural gas and oil properties over the past twelve months.

~~(1)~~

Includes $212 million, $239 million and $379 million of capitalized interest and internal costs for the years ended December 31, 2017, 2016 and 2015, respectively. These internal costs were directly related to acquisition, exploration and development activities and are included as part of the cost of natural gas and oil properties.


	For the years ended December 31,
(in millions)	2020		2019
Additions to properties and equipment	$	896	$	1,099
Adjustments for capital investments:
Changes in capital accruals	(3)		35
Other (1)	6		6
Total capital investing	$	899	$	1,140

Total E&P capital investing increased $625 million for the year ended December 31, 2017, compared to the same period in 2016, as a $652 million increase in direct E&P capital investing was only partially offset by a $27 million decrease in capitalized interest and internal costs. The significant increase in 2017 capital investing resulted from our decision to suspend drilling activity in the first half of 2016 due to an unfavorable commodity price environment. We began increasing activity in the second half of 2016.

(1)Includes capitalized non-cash stock-based compensation and costs to retire assets, which are classified as cash used in operating activities.

For the year ended December 31, 2016, total E&P capital investing decreased $1,102 million, compared to the same period in 2015 (excluding 2015 acquisitions), due to a $962 million decrease in direct E&P capital investing and a $140 million decrease in capitalized interest and internal costs. The significant decrease was the result of suspending drilling activity in the first half of 2016 due to an unfavorable commodity price environment.

Capital Investing

The increase in E&P capital investments for the year ended December 31, 2017, as compared to the same period in 2016, reflects our operational flexibility in light of current and expected economic conditions, as we adjusted our activities based on our anticipated cash flows from operation net of changes in working capital.


	For the years ended December 31,
(in millions except percentages)	2020		2019		Increase/ (Decrease)
E&P capital investing	$	899	$	1,138

Other capital investing (1)	—		2
Total capital investing	$	899	$	1,140	(21)%

(1)Other capital investing was immaterial for the year ended December 31, 2020.

Midstream capital investing increased $11 million for the year ended December 31, 2017, compared to the same period in 2016, related primarily to the purchase of several of our leased compressors during 2017 which were subsequently sold to third parties for a net gain of $6 million.

~~For the year ended December 31, 2016, Midstream capital investing decreased $37 million, compared to the same period in 2015, primarily due to reduced activity in the Fayetteville Shale.~~

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Index to Financial Statements


	For the years ended December 31,
(in millions)	2020		2019
E&P Capital Investments by Type:
Exploratory and development, including workovers	$	692	$	838
Acquisition of properties	37		55
Seismic expenditures	—		3
Water infrastructure project	9		35
Other	17		21
Capitalized interest and expenses	144		186
Total E&P capital investments	$	899	$	1,138

E&P Capital Investments by Area
Northeast Appalachia	$	362	$	365
Southwest Appalachia	510		710

Other E&P (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, respectively, related to our water infrastructure project.


	For the years ended December 31,
	2020	2019
Gross Operated Well Count Summary:
Drilled	98	105
Completed	96	116
Wells to sales	100	113

Actual capital expenditure levels may vary significantly from period to period due to many factors, including drilling results, natural gas, oil and NGL prices, industry conditions, the prices and availability of goods and services, and the extent to which properties are acquired or non-strategic assets are sold.

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~~Index to Financial Statements~~

Cash Flow from ~~Financing~~Financing Activities

For the years ended December 31,

Increase/
(in millions except percentages)
2017

2016

(Decrease)
Short-term debt
$
–

$
41

$
(41)
Long-term debt

4,391

4,612

(221)
Total debt
$
4,391

$
4,653

$
(262)
Equity
$
1,979

$
917

$
1,062
Total debt to capitalization ratio (1)

69%

84%

(15%)

Total debt
$
4,391

$
4,653

$
(262)
Less: Cash and cash equivalents

916

1,423

(507)
Debt, net of cash and cash equivalents
$
3,475

$
3,230

$
245
•Net cash provided by financing activities for the year ended December 31, 2020 was $361 million, compared to net cash used in financing activities of $115 million for the same period in 2019.

~~(1)~~

~~Debt, net of cash and cash equivalents is a non-GAAP financial measure of a company’s ability to repay its debts if they were all due today.~~

•In August 2020, we completed debt and equity offerings resulting in $345 million and $152 million in net proceeds, respectively.

Net cash used in financing activities for the year ended December 31, 2017 was $352 million, compared to net cash provided by financing activities of $1,072 million for the same period in 2016. The net cash provided by financing activities in 2016 resulted primarily from our fully-drawn 2016 Term Loan.

•In November 2020, we paid $522 million to retire the Montage senior notes, and repaid the outstanding balance of $200 million related to Montage’s revolving credit facility.

~~In October 2017, we retired $40 million principal amount outstanding of our 2017 Senior Notes.~~

•In 2020, we repurchased $107 million in aggregate principal amount of our outstanding senior notes at a discount for $72 million and recognized a $35 million gain on the extinguishment of debt.

In September 2017, we completed a public offering of $650 million aggregate principal amount of our 7.50% Senior Notes due 2026 and $500 million aggregate principal amount of our 7.75% Senior Notes due 2027, with net proceeds from the offering totaling approximately $1.1 billion, after approximately $17 million in offering expenses.

•In 2019, we paid $54 million on the open market to repurchase $62 million of our outstanding senior notes at a discount. We recognized a gain on early extinguishment of debt of $8 million.

The proceeds from the September 2017 offering were used to repay $758 million of our 4.05% Senior Notes due 2020 and the remaining $327 million principal amount outstanding of our 2015 Term Loan. We recognized a loss on early extinguishment of debt of $59 million.

•In December 2019, we retired the remaining $52 million principal of our 4.05% Senior Notes due January 2020.

~~In the first half of 2017, we redeemed $276 million principal amount outstanding of our 2018 Senior Notes. We recognized a loss on early extinguishment of debt of $11 million.~~

•In January 2019, we repurchased approximately 5 million shares of common stock for approximately $21 million.

We refer you to Note 79 of to the consolidated financial statements included in this Annual Report for additional discussion of our outstanding debt and credit ~~facilities.~~

facility and to N o te 1 for additional discussion of our equity offering.

Working Capital

~~We had positive working capital of $729 million at December 31, 2017 primarily due to $916 million of cash and cash equivalents resulting from our fully-drawn 2016 term loan.~~

•We had negative working capital of $341 million at December 31, 2020, a $172 million decrease from December 31, 2019, as an $8 million increase in cash and cash equivalents was more than offset by a $70 million increase in various payables and a $157 million net reduction in the current mark-to-market value of our derivative position related to improved forward strip pricing across all commodities as compared to December 2019. Additionally, other current liabilities at December 31, 2020 decreased $34 million, compared to December 31, 2019, as a $43 million decrease in our accrued firm transportation liability related to the Fayetteville Shale sale was only partially offset by a prepayment that we received for an unrelated firm transportation assumption. We believe that our existing cash and cash equivalents, our anticipated cash flow from operations and our available credit facility will be sufficient to meet our working capital and operational spending requirements.

At December 31, 2016, we had positive working capital of $808 million primarily due to $1.4 billion of cash and cash equivalents resulting from our fully-drawn 2016 term loan, our July 2016 equity offering and proceeds from the September 2016 sale of our West Virginia acreage.

Table of Contents

Index to Financial Statements

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, ~~2017,~~2020, our material off-balance sheet arrangements and transactions include operating ~~lease~~service arrangements, ~~and $323~~$233 million in letters of credit outstanding against our ~~2016~~2018 revolving credit ~~facility.~~facility and $221 million in outstanding surety bonds. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. For more information regarding off-balance sheet arrangements, we refer you to ~~“Contractual~~“Contractual Obligations and Contingent Liabilities and Commitments” below for more information on our operating leases.

~~Table of Contents~~

~~Index to Financial Statements~~

Contractual Obligations and and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual obligations as of December 31, ~~2017,~~2020, were as follows:

Contractual ~~Obligations~~:

Obligations:

Transportation charges (1)

Interest on debt (2)

Operating leases (3)

Compression services (4)

Other obligations (5)

~~(1)~~

~~As of December 31, 2017, we had commitments for demand and similar charges under firm transport~~(1)As of December 31, 2020, we had commitments for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems. Of the total $9.2 billion, $3.0 billion related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. For further information, we refer you to ~~“Operational Commitments and Contingencies”~~ in ~~Note 8~~ ~~to the consolidated financial statements.~~

~~(2)~~

Interest payments on our senior notes were calculated utilizing the fixed rates associated with our fixed rate notes outstanding at December 31, 2017. Interest payments on the term loan facility were calculated by assuming that the December 31, 2017 outstanding balance of $1,191 million will be outstanding through the December 2020 maturity date. A constant rate of 3.98%, the rate as of December 31, 2017, was assumed for the December 2020 term loan facility. All interest rates were based on our credit ratings as of December 31, 2017.

~~(3)~~

~~Operating leases include costs for compressors, drilling rigs, pressure pumping equipment, aircraft, office space and other equipment under non-cancelable operating leases expiring through 2027.~~

~~(4)~~

As of December 31, 2017, our Midstream segment had commitments of approximately $12 million and our E&P segment had commitments of approximately $3 million for compression services associated primarily with our Fayetteville and Southwest Appalachia divisions.

~~(5)~~

~~Our other significant contractual obligations include approximately $14 million for various information technology support and data subscription agreements.~~

With the close of the Montage Merger we acquired firm transportation commitments of approximately $1,100 million. These commitments approximate $99 million within the next year, $197 million from 1 to 3 years, $196 million from 3 to 5 years, $284 million from 5 to 8 years and $324 million beyond 8 years.

In the ~~table above are future~~first quarter of 2019, we agreed to purchase firm transportation with pipelines in the Appalachian basin starting in 2021 and running through 2032 totaling $357 million in total contractual commitments of which the seller has agreed to reimburse $133 million of these commitments.

(2)Interest payments on our senior notes were calculated utilizing the fixed rates associated with our fixed rate notes outstanding at December 31, 2020. Senior note interest rates were based on our credit ratings as of December 31, 2020.

(3)Operating leases include costs forcompressors, drilling rigs, pressure pumping equipment, office space and other equipment under non-cancelable operating leases expiring through 2036.

(4)As of December 31, 2020, our E&P segment had commitments of approximately $37 million for compression services associated primarily with our Southwest Appalachia division.

(5)Our other significant contractual obligations include approximately $12 million for various information technology support and data subscription agreements.

Future contributions to the pension and postretirement benefit ~~plans.~~plans are excluded from the table above. For further information regarding our pension and other postretirement benefit plans, we refer you to Note 1113 to the consolidated financial statements included in this Annual Report and ““Critical Accounting Policies and ~~Estimates”~~Estimates” below for additional information.

We refer you to Note 79 to the consolidated financial statements included in this Annual Report for a discussion of the terms of our debt.

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.

operations or cash flows.

For further information, we refer you to ~~“Litigation”~~“Litigation” and ~~“Environmental~~“Environmental Risk” in Note 810 to the consolidated financial ~~statements.~~

statements included in this Annual Report.

Supplemental Guarantor Financial Information

SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial ~~Statements~~

Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in the consolidated financial statements of the Company. The Parent and Guarantor Subsidiaries comprise the material operations of the Company. Therefore, the Company concluded that the presentation of the Summarized Financial Information is not required as the Summarized Financial Information of the Company’s Guarantors is not materially different from our consolidated financial statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following describes significant judgments and estimates used in the preparation of our consolidated financial statements.

Natural GasGas and Oil Properties

We utilize the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a quarterly ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives ~~qualifying as cash flow hedges,~~designated for hedge accounting, to calculate the ceiling value of their reserves.

Costs associated with unevaluated properties are excluded from our amortization base until we have evaluated the properties or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Our decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves ~~a significant amount of~~ judgment and may be subject to changes over time based on several factors, including our drilling plans, availability of capital, project economics and drilling results from adjacent acreage. At December 31, ~~2017,~~2020, we had ~~a total of $1,817~~approximately $1,472 million of costs excluded from our amortization base, all of which related to our properties in the United States. Inclusion of some or all of these costs in our properties in the United States in the future, without adding any associated reserves, could result in non-cash ceiling test impairments.

At December 31, ~~2017,~~2020, the ceiling value of our reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of ~~$2.98~~$1.98 per MMBtu, for West Texas Intermediate oil of ~~$47.79~~$39.57 per barrel and NGLs of ~~$14.41~~$10.27 per barrel, adjusted for market differentials. The net book value of our natural gas and oil properties ~~did not exceed~~exceeded the ceiling amount ~~and did not result~~ in aeach quarter of 2020 resulting in total non-cash full cost ceiling test ~~impairment at December 31, 2017. Although no ceiling test impairment was recorded in 2017, future decreases in commodity prices, increases in costs and/or changes in the balance~~write-downs of ~~costs excluded from amortization and other factors may result in impairments to our natural gas and oil properties.~~

The net book value of our United States and Canada natural gas and oil properties exceeded the ceiling by approximately $641 million (net of tax) at March 31, 2016, $297 million (net of tax) at June 30, 2016 and $506 million (net of tax) at September 30, 2016, resulting in non-cash ceiling test impairments in each of those quarters ended those dates.$2,825 million. We had no ~~hedge~~derivative positions that were designated for hedge accounting as of ~~March~~December 31, ~~2016, June 30, 2016~~2020. Future decreases in market prices, as well as changes in production rates, levels of reserves, evaluation costs excluded from amortization, future development costs and production costs may result in further non-cash impairments to our natural gas and oil properties.

No impairment expense was recorded for the year ended December 31, 2020 in relation to our recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, we determined that the fair value of the properties acquired at the closing of the Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, ~~2016.~~ 2021 as long as we can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, we are required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Merger was based on forward strip natural gas and oil pricing existing at the date of the Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Merger. The properties acquired in the Merger have an unamortized cost at December 31, 2020 of $1,087 million. Had we not received the waiver from the SEC, the impairment charge recorded would have been an additional $539 million for the year ended December 31, 2020.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of ~~$2.48~~$2.58 per MMBtu, West Texas Intermediate oil of ~~$39.25~~$55.69 per barrel and NGLs of ~~$6.74~~$11.58 per barrel, adjusted for market differentials, the net book value of our United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, ~~2016.~~2019. We had no derivative positions that were designated for hedge accounting as of December 31, ~~2016.~~

The net book value of our United States natural gas and oil properties exceeded the ceiling by $944 million (net of tax) at June 30, 2015 and $1,746 million (net of tax) at September 30, 2015 and resulted in non-cash ceiling test impairments in the quarters ended those dates. Cash flow hedges of natural gas production in place increased the ceiling amount by approximately $60 million and $40 million as of June 30, 2015 and September 30, 2015, respectively. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.59 per MMBtu,

2019.

Proved natural gas, oil and NGL reserves are a major component of the full cost ceiling test. Natural gas, oil and NGL reserves cannot be measured exactly. Our estimate of natural gas, oil and NGL reserves requires extensive judgments of reservoir engineering data and projections of ~~cost~~costs that will be incurred in developing and producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates under the supervision of our management. Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team ~~to which the property is assigned.~~for that property. The reservoir engineering and financial data included in these estimates are reviewed by senior engineers, who are not part of the asset management teams, and by our ~~Reservoir Supervisor –~~Director of Reserves, who is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our ~~Reservoir Supervisor –~~Director of Reserves has more than 3126 years of experience in petroleum engineering, including the estimation of ~~oil~~natural gas and ~~natural gas~~oil reserves, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining us in ~~2009,~~2018, our ~~Reservoir Supervisor –~~Director of Reserves served in various reservoir engineering roles for ~~Citation~~EP Energy Company, El Paso Corporation, Cabot Oil & Gas Corporation, ~~Mitchell Energy & Development Corporation, White Stone Energy~~Schlumberger and H.J. Gruy & Associates, and is a member of the Society of Petroleum ~~Engineers and Society of Petroleum Evaluation Engineers and is a Licensed Professional Engineer in the state of Texas.~~Engineers. He reports to our ~~Senior~~Executive Vice President ~~– SWN Advance,~~and Chief Operating Officer, who has more than 2332 years of experience in petroleum engineering including the estimation of natural gas, oil and NGL reserves in multiple basins in the United States, and holds a Bachelor of Science in Petroleum ~~Engineering and a Master~~Engineering. Prior to

joining Southwestern in ~~2014,~~2017, our ~~Senior Vice President – SWN Advance~~Chief Operating Officer served in various engineering and leadership roles for ~~Quantum Resource Management, Anadarko Petroleum~~EP Energy Corporation, El Paso Corporation, ARCO Oil and Gas Company, ~~Howell Petroleum~~Burlington Resources and ~~Meridian Oil/Burlington Resources~~Peoples Energy Production, and is a member of the Society of Petroleum ~~Engineers and IPSS.~~

Engineers.

We engage NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates as discussed in more detail below. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the two technical persons primarily responsible for auditing our proved reserves estimates (1) have over 3623 years and over 1519 years of practical experience in petroleum geosciences and petroleum engineering, respectively; (2) have over 2612 years and over 1519 years of experience in the estimation and evaluation of reserves, respectively; (3) each has a college degree; (4) each is a Licensed Professional Geoscientist in the State of Texas or a Licensed Professional Engineer in the State of Texas; (5) each meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and (6) each is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The financial data included in the reserve estimates is also separately reviewed by our accounting staff. Our proved reserves estimates, as internally reviewed and audited by NSAI, are submitted for review and approval to our President and Chief Executive Officer. Finally, upon his approval, NSAI reports the results of its reserve audit to the Board of Directors, with whom final authority over the estimates of our proved reserves rests. A copy of NSAI’s report has been filed as Exhibit 99.1 to this Annual Report.

Proved developed reserves generally have a higher degree of accuracy in this estimation process, when compared to proved undeveloped and proved non-producing reserves, as production history and pressure data over time is available for the majority of our proved developed properties. Proved developed reserves accounted for ~~54%~~68% of our total reserve base as of December 31, ~~2017.~~2020. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. The uncertainties inherent in the reserve estimates are compounded by applying additional estimates of the rates and timing of future production volumes and the costs that will be incurred in developing and producing the reserves. We cannot assure you that our internal controls sufficiently address the numerous uncertainties and risks that are inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. We refer you to “Our proved natural gas, oil and NGL reserves are ~~estimates.~~estimates that include uncertainties. Any material ~~inaccuracies in our reserve estimates~~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, “Risk Factors,” of Part I of this Annual Report for a more detailed discussion of these uncertainties, risks and other factors.

Business Combinations

We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. Fair value of proved natural gas and oil properties as of the acquisition date was based on estimated proved natural gas, oil and NGL reserves and related discounted net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future


	For the year ended December 31,				For the year ended December 31,
(MMBtu/d)	2018	2019	2020	(MMBtu/d)	2021		2022		2023
Firm transportation(1)	1,307,000	1,376,000	1,363,000	1,252,574		938,347		709,498
Firm sales	143,000	73,000	35,000	Firm sales	341,744		127,439		29,864
Total firm takeaway – Northeast Appalachia	1,450,000	1,449,000	1,398,000	Total firm takeaway – Northeast Appalachia	1,594,318		1,065,786		739,362


	For the year ended December 31,				For the year ended December 31,
(MMBtu/d)	2018	2019	2020	(MMBtu/d)	2021		2022		2023
Firm transportation(1)	327,000	777,000	777,000	1,102,016		1,279,900		1,240,539
Firm sales	101,000	55,000	92,000	Firm sales	294,722		47,817		47,817
Total firm takeaway – Southwest Appalachia	428,000	832,000	869,000	Total firm takeaway – Southwest Appalachia	1,396,738		1,327,717		1,288,356


2017 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA

	Appalachia				Fayetteville
	Northeast		Southwest		Shale		Other (1)			Total
Estimated Proved Reserves:
Natural Gas (Bcf):
Developed (Bcf)		3,007		833		3,135		4			6,979
Undeveloped (Bcf)		1,119		2,484		544		–			4,147
		4,126		3,317		3,679		4			11,126
Crude Oil (MMBbls):
Developed (MMBbls)		–		14.2		–		0.3			14.5
Undeveloped (MMBbls)		–		51.1		–		–			51.1
		–		65.3		–		0.3			65.6
Natural Gas Liquids (MMBbls):
Developed (MMBbls)		–		141.9		–		0.3			142.2
Undeveloped (MMBbls)		–		400.2		–		–			400.2
		–		542.1		–		0.3			542.4
Total Proved Reserves (Bcfe) (2):
Developed (Bcfe)		3,007		1,770		3,135		8			7,920
Undeveloped (Bcfe)		1,119		5,192		544		–			6,855
		4,126		6,962		3,679		8			14,775
Percent of Total		28%		47%		25%		0%			100%

Percent Proved Developed		73%		25%		85%		100%			54%
Percent Proved Undeveloped		27%		75%		15%		0%			46%

Production (Bcfe)		395		183		316		3			897
Capital Investments (in millions) (3)	$	489	$	547	$	114	$	41		$	1,191
Total Gross Producing Wells (4)		983		364		4,191		20			5,558
Total Net Producing Wells (4)		516		255		2,921		17			3,709

Total Net Acreage		191,226		290,291		917,842		386,304	(5)		1,785,663
Net Undeveloped Acreage		87,927		219,709		424,858		369,236	(5)		1,101,730

PV-10:
Pre-Tax (in millions) (6)	$	2,085	$	1,718	$	1,978	$	3		$	5,784
PV of Taxes (in millions) (6)		80		66		76		–			222
After-Tax (in millions) (6)	$	2,005	$	1,652	$	1,902	$	3		$	5,562
Percent of Total		36%		30%		34%		0%			100%
Percent Operated (7)		99%		100%		99%		100%			99%


	For the years ended December 31,
Average realized price per unit:	2017		2016		2015
Natural gas sales, excluding derivatives (per Mcf)	$	2.23	$	1.59	$	1.91
Effect of settled gain (loss) on derivatives (per Mcf)		(0.04)		0.05		0.46
Natural gas sales, including derivatives (per Mcf)	$	2.19	$	1.64	$	2.37

Oil sales (per Bbl)	$	43.12	$	31.20	$	33.25

NGL sales, excluding derivatives (per Bbl)	$	14.46	$	7.46	$	6.80
Effect of settled gain (loss) on derivatives (per Bbl)		0.02		–		–
NGL sales, including derivatives (per Bbl)	$	14.48	$	7.46	$	6.80


	Natural Gas		Oil		Total		Gross Wells
	Gross	Net	Gross	Net	Gross	Net	Operated
Appalachia:
Northeast	600	531	–	–	600	531	538
Southwest	387	272	–	–	387	272	360
Fayetteville Shale	4,698	3,243	–	–	4,698	3,243	4,033
Other	10	7	14	14	24	21	22
	5,695	4,053	14	14	5,709	4,067	4,953


	Range of Market Prices
Quarter Ended	2017				2016				2015
	High		Low		High		Low		High		Low
March 31	$	10.68	$	7.20	$	9.90	$	5.30	$	28.02	$	21.46
June 30	$	8.94	$	5.47	$	15.45	$	7.55	$	29.61	$	22.40
September 30	$	6.39	$	5.00	$	15.59	$	11.42	$	22.84	$	11.84
December 31	$	6.72	$	4.90	$	14.40	$	9.14	$	13.90	$	5.00


	12/31/12		12/31/13		12/31/14		12/31/15		12/31/16		12/31/17
Southwestern Energy Company	$	100	$	118	$	82	$	21	$	32	$	17
S&P 500 Index		100		132		151		153		171		208
Peer Group		100		132		112		74		108		97


	For the years ended December 31,
	Natural
(in millions except percentages)	Gas			Oil		NGLs		Total
2016 sales revenues	$	1,252		$	69	$	92	$	1,413
Changes associated with prices		507			28		100		635
Changes associated with production volumes		16			4		14		34
2017 sales revenues	$	1,775		$	101	$	206	$	2,082
Increase from 2016		42%			46%		124%		47%

	For the years ended December 31,
	Natural
(in millions except percentages)	Gas			Oil		NGLs		Total
2015 sales revenues	$	1,923		$	76	$	73	$	2,072
Changes associated with prices		(459)	(1)		(5)		11		(453)
Changes associated with production volumes		(212)			(2)		8		(206)
2016 sales revenues	$	1,252		$	69	$	92	$	1,413
Increase (decrease) from 2015		(35%)			(9%)		26%		(32%)


	Payments Due by Period													Payments Due by Period
	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
	(in millions)
(in millions)													(in millions)	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		5 to 8 Years		More than 8 Years
Transportation charges (1)	$	9,171	$	702	$	1,565	$	1,253	$	1,742	$	3,909	Transportation charges (1)	$	8,544	$	862	$	1,562	$	1,323	$	1,901	$	2,896
Debt		4,433		–		1,283		1,000		1,000		1,150	Debt	3,171		—		207		1,556		1,408		—
Interest on debt (2)		1,646		250		494		370		430		102	Interest on debt (2)	1,070		199		382		310		179		—
Operating leases (3)		213		66		105		31		7		4	Operating leases (3)	131		30		39		26		30		6
Compression services (4)		15		12		3		–		–		–	Compression services (4)	37		20		14		3		—		—
Operating agreements		91		90		1		–		–		–	Operating agreements	4		4		—		—		—		—
Purchase obligations		30		30		–		–		–		–	Purchase obligations	45		45		—		—		—		—
Other obligations (5)		21		10		11		–		–		–	Other obligations (5)	12		9		3		—		—		—
	$	15,620	$	1,160	$	3,462	$	2,654	$	3,179	$	5,165		$	13,014	$	1,169	$	2,207	$	3,218	$	3,518	$	2,902


	Increase (Decrease) of Annual Pension Expense					Increase (Decrease) of Annual Pension Expense
(in millions)	0.5% Increase		0.5% Decrease		(in millions)	0.5% Increase		0.5% Decrease
Discount rate	$	(1)	$	1	Discount rate	$	(1)	$	1
Expected long-term rate of return	$	–	$	–	Expected long-term rate of return	$	—	$	—


	Expected Maturity Date
	2017		2018		2019		2020			2021		Thereafter		Total
Fixed Rate payments (1) (in millions)	$	−	$	−	$	−	$	92		$	−	$	3,150		$	3,242
Weighted Average Interest Rate		− %		− %		− %		5.80%			− %		6.21%			6.19%

Variable Rate Payments (1) (in millions)	$	−	$	−	$	−	$	1,191	(2)	$	−	$	−		$	1,191
Weighted Average Interest Rate		− %		− %		− %		3.98%			− %		– %			3.98%


			Page
Management’s Report on Internal Control Over Financial Reporting			69 72
Report of Independent Registered Public Accounting Firm			69 72
Consolidated Statements of Operations for the three years ended December 31, ~~2017~~2020			71 75
Consolidated Statements of Comprehensive Income (Loss) for the three years ended December 31, ~~2017~~2020			72 76
Consolidated Balance Sheets as of December 31, ~~2017~~2020 and ~~2016~~2019			73 77
Consolidated Statements of Cash Flows for the three years ended December 31, ~~2017~~2020			74 78
Consolidated Statements of Changes in Equity for the three years ended December 31, ~~2017~~2020			75 79
Notes to Consolidated Financial Statements			76 80
Note 1 – Organization and Summary of Significant Accounting Policies			76 80
Note 2 – ~~Reduction in Workforce~~Restructuring Charges			82 87
Note 3 – Acquisitions and Divestitures			83 88
Note 4 – Leases			91
Note 5 – Revenue Recognition			92
Note 6 – Derivatives and Risk Management			84 94
Note 57 – Reclassifications from Accumulated Other Comprehensive Income (Loss)			88 102
Note 68 – Fair Value Measurements			88 102
Note 79 – Debt			90 105
Note 810 – Commitments and Contingencies			93 108
Note 911 – Income Taxes			95 109
Note 1012 – Asset Retirement Obligation			97 112
Note 1113 – Retirement and Employee Benefit Plans			97 112
Note 1214 – ~~Stock-Based~~Long-Term Incentive Compensation			~~102~~ 117
Note 1315 – Segment Information			~~105~~ 122

Supplemental Quarterly Results (Unaudited)			~~107~~ 124
Supplemental Oil and Gas Disclosures (Unaudited)			~~107~~ 124


~~UNITED STATES~~


SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	For the years ended December 31,
	2017(1)		2016		2015
	(in millions)
Net income (loss)	$	1,046	$	(2,643)	$	(4,556)

Change in derivatives:
Settlements (2)		–		–		(128)
Ineffectiveness		–		–		1
Change in fair value of derivative instruments (3)		–		–		29
Total change in derivatives		–		–		(98)

Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic pension cost (4)		2		13		2
Net loss incurred in period (5)		(13)		(7)		(3)
Total change in value of pension and postretirement liabilities		(11)		6		(1)

Change in currency translation adjustment		6		3		(11)

Comprehensive income (loss)	$	1,041	$	(2,634)	$	(4,666)


	December 31,		December 31,
	2017		2016			December 31, 2020		December 31, 2019
ASSETS		(in millions)			ASSETS	(in millions, except share amounts)
Current assets:					Current assets:
Cash and cash equivalents	$	916	$	1,423	Cash and cash equivalents	$	13	$	5
Accounts receivable, net		428		363	Accounts receivable, net	368		345
Derivative assets		130		51	Derivative assets	241		278
Other current assets		35		35	Other current assets	49		51
Total current assets		1,509		1,872	Total current assets	671		679
Natural gas and oil properties, using the full cost method, including $1,817 million as of December 31, 2017 and $2,105 million as of December 31, 2016 excluded from amortization		23,890		22,653
Gathering systems		1,315		1,299
Natural gas and oil properties, using the full cost method, including $1,472 million as of December 31, 2020 and $1,506 million as of December 31, 2019 excluded from amortization					Natural gas and oil properties, using the full cost method, including $1,472 million as of December 31, 2020 and $1,506 million as of December 31, 2019 excluded from amortization	27,261		25,250
Other		564		537	Other	523		520
Less: Accumulated depreciation, depletion and amortization		(19,997)		(19,534)	Less: Accumulated depreciation, depletion and amortization	(23,673)		(20,503)
Total property and equipment, net		5,772		4,955	Total property and equipment, net	4,111		5,267
Operating lease assets					Operating lease assets	163		159
Deferred tax assets					Deferred tax assets	0		407
Other long-term assets		240		249	Other long-term assets	215		205
Total long-term assets					Total long-term assets	378		771
TOTAL ASSETS	$	7,521	$	7,076	TOTAL ASSETS	$	5,160	$	6,717
LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:					Current liabilities:
Short-term debt	$	–	$	41

Accounts payable		533		473	Accounts payable	$	573	$	525
Taxes payable		62		59	Taxes payable	74		59
Interest payable		70		74	Interest payable	58		51
Dividends payable		27		27
Derivative liabilities		64		355	Derivative liabilities	245		125
Current operating lease liabilities					Current operating lease liabilities	42		34
Other current liabilities		24		35	Other current liabilities	20		54
Total current liabilities		780		1,064	Total current liabilities	1,012		848
Long-term debt		4,391		4,612	Long-term debt	3,150		2,242
Long-term operating lease liabilities					Long-term operating lease liabilities	117		119
Long-term derivative liabilities					Long-term derivative liabilities	183		111
Pension and other postretirement liabilities		58		49	Pension and other postretirement liabilities	45		43
Other long-term liabilities		313		434	Other long-term liabilities	156		108
Total long-term liabilities		4,762		5,095	Total long-term liabilities	3,651		2,623
Commitments and contingencies (see Note 8)
Commitments and contingencies (Note 10)					Commitments and contingencies (Note 10)	0		0
Equity:					Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 512,134,311 shares as of December 31, 2017 and 495,248,369 as of December 31, 2016		5		5
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding as of December 31, 2017 and 2016, converted to common stock in January 2018		–		–
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 718,795,700 shares as of December 31, 2020 and 585,555,923 as of December 31, 2019					Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 718,795,700 shares as of December 31, 2020 and 585,555,923 as of December 31, 2019	7		6
Additional paid-in capital		4,698		4,677	Additional paid-in capital	5,093		4,726
Accumulated deficit		(2,679)		(3,725)	Accumulated deficit	(4,363)		(1,251)
Accumulated other comprehensive loss		(44)		(39)	Accumulated other comprehensive loss	(38)		(33)
Common stock in treasury, 31,269 shares as of December 31, 2017 and 2016		(1)		(1)
Common stock in treasury, 44,353,224 shares as of December 31, 2020 and 2019					Common stock in treasury, 44,353,224 shares as of December 31, 2020 and 2019	(202)		(202)
Total equity		1,979		917	Total equity	497		3,246
TOTAL LIABILITIES AND EQUITY	$	7,521	$	7,076	TOTAL LIABILITIES AND EQUITY	$	5,160	$	6,717


	For the twelve months ended							For the years ended December 31,
	December 31,
	2017		2016		2015
		(in millions)
(in millions)							(in millions)	2020		2019		2018
Cash Flows From Operating Activities:							Cash Flows From Operating Activities:
Net income (loss)	$	1,046	$	(2,643)	$	(4,556)	Net income (loss)	$	(3,112)	$	891	$	537
Adjustments to reconcile net income (loss) to net cash provided by operating activities:							Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		504		436		1,092	Depreciation, depletion and amortization	357		471		560
Impairment of natural gas and oil properties		–		2,321		6,950
Amortization of debt issuance costs		9		14		53	Amortization of debt issuance costs	9		8		8
Impairments							Impairments	2,830		16		171
Deferred income taxes		(71)		(22)		(2,003)	Deferred income taxes	409		(409)		0
(Gain) loss on derivatives, unsettled		(451)		373		155	(Gain) loss on derivatives, unsettled	138		(94)		24
Stock-based compensation		24		29		26	Stock-based compensation	3		8		14
Gain on sale of assets, net		(6)		–		(283)
Restructuring charges		–		30		–
Loss on early extinguishment of debt		70		51		–
(Gain) loss on early extinguishment of debt							(Gain) loss on early extinguishment of debt	(35)		(8)		17
(Gain) loss on sale of assets							(Gain) loss on sale of assets	0		2		(17)

Other		13		8		34	Other	6		10		(1)
Change in assets and liabilities:							Change in assets and liabilities:
Accounts receivable		(65)		(30)		203	Accounts receivable	50		234		(153)
Accounts payable		48		(69)		(78)	Accounts payable	(131)		(141)		65
Taxes payable		4		(5)		(28)	Taxes payable	(7)		0		2
Interest payable		(2)		–		9	Interest payable	(11)		0		(10)
Inventories							Inventories	2		(7)		(13)
Other assets and liabilities		(26)		5		6	Other assets and liabilities	20		(17)		19
Net cash provided by operating activities		1,097		498		1,580	Net cash provided by operating activities	528		964		1,223

Cash Flows From Investing Activities:							Cash Flows From Investing Activities:
Capital investments		(1,268)		(593)		(1,798)	Capital investments	(896)		(1,099)		(1,290)
Acquisitions		–		–		(579)
Proceeds from sale of property and equipment		10		430		729	Proceeds from sale of property and equipment	12		54		1,643
Cash acquired in Montage merger							Cash acquired in Montage merger	3		0		0
Other		6		1		10	Other	0		0		6
Net cash used in investing activities		(1,252)		(162)		(1,638)
Net cash provided by (used in) investing activities							Net cash provided by (used in) investing activities	(881)		(1,045)		359

Cash Flows From Financing Activities:							Cash Flows From Financing Activities:
Payments on current portion of long-term debt		(328)		(1)		(1)	Payments on current portion of long-term debt	0		(52)		0
Payments on long-term debt		(1,139)		(1,175)		(500)	Payments on long-term debt	(72)		(54)		(2,095)
Payments on short-term debt		–		–		(4,500)
Payments on revolving credit facility		–		(3,268)		(3,024)	Payments on revolving credit facility	(1,671)		(532)		(1,983)
Borrowings under revolving credit facility		–		3,152		2,840	Borrowings under revolving credit facility	2,337		566		1,983
Payments on commercial paper		–		(242)		(7,988)
Borrowings under commercial paper		–		242		7,988
Change in bank drafts outstanding		9		(20)		12	Change in bank drafts outstanding	1		(19)		17
Repayment of Montage revolving credit facility							Repayment of Montage revolving credit facility	(200)		0		0
Repayment of Montage senior notes							Repayment of Montage senior notes	(522)		0		0
Proceeds from issuance of long-term debt		1,150		1,191		2,950	Proceeds from issuance of long-term debt	350		0		0
Payment of debt issuance costs		(24)		(17)		(20)
Debt issuance and other financing costs							Debt issuance and other financing costs	(10)		(3)		(9)
Proceeds from issuance of common stock		–		1,247		669	Proceeds from issuance of common stock	152		0		0
Proceeds from issuance of mandatory convertible preferred stock		–		–		1,673
Purchase of treasury stock							Purchase of treasury stock	0		(21)		(180)
Preferred stock dividend		(16)		(27)		(79)	Preferred stock dividend	0		0		(27)
Cash paid for tax withholding		(2)		(9)		–	Cash paid for tax withholding	(4)		(1)		(3)
Other		(2)		(1)		–	Other	0		1		0
Net cash provided by (used in) financing activities		(352)		1,072		20	Net cash provided by (used in) financing activities	361		(115)		(2,297)

Increase (decrease) in cash and cash equivalents		(507)		1,408		(38)	Increase (decrease) in cash and cash equivalents	8		(196)		(715)
Cash and cash equivalents at beginning of year		1,423		15		53	Cash and cash equivalents at beginning of year	5		201		916
Cash and cash equivalents at end of year	$	916	$	1,423	$	15	Cash and cash equivalents at end of year	$	13	$	5	$	201


																Common Stock				Preferred Stock		Additional Paid-In Capital				Accumulated Deficit				Accumulated Other Comprehensive Income (Loss)					Common Stock in Treasury
				Preferred			Retained		Accumulated
	Common Stock			Stock	Additional		Earnings		Other		Common
	Shares			Shares	Paid-In		(Accumulated		Comprehensive		Stock in
	Issued	Amount		Issued	Capital		Deficit)(1)		Income (Loss)		Treasury		Total
	(in millions, except share amounts)
Balance at December 31, 2014	354,488,992	$	4	–	$	1,019	$	3,577	$	62	$	–	$	4,662
Comprehensive loss:
Net loss	–		–	–		–		(4,556)		–		–		(4,556)
Other comprehensive loss	–		–	–		–		–		(110)		–		(110)
Total comprehensive loss	–		–	–		–		–		–		–		(4,666)
Stock-based compensation	–		–	–		48		–		–		–		48
Preferred stock dividend	–		–	–		–		(106)		–		–		(106)
Issuance of common stock	30,000,000		–	–		669		–		–		–		669
Issuance of preferred stock	–		–	1,725,000		1,673		–		–		–		1,673
Issuance of restricted stock	5,821,125		–	–		–		–		–		–		–
Cancellation of restricted stock	(103,162)		–	–		–		–		–		–		–
Treasury stock – non-qualified plan	–		–	–		–		–		–		(1)		(1)
Tax withholding – stock compensation	(73,869)		–	–		–		–		–		–		–
Issuance of stock awards	5,463		–	–		–		–		–		–		–
Non-controlling interest	–		–	–		–		3		–		–		3
Balance at December 31, 2015	390,138,549	$	4	1,725,000	$	3,409	$	(1,082)	$	(48)	$	(1)	$	2,282
Comprehensive loss:
Net loss	–		–	–		–		(2,643)		–		–		(2,643)
Other comprehensive loss	–		–	–		–		–		9		–		9
Total comprehensive loss	–		–	–		–		–		–		–		(2,634)
Stock-based compensation	–		–	–		58		–		–		–		58
Preferred stock dividend	7,166,389		–	–		(27)		–		–		–		(27)
Exercise of stock options	44,880		–	–		–		–		–		–		–
Issuance of common stock	98,900,000		1	–		1,246		–		–		–		1,247
Issuance of restricted stock	87,472		–	–		–		–		–		–		–
Cancellation of restricted stock	(165,483)		–	–		–		–		–		–		–
Tax withholding – stock compensation	(929,252)		–	–		(9)		–		–		–		(9)
Issuance of stock awards	5,814		–	–		–		–		–		–		–
Balance at December 31, 2016	495,248,369	$	5	1,725,000	$	4,677	$	(3,725)	$	(39)	$	(1)	$	917
Comprehensive income:
(in millions, except share amounts)															(in millions, except share amounts)		Shares Issued	Amount			Shares Issued				Additional Paid-In Capital								Accumulated Deficit					Accumulated Other Comprehensive Income (Loss)				Shares				Amount		Total
Balance at December 31, 2017															Balance at December 31, 2017		512,134,311	$	5		1,725,000								31,269						$	(1)						$	1,979
Comprehensive income															Comprehensive income
Net income	–		–	–		–		1,046		–		–		1,046	Net income		—	—			—		—						537					—					—				—				537
Other comprehensive income	–		–	–		–		–		(5)		–		(5)	Other comprehensive income		—	—			—		—				—				8						—				—				8
Total comprehensive income	–		–	–		–		–		–		–		1,041	Total comprehensive income		—	—			—		—				—				—					—				—				545
Stock-based compensation	–		–	–		38		–		–		–		38	Stock-based compensation		—	—			—		21				—				—					—				—				21
Preferred stock dividend	12,791,716					(16)								(16)	Preferred stock dividend		74,998,614	1			(1,725,000)		(1)				—				—					—				—				0
Issuance of restricted stock	5,055,208		–	–		–		–		–		–		–	Issuance of restricted stock		349,562	—			—		—				—				—					—				—				—
Cancellation of restricted stock	(742,028)		–	–		–		–		–		–		–	Cancellation of restricted stock		(1,804,122)	—			—		—				—				—					—				—				—
Performance units vested	121,208		–	–		–		–		–		–		–	Performance units vested		214,866	—			—		—				—				—					—				—				—

Treasury stock															Treasury stock		—	—			—		—				—				—					39,061,268				(180)				(180)
Tax withholding – stock compensation	(340,234)		–	–		(1)		–		–		–		(1)	Tax withholding – stock compensation		(486,124)	—			—		(3)				—				—					—				—				(3)
Issuance of stock awards	72		–	–		–		–		–		–		–
Balance at December 31, 2017	512,134,311	$	5	1,725,000	$	4,698	$	(2,679)	$	(44)	$	(1)	$	1,979
Balance at December 31, 2018															Balance at December 31, 2018		585,407,107	$	6		0		$	4,715			$	(2,142)			$	(36)				39,092,537				$	(181)			$	2,362
Comprehensive income															Comprehensive income
Net income															Net income		—	—			—		—				891				—					—				—				891
Other comprehensive income															Other comprehensive income		—	—			—		—				—				3					—				—				3
Total comprehensive income															Total comprehensive income		—	—			—		—				—				—					—				—				894
Stock-based compensation															Stock-based compensation		—	—			—		12				—				—					—				—				12
Issuance of restricted stock															Issuance of restricted stock		236,978	—			—		—				—				—					—				—				—
Cancellation of restricted stock															Cancellation of restricted stock		(239,571)	—			—		—				—				—					—				—				—
Performance units vested															Performance units vested		535,802	—			—		—				—				—					—				—				—
Treasury stock															Treasury stock		—	—			—		—				—				—					5,260,687				(21)				(21)
Tax withholding – stock compensation															Tax withholding – stock compensation		(384,393)	—			—		(1)				—				—					—				—				(1)
Balance at December 31, 2019															Balance at December 31, 2019		585,555,923	$	6		0		$	4,726			$	(1,251)			$	(33)				44,353,224				$	(202)			$	3,246
Comprehensive loss															Comprehensive loss
Net loss															Net loss		—	—			—		—				(3,112)				—					—				—				(3,112)
Other comprehensive loss															Other comprehensive loss		—	—			—		—				—				(5)					—				—				(5)
Total comprehensive loss															Total comprehensive loss		—	—			—		—				—				—					—				—				(3,117)
Stock-based compensation															Stock-based compensation		—	—			—		4				—				—					—				—				4
Issuance of common stock															Issuance of common stock		63,250,000	—			—		152				—				—					—				—				152
Issuance of restricted stock															Issuance of restricted stock		311,446	—			—		—				—				—					—				—				—
Cancellation of restricted stock															Cancellation of restricted stock		(1,274,802)	—			—		—				—				—					—				—				—
Restricted units granted															Restricted units granted		2,697,170	—			—		3				—				—					—				—				3
Montage merger exchange															Montage merger exchange		69,740,848	1			—		212				—				—					—				—				213

Tax withholding – stock compensation															Tax withholding – stock compensation		(1,484,885)	—			—		(4)				—				—					—				—				(4)
Balance at December 31, 2020															Balance at December 31, 2020		718,795,700	$	7		0		$	5,093			$	(4,363)			$	(38)				44,353,224				$	(202)			$	497


Water facilities			5 – 10 years
Gathering systems			15 – 25 years
Technology infrastructure			3 – 7 years
Drilling rigs and equipment			3 years
Buildings and leasehold improvements			10 – 30 years


	For the years ended December 31,							For the years ended December 31,
(in millions, except share/per share amounts)	2017		2016		2015		(in millions, except share/per share amounts)	2020		2019		2018
Net income (loss)	$	1,046	$	(2,643)	$	(4,556)	Net income (loss)	$	(3,112)	$	891	$	537
Mandatory convertible preferred stock dividend		108		108		106

Participating securities – mandatory convertible preferred stock		123		–		–	Participating securities – mandatory convertible preferred stock	0		0		2
Net income (loss) attributable to common stock	$	815	$	(2,751)	$	(4,662)	Net income (loss) attributable to common stock	$	(3,112)	$	891	$	535

Number of common shares:							Number of common shares:
Weighted average outstanding		498,264,321		435,337,402		380,521,039	Weighted average outstanding	573,889,502		539,345,343		574,631,756
Issued upon assumed exercise of outstanding stock options		–		–		–	Issued upon assumed exercise of outstanding stock options	0		0		0
Effect of issuance of non-vested restricted common stock		1,061,056		–		–	Effect of issuance of non-vested restricted common stock	0		361,380		698,103
Effect of issuance of non-vested restricted units							Effect of issuance of non-vested restricted units	0		0		0
Effect of issuance of non-vested performance units		1,478,920		–		–	Effect of issuance of non-vested performance units	0		676,191		1,312,949
Effect of issuance of mandatory convertible preferred stock		–		–		–
Effect of declaration of preferred stock dividends		–		–		–
Weighted average and potential dilutive outstanding		500,804,297		435,337,402		380,521,039	Weighted average and potential dilutive outstanding	573,889,502		540,382,914		576,642,808

Earnings (loss) per common share:							Earnings (loss) per common share:
Basic	$	1.64	$	(6.32)	$	(12.25)	Basic	$	(5.42)	$	1.65	$	0.93
Diluted	$	1.63	$	(6.32)	$	(12.25)	Diluted	$	(5.42)	$	1.65	$	0.93


			(in millions)
~~Severance (including payroll taxes)~~ Liability at December 31, 2019		$	$ 2	44
~~Stock-based compensation~~ Additions		16			24
~~Pension and other post retirement benefits~~ ~~(1)~~ Distributions		(15)			5
~~Other benefits~~ Liability at December 31, 2020		$	3	3
~~Outplacement services, other~~		2
~~Total restructuring charges~~ ~~(2)~~	$	78


(in millions, except share, per share amounts)	As of November 13, 2020
Shares of Southwestern common stock issued in respect of outstanding Montage common stock	67,311,166
Shares of Southwestern common stock issued in respect of Montage stock-based awards	2,429,682
	69,740,848
NYSE closing price per share of Southwestern common shares on November 13, 2020	$	3.05
Total consideration (fair value of Southwestern common shares issued)	$	213
Increase in Southwestern common stock ($0.01 par value per share)	1
Increase in Southwestern additional paid-in capital	$	212


(in millions)	As of November 13, 2020
Consideration:
Fair value of Southwestern’s stock issued on November 13, 2020	$	213
Fair value of assets acquired:
Cash and cash equivalents	3
Accounts receivable	73
Other current assets	1
Derivative assets	11
Evaluated natural gas and oil properties	1,012
Unevaluated natural gas and oil properties	90
Other property, plant and equipment	28
Other long-term assets	26
Total assets acquired	1,244
Fair value of liabilities assumed:
Accounts payable	145
Other current liabilities	49
Derivative liabilities	70
Revolving credit facility	200
Senior unsecured notes	522
Asset retirement obligations	28
Other long-term liabilities	17
Total liabilities assumed	1,031
Net assets acquired and liabilities assumed	$	213


	For the years ended December 31,
(in millions, except per share amounts)	2020		2019
Revenues	$	2,701	$	3,673
Net income (loss) attributable to common stock	$	(3,177)	$	995
Net income (loss) attributable to common stock per share – basic	$	(4.71)	$	1.48
Net income (loss) attributable to common stock per share – diluted	$	(4.71)	$	1.48



(in millions)	For the year ended December 31, 2020
Bank, legal and consulting fees	$	18
Employee severance and related costs	17
Contract buyouts	5
Other	1
Total Montage merger-related expenses	$	41


~~Consideration:~~		~~(in millions)~~
~~Cash~~	$	~~270~~
~~Recognized amounts of identifiable assets acquired and liabilities assumed:~~
~~Assets acquired:~~
~~Proved natural gas and oil properties~~		31
~~Unproved natural gas and oil properties~~		~~114~~
~~Intangible asset~~		~~109~~
~~Gathering system~~		22
~~Other~~		1
~~Total assets acquired~~		~~277~~
~~Liabilities assumed:~~
~~Asset retirement obligations~~		~~(7)~~
~~Total liabilities assumed~~		~~(7)~~
	$	~~270~~


(in millions)	E&P		Marketing		Intersegment Revenues		Total
Year ended December 31, 2020
Gas sales	$	928	$	0	$	39	$	967
Oil sales	150		0		4		154
NGL sales	265		0		0		265
Marketing	0		2,145		(1,228)		917
Other (1)	5		0		0		5
Total	$	1,348	$	2,145	$	(1,185)	$	2,308

Year ended December 31, 2019
Gas sales	$	1,207	$	0	$	34	$	1,241
Oil sales	220		0		3		223
NGL sales	274		0		0		274
Marketing	0		2,849		(1,552)		1,297
Other (1)	2		1		0		3
Total	$	1,703	$	2,850	$	(1,515)	$	3,038

Year ended December 31, 2018
Gas sales	$	1,974	$	0	$	24	$	1,998
Oil sales	193		0		3		196
NGL sales	353		0		(1)		352
Marketing	0		3,497		(2,275)		1,222
Gas gathering (2)	0		248		(159)		89
Other (1)	5		0		0		5
Total	$	2,525	$	3,745	$	(2,408)	$	3,862


Fixed price swaps		~~The~~If the Company sells a fixed price swap, the Company receives a fixed price for the contract and pays a floating market to the counterparty. If the Company purchases a fixed price swap, the Company receives a floating market price for the contract and pays a fixed price to the counterparty.
~~Purchased put options~~		The Company purchases put options based on an index price from the counterparty by payment of a cash premium. If the index price is lower than the put’s strike price at the time of settlement, the Company receives from the counterparty such difference between the index price and the purchased put strike price. If the market price settles above the put’s strike price, no payment is due from either party.
Two-way costless collars	Arrangements that contain a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price.
Three-way costless collars		Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.


Basis swaps		Arrangements that guarantee a price differential for natural gas from a specified delivery point. ~~The~~If the Company sells a basis swap, the Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the Company purchases a basis swap, the Company pays the counterparty if the price differential is greater than the state terms of the contract and receives a payment from the counterparty if the price differential is less than the stated terms of the contract.
~~Purchased call~~Call options		The Company purchases and sells call options in exchange for a premium. If the Company purchases a call option, the Company receives from the counterparty the excess (if any) of the market price ~~exceeds~~over the strike price of the call option at the time of settlement, ~~the Company receives from the counterparty such difference between the index price and the purchased call strike price. If~~but if the market price ~~settles~~is below the call’s strike price, no payment is due from either party.
~~Sold call options~~	~~The~~ If the Company sells a call ~~options in exchange for a premium. If~~option, the Company pays the counterparty the excess (if any) of the market price ~~exceeds~~over the strike price ~~of the call option~~ at the time of settlement, ~~the Company pays the counterparty such excess on sold call options. If~~but if the market price ~~settles~~is below the call’s strike price, no payment is due from either party.
Swaptions		Instruments that refer to an option to enter into a fixed price swap. In exchange for an option premium, the purchaser gains the right but not the obligation to enter a specified swap agreement with the issuer for specified future dates. If the Company sells a swaption, the counterparty has the right to enter into a fixed price swap wherein the Company receives a fixed price for the contract and pays a floating market price to the counterparty. If the Company purchases a swaption, the Company has the right to enter into a fixed price swap wherein the Company receives a floating market price for the contract and pays a fixed price to the counterparty.
Interest rate swaps		Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes.


		Weighted Average Price per MMBtu
Financial protection on production	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential		Fair value at December 31, 2017 ($ in millions)
2018
Fixed price swaps	194	$	3.02	$	–	$	–	$	–	$	–	$	38
Two-way costless collars	23		–		–		2.97		3.56		–		4
Three-way costless collars	272		–		2.40		2.97		3.37		–		46
Total	489											$	88
2019
Fixed price swaps	93	$	3.00	$	–	$	–	$	–	$	–	$	17
Three-way costless collars	108		–		2.50		2.95		3.32		–		9
Total	201											$	26

Basis swaps
2018	44	$	–	$	–	$	–	$	–	$	(0.48)	$	(21)
2019	–		–		–		–		–		(0.59)		–
Total	44											$	(21)


Purchased call options	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair value at December 31, 2017 ($ in millions)
2018	13	$	3.23	$	2	(1)
	13			$	2

Sold call options
2018	63	$	3.50	$	(3)
2019	52		3.50		(5)
2020	68		3.63		(4)
2021	57		3.52		(6)
Total	240			$	(18)


		Weighted Average Price per MMBtu										Fair value at December 31, 2020 ($ in millions)
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls		Basis Differential
Natural Gas
2021
Fixed price swaps	201	$	2.80	$	—	$	—	$	—	$	—	$	29
Two-way costless collars	237	—		—		2.57		2.95		—		11
Three-way costless collars	313	—		2.16		2.49		2.85		—		(24)
Total	751											$	16
2022
Fixed price swaps	112	$	2.68	$	—	$	—	$	—	$	—	$	4
Two-way costless collars	63	—		—		2.52		3.03		—		(1)
Three-way costless collars	203	—		2.06		2.46		2.89		—		(15)
Total	378											$	(12)
2023
Three-way costless collars	87	$	—	$	2.06	$	2.47	$	2.98	$	—	$	0

Basis swaps
2021	219	$	—	$	—	$	—	$	—	$	(0.21)	$	57
2022	139	—		—		—		—		(0.33)		8
2023	47	—		—		—		—		(0.45)		0
2024	11	—		—		—		—		(0.60)		0
2025	4	—		—		—		—		(0.59)		0
Total	420											$	65


		Weighted Average Price per Bbl								Fair value at December 31, 2020 ($ in millions)
	Volume (MBbls)	Swaps		Sold Puts		Purchased Puts		Sold Calls
Oil
2021
Fixed price swaps	4,887	$	48.59	$	—	$	—	$	—	$	1
Two-way costless collars	201	—		—		37.73		45.68		(1)
Three-way costless collars	1,543	—		37.42		47.22		52.86		0
Total	6,631									$	0
2022
Fixed price swaps	1,282	$	46.37	$	—	$	—	$	—	$	0
Three-way costless collars	873	0		40.25		50.78		56.54		1
Total	2,155									$	1
2023
Three-way costless collars	878	$	0	$	33.52	$	43.52	$	53.41	$	(1)

Ethane
2021
Fixed price swaps	5,889	$	7.12	$	—	$	—	$	—	$	(10)
Two-way costless collars	584	—		—		7.14		10.40		0
Total	6,473									$	(10)
2022
Fixed price swaps	1,575	$	8.69	$	—	$	—	$	—	$	0
Two-way costless collars	135	—		—		7.56		9.66		0
Total	1,710									$	0

Propane
2021
Fixed price swaps	6,974	$	20.43	$	—	$	—	$	—	$	(36)
2022
Fixed price swaps	2,120	$	20.23	$	—	$	—	—		$	(2)

Normal Butane
2021
Fixed price swaps	2,004	$	24.97	$	—	$	—	$	—	$	(8)
2022
Fixed price swaps	667	$	22.77	$	—	$	—	$	—	$	(1)

Natural Gasoline
2021
Fixed price swaps	1,936	$	37.35	$	—	$	—	$	—	$	(13)
2022
Fixed price swaps	643	$	37.77	$	—	$	—	$	—	$	(2)


Other Derivative Contracts
	Volume (Bcf)	Weighted Average Strike Price per MMBtu		Fair value at December 31, 2020 ($ in millions)
Call Options – Natural Gas (Net)
2021	75	$	3.19	$	(8)
2022	77	3.00		(17)
2023	46	2.94		(8)
2024	9	3.00		(3)
Total	207			$	(36)

Put Options – Natural Gas
2021	18	$	2.00	$	(1)
2022	5	2.00		0
Total	23			$	(1)