sm-20211231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☑ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2021

☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission file number 001-31539

SM ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware

41-0518430

(State or other jurisdiction of incorporation or organization)

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

1775 Sherman Street, Suite 1200, Denver, Colorado

80203

(Address of principal executive offices)

(Zip Code)

(303) 861-8140

(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, $.01 par value	SM	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 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

☐

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 119,336,315 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on June 30, 2021, the last business day of the registrant’s most recently completed second fiscal quarter, of $24.63 per share, as reported on the New York Stock Exchange, was $2,939,253,438. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 10, 2022, the registrant had 121,862,248 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13, and 14 of Part III of this report is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule 14A relating to its 2022 annual meeting of stockholders, to be filed within 120 days after December 31, 2021.


TABLE OF CONTENTS
Item		Page
	Cautionary Information about Forward-Looking Statements	4
	Glossary	5
	Part I	8
Items 1. and 2.	Business and Properties	8
	General	8
	Strategy	8
	Significant Developments in 2021	8
	Outlook	9
	Areas of Operation	9
	Reserves	11
	Production	15
	Productive Wells	15
	Drilling and Completion Activity	16
	Title to Properties	16
	Acreage	17
	Delivery Commitments	17
	Major Customers	17
	Human Capital	17
	Seasonality	18
	Competition	19
	Government Regulations	19
	Available Information	22
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35
	Part II	36
Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	36
Item 6.	[Reserved]	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
	Overview of the Company	38
	Financial Results of Operations and Additional Comparative Data	42
	Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019	45
	Overview of Liquidity and Capital Resources	48
	Critical Accounting Policies and Estimates	52
	Accounting Matters	55
	Environmental	55
	Non-GAAP Financial Measures	56
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	57
Item 8.	Consolidated Financial Statements and Supplementary Data	58
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	100
Item 9A.	Controls and Procedures	101
Item 9B.	Other Information	104
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspection	104


TABLE OF CONTENTS
(Continued)
Item		Page
	Part III	104
Item 10.	Directors, Executive Officers, and Corporate Governance	104
Item 11.	Executive Compensation	104
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	104
Item 13.	Certain Relationships and Related Transactions, and Director Independence	105
Item 14.	Principal Accountant Fees and Services	105
	Part IV	106
Item 15.	Exhibits and Consolidated Financial Statement Schedules	106
Item 16.	Form 10-K Summary	109
	Signatures	110

Cautionary Information about Forward-Looking Statements

This Annual Report on Form 10-K (“Form 10-K” or “this report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements included in this report, other than statements of historical facts, that address activities, conditions, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “pending,” “plan,” “potential,” “projected,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:

•the impacts of the global COVID-19 pandemic (“Pandemic”) on us, our industry, our financial condition, and our results of operations;

•the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;

•any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (“Credit Agreement”);

•our outlook on prices for future crude oil, natural gas, and natural gas liquids (also referred to throughout this report as “oil,” “gas,” and “NGLs,” respectively), well costs, service costs, production costs, and general and administrative costs;

•our drilling and completion activities and other exploration and development activities, our ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;

•possible or expected acquisitions and divestitures, including the possible divestiture or farm-out of, or farm-in or joint development of, certain properties;

•oil, gas, and NGL reserve estimates and estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates, as well as the conversion of proved undeveloped reserves to proved developed reserves;

•our expected future production volumes, identified drilling locations, as well as drilling prospects, inventories, projects and programs;

•cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;

•business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, debt redemptions or equity repurchases, capital markets activities, environmental, social, and governance (“ESG”) goals and initiatives, and our outlook on our future financial condition or results of operations; and

•other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. We caution you that forward-looking statements are not guarantees of future performance and these statements are subject to known and unknown risks and uncertainties, which may cause our actual results or performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in Part I, Item 1A, Risk Factors below and elsewhere in this report.

The forward-looking statements in this report speak only as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.

Glossary

The oil and gas terms and other terms defined in this section are used throughout this report. The definitions of the terms “developed reserves,” “exploratory well,” “field,” “proved reserves,” and “undeveloped reserves” have been abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the Securities and Exchange Commission’s (“SEC”) website at www.sec.gov.

Ad valorem tax. A tax based on the value of real estate or personal property.

ASC. Accounting Standards Codification.

ASU. Accounting Standards Update.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs, water, or other liquid hydrocarbons.

BBtu. One billion British thermal units.

Bcf. One billion cubic feet, used in reference to gas.

BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas to one Bbl of oil or NGLs.

Btu. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Completion. The installation of equipment for production of oil, gas, and/or NGLs, or in the case of a dry hole, the reporting to the applicable authority that the well has been abandoned.

Conversion rate. Current year conversions of proved undeveloped reserves to proved developed reserves, divided by beginning of the year proved undeveloped reserves (also commonly referred to in our industry as “track record”).

Costs incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Developed reserves. Reserves 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.

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.

Dry hole. An exploratory, development, or extension well that proves to be incapable of producing oil, gas, and/or NGLs in sufficient commercial quantities to justify completion, or upon completion, the economic operation of a well (also referred to as “non-productive well”).

Exploratory well. 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.

FASB. Financial Accounting Standards Board.

Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and gas) rights.

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.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

GAAP. Accounting principles generally accepted in the United States.

Gross acres or gross wells. Acres or wells in which a working interest is owned.

Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.

LIBOR. London Interbank Offered Rate. Discontinued as a global reference rate for new loans and contracts after December 31, 2021.

Lease operating expenses. The expenses incurred in the lifting of oil, gas, and/or NGLs from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs.

MBbl. One thousand barrels, used in reference to oil, NGLs, water, or other liquid hydrocarbons.

MBOE. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet, used in reference to gas.

MMBbl. One million barrels, used in reference to oil, NGLs, water, or other liquid hydrocarbons.

MMBOE. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet, used in reference to gas.

Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.

NGLs. The combination of ethane, propane, isobutane, normal butane, and natural gasoline that when removed from gas become liquid under various levels of higher pressure and lower temperature.

NYMEX WTI. New York Mercantile Exchange West Texas Intermediate, a common industry benchmark price for oil.

NYMEX Henry Hub. New York Mercantile Exchange Henry Hub, a common industry benchmark price for gas.

OPEC+. The Organization of the Petroleum Exporting Countries Plus other non-OPEC oil producing countries.

OPIS. Oil Price Information Service, a common industry benchmark for NGL pricing at Mont Belvieu, Texas.

PV-10. PV-10 is a non-GAAP measure. The present value of estimated future revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period.

Productive well. An exploratory, development, or extension well that is producing or is capable of commercial production of oil, gas, and/or NGLs.

Proved reserves. Those quantities of oil, gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Recompletion. The completion of an existing wellbore in a formation other than that in which the well has previously been completed.

Reserve life index. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil, gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resource play. A term used to describe an accumulation of oil, gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has lower expected geological risk.

Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from oil, gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.

Royalty interest. An interest in an oil and gas property entitling the owner to shares of oil, gas, and NGL production free of costs of exploration, development, and production operations.

Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations.

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Standardized measure of discounted future net cash flows. The discounted future net cash flows related to estimated proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, at a 10 percent annual discount rate. The information for this calculation is included in Supplemental Oil and Gas Information (unaudited) located in Part II, Item 8 of this report.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and NGLs regardless of whether such acreage contains estimated net proved reserves.

Undeveloped reserves. Reserves 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. The applicable SEC definition of undeveloped reserves provides that undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs.

PART I

When we use the terms “SM Energy,” the “Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business in the Glossary section of this report. Throughout this document we make statements and projections that address future expectations, possibilities, or events, all of which may be classified as “forward-looking statements.” Please refer to the Cautionary Information about Forward-Looking Statements section of this report for an explanation of these types of statements and the associated risks and uncertainties.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the state of Texas. SM Energy was founded in 1908, incorporated in Delaware in 1915, and our initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.”

Our principal office is located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140.

Strategy

Our strategic objective is to be a premier operator of top-tier oil and gas assets. Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our short-term operational and financial goals include generating positive cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization. Our long-term vision is to sustainably grow value for all of our stakeholders. We believe that in order to accomplish this vision, we must be a premier operator of top-tier oil and gas assets. Our strategy for achieving these goals is to focus on high-quality economic drilling, completion, and production opportunities. Our investment portfolio is comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive impact in the communities where we live and work; and transparency in reporting our progress in these areas. We have prioritized ESG initiatives by, among other things, integrating enhanced environmental and social programs throughout the organization and setting near-term and medium-term goals that include reducing flaring and greenhouse gas (“GHG” or “GHGs”) emissions intensity, and maintaining low methane emissions intensity. Additionally, we are putting systems in place to track additional ESG metrics to enable increased reporting in the future and to increase employee awareness. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company’s ESG policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide performance-based metrics that include key financial, operational, and environmental, health, and safety measures.

Significant Developments in 2021

Cash Flows and Debt Reduction. For the year ended December 31, 2021, net cash provided by operating activities was $1.2 billion, which was in excess of net cash used in investing activities of $667.2 million, resulting in a six percent decrease in the principal balance of our total outstanding long-term debt to $2.1 billion as of December 31, 2021, from $2.3 billion as of December 31, 2020. The decrease in the principal balance of our total outstanding long-term debt was primarily driven by a $93.0 million decrease in the outstanding balance on our revolving credit facility, and the retirement of the remaining $65.5 million of our 2021 Senior Secured Convertible Notes. Additionally, as of December 31, 2021, we had a cash and cash equivalents balance of $332.7 million and no outstanding balance on our revolving credit facility. Please refer to Analysis of Cash Flow Changes Between 2021 and 2020 and Between 2020 and 2019 in Overview of Liquidity and Capital Resources in Part II, Item 7, and to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion, including the definition of 2021 Senior Secured Convertible Notes.

Production, Pricing, Revenue, and Commodity Derivatives. Our average net daily equivalent production in 2021 increased 11 percent compared with 2020 to 140.7 MBOE, consisting of 76.5 MBbl of oil, 296.9 MMcf of gas, and 14.7 MBbl of NGLs. This increase was primarily driven by a 19 percent increase from our Midland Basin assets and resulted from an increased number of completions, strong well performance, and our focus on operational execution. Oil production as a percentage of total production increased to 54 percent in 2021 from 50 percent in 2020. Realized prices before the effect of derivative settlements (“realized price” or “realized prices”) for oil, gas, and NGLs increased 83 percent, 169 percent, and 141 percent, respectively, for the year ended December 31,

2021, compared with 2020. As a result of increased realized prices, oil, gas, and NGL production revenue increased 131 percent to $2.6 billion for the year ended December 31, 2021, compared with $1.1 billion for 2020. Oil production revenue was 73 percent and 76 percent of total production revenue for the years ended December 31, 2021, and 2020, respectively. We recorded a net derivative loss of $901.7 million for the year ended December 31, 2021, compared to a net derivative gain of $161.6 million for 2020. These amounts include a derivative settlement loss of $749.0 million for the year ended December 31, 2021, and a derivative settlement gain of $351.3 million for the year ended December 31, 2020. Please refer to Areas of Operation below and Overview of the Company in Part II, Item 7 of this report for additional discussion.

Reserves and Capital Investment. Total estimated proved reserves were 492.0 MMBOE as of December 31, 2021, which was an increase of 22 percent from 404.6 MMBOE as of December 31, 2020. We added 139.1 MMBOE through extensions and infill as a result of continued success in and further development of our Austin Chalk and Midland Basin assets, partially offset by 51.4 MMBOE of production during 2021. Our proved reserve life index increased to 9.6 years as of December 31, 2021, compared with 8.7 years as of December 31, 2020. Please refer to Areas of Operation and Reserves below for additional discussion regarding additions from extensions, discoveries, and infill, the removal of certain proved undeveloped reserve cases that are no longer within our development plan over the next five years, and price and performance revisions. Costs incurred increased 23 percent from 2020 to $718.0 million in 2021. Please refer to Areas of Operation below, and to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

Outlook

Our vision to sustainably grow value for all of our stakeholders includes short-term operational and financial goals of generating cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization. Our long-term plan is to deliver cash flow growth that is supported by our high-quality asset base and ability to generate favorable returns.

Our total 2022 capital program, which we expect to fund with cash flows from operations, is expected to be approximately $750.0 million. We expect to focus our 2022 capital program on highly economic oil development projects in both our Midland Basin assets and our South Texas assets.

Areas of Operation

____________________________________________

(1)As of December 31, 2021.

Our 2021 operations were concentrated in the Midland Basin and South Texas, as described below. The following table summarizes estimated proved reserves, net production volumes, and costs incurred for the year ended December 31, 2021, for these areas:


	Midland Basin			South Texas			Total (1)
Proved reserves
Oil (MMBbl)	156.7			42.9			199.5
Gas (Bcf)	568.9			674.5			1,243.5
NGLs (MMBbl)	0.1			85.1			85.2
MMBOE (1)	251.6			240.4			492.0
Relative percentage	51		%	49		%	100		%
Proved developed %	66		%	56		%	61		%
Net production volumes
Oil (MMBbl)	25.2			2.7			27.9
Gas (Bcf)	55.4			52.9			108.4
NGLs (MMBbl)	—			5.4			5.4
MMBOE (1)	34.4			16.9			51.4
Avg. daily equivalents (MBOE/d) (1)	94.4			46.4			140.7
Relative percentage	67		%	33		%	100		%
Costs incurred (in millions) (2)	$	433.8		$	240.7		$	718.0

___________________________________________

(1)Amounts may not calculate due to rounding.

(2)Asset costs incurred do not sum to total costs incurred primarily due to corporate overhead charges incurred on exploration activities that are excluded from this table. Please refer to Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Total estimated proved reserves at December 31, 2021, increased 22 percent from December 31, 2020. Total net equivalent production increased 11 percent for the year ended December 31, 2021, compared with 2020. Costs incurred for the year ended December 31, 2021, increased 23 percent compared with 2020, primarily as a result of the increase in our capital activity, specifically an increase related to the development of our South Texas assets.

Midland Basin. Our Midland Basin assets, which are located in the Permian Basin in West Texas, are comprised of approximately 80,000 net acres, and include our RockStar assets in Howard and Martin Counties, Texas and our Sweetie Peck assets in Upton and Midland Counties, Texas (“Midland Basin”). In 2021, drilling and completion activities within our RockStar and Sweetie Peck positions continued to focus primarily on development optimization and further delineating our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations. We expect 2022 capital activity in the Midland Basin to be focused on highly economic oil development projects.

In 2021, costs incurred were $433.8 million and we averaged three drilling rigs and two completion crews. We completed 97 gross (81 net) wells, and as of December 31, 2021, 30 gross (27 net) wells had been drilled but not completed. Net equivalent production for the year ended December 31, 2021, was 34.4 MMBOE, an 18 percent increase from 29.1 MMBOE for the year ended December 31, 2020. Estimated proved reserves increased 13 percent to 251.6 MMBOE at December 31, 2021, from 222.0 MMBOE at December 31, 2020, as a result of additions of 46.6 MMBOE and positive price and performance revisions of 29.6 MMBOE partially offset by production of 34.4 MMBOE. Additionally, we removed 11.8 MMBOE of proved undeveloped reserves which were replaced by recognizing additions to proved undeveloped reserves associated with different locations that were added to our five-year development plan. Additions to proved reserves primarily resulted from extensions and infill reserves replacing converted proved undeveloped reserves.

South Texas. Our South Texas assets are comprised of approximately 155,000 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). In 2021, our operations in South Texas were focused on production from the Eagle Ford shale formation and Austin Chalk formation, and further development of the Austin Chalk formation. Our overlapping acreage position in the Maverick Basin covers a significant portion of the western Eagle Ford shale and Austin Chalk formations (“Maverick Basin”) and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction. We expect 2022 capital activity in South Texas to be focused primarily on developing the Austin Chalk formation.

In 2021, costs incurred were $240.7 million and we averaged one drilling rig and one completion crew. We completed 31 gross (28 net) wells, and as of December 31, 2021, 32 gross (32 net) wells had been drilled but not completed. Net equivalent production for the year ended December 31, 2021, was 16.9 MMBOE, a two percent decrease from 17.3 MMBOE for the year ended

December 31, 2020. Estimated proved reserves increased 32 percent to 240.4 MMBOE at December 31, 2021, from 182.6 MMBOE at December 31, 2020, as a result of additions of 92.5 MMBOE and positive price revisions of 29.0 MMBOE offset by production of 16.9 MMBOE and downward revisions of 46.8 MMBOE. Additions to proved reserves from extensions and infill were the result of continued success in our development of the Austin Chalk formation. Downward revisions consisted of 28.7 MMBOE of proved undeveloped reserves which were replaced by recognizing additions to proved undeveloped reserves associated with different locations that were added to our five-year development plan, and 18.1 MMBOE resulting from performance revisions.

Office Space. As of December 31, 2021, we leased and owned office space as summarized in the table below:


	Approximate Square Footage Leased	Approximate Square Footage Owned
Corporate (1)	164,000	—
Midland Basin	59,000	—
South Texas (2)	62,000	12,000
Total	285,000	12,000

__________________________________________

(1)We expect to reduce our Corporate leased office space to approximately 59,000 square feet in 2022.

(2)Subsequent to December 31, 2021, the square footage leased in South Texas was reduced to approximately 21,000 square feet.

Reserves

Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, we expect these estimates to change as new information becomes available. The following table presents the standardized measure of discounted future net cash flows and PV-10. PV-10 is a non-GAAP financial measure, and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither the standardized measure of discounted future net cash flows nor PV-10 represents the fair market value of our oil and gas properties. We and others in the oil and gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held without regard to the specific tax characteristics of such entities. Please refer to the Glossary section of this report for additional information regarding these measures and refer to the reconciliation of the standardized measure of discounted future net cash flows to PV-10 set forth below. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. The following table should be read along with the Risk Factors section below.

The following table summarizes estimated proved reserves, the standardized measure of discounted future net cash flows (GAAP), PV-10 (non-GAAP), the prices used in the calculation of proved reserves estimates, and reserve life index as of December 31, 2021, 2020, and 2019:


	As of December 31,
	2021			2020			2019
Reserve volumes:
Proved developed
Oil (MMBbl)	110.7			89.8			85.0
Gas (Bcf)	833.0			643.9			712.1
NGLs (MMBbl)	50.7			32.1			43.4
MMBOE (1)	300.2			229.3			247.0
Proved undeveloped
Oil (MMBbl)	88.8			82.9			99.1
Gas (Bcf)	410.4			408.1			511.1
NGLs (MMBbl)	34.5			24.4			30.6
MMBOE (1)	191.8			175.3			214.9
Total proved (1)
Oil (MMBbl)	199.5			172.7			184.1
Gas (Bcf)	1,243.5			1,052.0			1,223.2
NGLs (MMBbl)	85.2			56.6			74.0
MMBOE	492.0			404.6			462.0
Proved developed reserves percentage	61		%	57		%	53		%
Proved undeveloped reserves percentage	39		%	43		%	47		%

Reserve data (in millions):
Standardized measure of discounted future net cash flows (GAAP)	$	6,962.6		$	2,682.5		$	4,104.0
PV-10 (non-GAAP):
Proved developed PV-10	$	5,407.2		$	1,848.8		$	2,830.4
Proved undeveloped PV-10	2,751.4			833.7			1,532.4
Total proved PV-10 (non-GAAP)	$	8,158.6		$	2,682.5		$	4,362.8

12-month trailing average prices: (2)
Oil (per Bbl)	$	66.56		$	39.57		$	55.69
Gas (per MMBtu)	$	3.60		$	1.99		$	2.58
NGLs (per Bbl)	$	36.60		$	17.64		$	22.68

Reserve life index (years) (3)	9.6			8.7			9.6

____________________________________________

(1)Amounts may not calculate due to rounding.

(2)The prices used in the calculation of proved reserve estimates reflect the unweighted arithmetic average of the first-day-of-the-month price of each month within the trailing 12-month period in accordance with SEC rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves.

(3)Our ability to replace production with new oil and gas reserves is critical to the future success of our business. Please refer to the reserve life index term in the Glossary section of this report for information describing how this metric is calculated.

The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 (non-GAAP) of total estimated proved reserves. Please refer to the Glossary section of this report for the definitions of standardized measure of discounted future net cash flows and PV-10.


	As of December 31,
	2021		2020		2019
	(in millions)
Standardized measure of discounted future net cash flows (GAAP)	$	6,962.6	$	2,682.5	$	4,104.0
Add: 10 percent annual discount, net of income taxes	4,844.9		1,856.3		2,955.3
Add: future undiscounted income taxes	2,130.3		—		579.8
Pre-tax undiscounted future net cash flows	13,937.8		4,538.8		7,639.1
Less: 10 percent annual discount without tax effect	(5,779.2)		(1,856.3)		(3,276.3)
PV-10 (non-GAAP)	$	8,158.6	$	2,682.5	$	4,362.8

Proved Undeveloped Reserves

Proved undeveloped reserves include those reserves that are expected to be recovered from future wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of economic producibility when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2021, we did not have any proved undeveloped reserves that had been on our books in excess of five years, and none of our proved undeveloped reserves were on acreage expected to expire or on acreage that was not expected to be held through renewal before the targeted completion date.

For proved undeveloped locations that are more than one development spacing area from developed producing locations, we utilized reliable geologic and engineering technology when booking estimated proved undeveloped reserves. Of the 191.8 MMBOE of total proved undeveloped reserves as of December 31, 2021, approximately 29.0 MMBOE of proved undeveloped reserves in the Midland Basin and 68.7 MMBOE of proved undeveloped reserves in our South Texas position were offset by more than one development spacing area from the nearest developed producing location. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected) and petrophysical analysis of that log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results.

As of December 31, 2021, estimated proved undeveloped reserves increased 16.5 MMBOE, or nine percent compared with December 31, 2020. The following table provides a reconciliation of our proved undeveloped reserves for the year ended December 31, 2021:


			Total (MMBOE)
Total proved undeveloped reserves:
Beginning of year			175.3
Additions from extensions, discoveries, and infill			125.2
Conversions to proved developed			(66.0)
Removed for five-year rule			(40.6)
Revisions of previous estimates			(2.1)


End of year			191.8

Additions from extensions, discoveries, and infill. During 2021, we added 81.0 MMBOE and 44.2 MMBOE of estimated proved undeveloped reserves in South Texas and the Midland Basin, respectively. The majority of the additions in South Texas resulted from extensions from our continued success in, and further development of, the Austin Chalk formation, while the majority of the additions in the Midland Basin resulted from infill development.

Conversions to proved developed. Our 2021 conversion rate was 38 percent and was primarily the result of developing proved reserves in our Austin Chalk and Midland Basin assets. During 2021, we incurred $448.7 million on projects with reserves

booked as proved undeveloped at the end of 2020, of which $396.0 million was spent on converting proved undeveloped reserves to proved developed reserves by December 31, 2021. At December 31, 2021, drilled but not completed wells represented 32.3 MMBOE of total estimated proved undeveloped reserves. We expect to incur $124.5 million of capital expenditures in completing these drilled but not completed wells, and we expect all estimated proved undeveloped reserves to be converted to proved developed reserves within five years from their initial booking as proved undeveloped reserves.

Removed for five-year rule. As a result of our testing and delineation efforts in 2021, we revised certain aspects of our future development plan to focus on maximizing returns and the value of our assets. As a result, we removed 40.6 MMBOE of estimated proved undeveloped reserves and reclassified these locations to unproved reserve categories, of which 27.0 MMBOE related to our Eagle Ford shale proved undeveloped reserves and reflects our continued shift to further develop the Austin Chalk formation, and 11.8 MMBOE related to optimization in our future development plan for our Midland Basin program. The Eagle Ford shale future development locations were replaced by Austin Chalk locations which are reflected as additions from extensions, discoveries, and infill.

As of December 31, 2021, estimated future development costs relating to our proved undeveloped reserves totaled $1.4 billion, and we expect to incur approximately $481.8 million, $336.8 million, and $364.5 million in 2022, 2023, and 2024, respectively.

Internal Controls Over Proved Reserves Estimates

Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves is delegated to our corporate reserves group and is coordinated by our Corporate Engineering Manager, subject to the oversight of our management and the Audit Committee of our Board of Directors, as discussed below. Our Corporate Engineering Manager has worked in the energy industry since 2008 and has been employed by the Company since 2010. He holds a Bachelor of Science Degree in Petroleum Engineering from Montana Technological University and is a Registered Professional Petroleum Engineer in the states of Texas, Wyoming, and Montana. He is also a member of the Society of Petroleum Engineers. Technical, geological, and engineering reviews of our assets are performed throughout the year by our staff. Data obtained from these reviews, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. Our asset team’s engineering technical staff do not report directly to our Corporate Engineering Manager; they report to either their respective asset technical managers or directly to the Senior Vice President of Exploration, Development and EHS. This design is intended to promote objective and independent analysis within our asset teams in the proved reserves estimation process.

Third-party Reserves Audit

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over 80 years. Ryder Scott performed an independent audit using its own engineering assumptions, but with economic and ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10. In the aggregate, the proved reserve amounts of our audited properties determined by Ryder Scott are required, per our policy, to be within 10 percent of our proved reserve amounts for the total Company, as well as for each respective major asset. The technical engineer at Ryder Scott primarily responsible for overseeing our reserves audit was a Managing Senior Vice President who received a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003. He is a licensed Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers. The 2021 Ryder Scott audit report is included as Exhibit 99.1.

In addition to a third-party audit, our reserves are reviewed by our management with the Audit Committee of our Board of Directors. Our management, which includes our President and Chief Executive Officer, Executive Vice President and Chief Financial Officer, and Senior Vice President of Exploration, Development and EHS, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives, separate from our management, from time to time to discuss processes and findings.

Production

The following table summarizes our net production volumes and realized prices for oil, gas, and NGLs produced and sold during the periods presented. Realized prices presented below exclude the effects of derivative contract settlements. Also presented is a summary of related production expense on a per BOE basis.


	For the Years Ended December 31,
	2021		2020		2019
Net production volumes
Oil (MMBbl)	27.9		23.0		21.9
Gas (Bcf)	108.4		103.9		109.8
NGLs (MMBbl)	5.4		6.1		8.1
Equivalent (MMBOE) (1)	51.4		46.4		48.3
Midland Basin net production volumes (2)
Oil (MMBbl)	25.2		21.3		20.5
Gas (Bcf)	55.4		46.6		34.4
NGLs (MMBbl)	—		—		—
Equivalent (MMBOE) (1)	34.4		29.1		26.3
Maverick Basin net production volumes (2)
Oil (MMBbl)	2.7		1.7		1.3
Gas (Bcf)	52.8		57.2		75.4
NGLs (MMBbl)	5.4		6.1		8.1
Equivalent (MMBOE) (1)	16.9		17.3		21.9
Realized price
Oil (per Bbl)	$	67.72	$	37.08	$	54.10
Gas (per Mcf)	$	4.85	$	1.80	$	2.39
NGLs (per Bbl)	$	33.67	$	13.96	$	17.26
Per BOE	$	50.58	$	24.26	$	32.84
Production expense per BOE
Lease operating expense	$	4.39	$	3.97	$	4.67
Transportation costs	$	2.71	$	3.06	$	3.88
Production taxes	$	2.36	$	0.99	$	1.35
Ad valorem tax expense	$	0.38	$	0.41	$	0.48

____________________________________________

(1)Amounts may not calculate due to rounding.

(2)For each of the years ended December 31, 2021, 2020, and 2019, total estimated proved reserves attributed to our Midland Basin field and our Maverick Basin field exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis.

Productive Wells

As of December 31, 2021, we had working interests in 825 gross (743 net) productive oil wells and 483 gross (449 net) productive gas wells. Productive wells may be temporarily shut-in. Multiple completions in the same wellbore are counted as one well, and as of December 31, 2021, two of these wells had multiple completions. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil when it first commenced production, but such designation may not be indicative of current or future production composition.

Drilling and Completion Activity

All of our drilling and completion activities are conducted by independent contractors using equipment they own and operate. The following table summarizes the number of operated and outside-operated wells drilled and completed or recompleted on our properties in 2021, 2020, and 2019, excluding non-consented projects, active injector wells, saltwater disposal wells, or wells in which we own only a royalty interest:


	For the Years Ended December 31,
	2021		2020		2019
	Gross	Net	Gross	Net	Gross	Net
Development wells
Oil	107	91	78	71	119	107
Gas	11	8	—	—	27	16
Non-productive	—	—	—	—	1	1
	118	99	78	71	147	124
Exploratory wells
Oil	2	2	5	5	4	4
Gas	8	8	1	1	4	4
Non-productive	—	—	—	—	1	1
	10	10	6	6	9	9
Total	128	109	84	77	156	133

____________________________________________

Note: The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated.

In addition to the wells drilled and completed in 2021 (included in the table above), we were actively participating in the drilling of seven gross (seven net) wells and had 63 gross (59 net) drilled but not completed wells as of January 31, 2022. Drilled but not completed wells as of January 31, 2022, represent wells that were being completed or were waiting on completion. The drilled but not completed well count as of January 31, 2022, includes 11 gross (11 net) wells that are not included in our five-year development plan, 10 of which are in the Eagle Ford shale.

Title to Properties

As of December 31, 2021, over 98 percent of our operated oil and gas producing assets are located on private lands, are held pursuant to oil and gas leases from private mineral owners, and are not located on federal lands or leased from the federal government. The remainder of our operated oil and gas producing assets are located on Texas state lands. We have obtained title opinions or have conducted other title review on substantially all of our producing properties and believe we have satisfactory title to such properties. We obtain new or updated title opinions prior to commencing initial drilling operations on the properties that we operate. Most of our producing properties are subject to mortgages securing indebtedness under our Credit Agreement and Senior Secured Notes, as defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report, royalty and overriding royalty interests, liens for current taxes, and other ordinary course burdens that we believe do not materially interfere with the development of such properties. We typically perform title investigations in accordance with standards generally accepted in the oil and gas industry before acquiring developed and undeveloped leasehold acreage.

Acreage

The following table sets forth the number of gross and net surface acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes that we held as of December 31, 2021.


	Developed Acres (1)		Undeveloped Acres (2)(3)		Total
	Gross	Net	Gross	Net	Gross	Net
Midland Basin:
RockStar	67,528	61,510	2,802	2,019	70,330	63,529
Sweetie Peck	19,308	16,125	2,242	340	21,550	16,465
Midland Basin Total (4)	86,836	77,635	5,044	2,359	91,880	79,994
South Texas	80,101	79,708	78,340	75,355	158,441	155,063
Other (5)	16,259	11,363	89,691	25,306	105,950	36,669
Total	183,196	168,706	173,075	103,020	356,271	271,726

____________________________________________

(1)Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations but has been included only as developed acreage in the table above.

(2)Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.

(3)As of February 10, 2022, none of our undeveloped acreage is scheduled to expire by December 31, 2022, and 82 and 564 net acres of undeveloped acreage are scheduled to expire by December 31, 2023, and 2024, respectively, unless production is established or we take other action to extend the terms of the applicable leases. Certain of our acreage, primarily in South Texas, is subject to lease consolidation agreements containing drilling, completion, and other obligations that we currently intend to satisfy. Failure to meet these obligations results in payments to lessors, or termination of the lease consolidation agreements, which could result in additional future lease expirations if continuous development obligations required by individual leases are not met.

(4)As of December 31, 2021, total Midland Basin acreage excludes approximately 1,523 net acres associated with drill-to-earn opportunities that we intend to pursue.

(5)Includes other non-core acreage located in Colorado, Louisiana, Montana, North Dakota, Texas, Utah, and Wyoming.

Delivery Commitments

For gathering, processing, transportation throughput, and delivery commitments, please refer to Pipeline Transportation Commitments within Note 6 – Commitments and Contingencies in Part II, Item 8 of this report.

Major Customers

For major customers and entities under common control that accounted for 10 percent or more of our total oil, gas, and NGL production revenue for at least one of the years ended December 31, 2021, 2020, and 2019, please refer to Concentration of Credit Risk and Major Customers within Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report.

Human Capital

Our Company culture, which seeks to recognize our employees as our most valuable asset, drives the manner in which we pursue our short-term and long-term goals, as well as our efforts to attract and retain talent. Through our culture, we work to promote:

•integrity and ethical behavior in the conduct of our business;

•environmental, health, and safety priorities;

•prioritizing the success of others and the team;

•understanding and communicating why we do what we do and how every employee contributes to achieving success;

•collaboration and openness to new ideas and technologies that serve business improvement;

•support for team members’ professional and personal development; and

•support for the communities where we live and work.

The core values of integrity and ethical behavior are the pillars of our culture, and as a result, the health and safety of our employees and contractors is our highest priority. All employees are responsible for upholding Company-wide standards and values. We have many long-standing policies designed to promote ethical conduct and integrity, that employees are required to read and

acknowledge on an annual basis. Employees are consistently provided training opportunities to develop skills in leadership, safety, and technical acumen, which help strengthen our efforts in conducting business with high ethical standards.

We strive to provide competitive, performance-based compensation and benefits to our employees, including market-competitive pay, short-term and long-term incentive compensation plans, an employee stock purchase program, and various healthcare, retirement, and other benefit packages such as a hybrid work environment that is guided by each employee’s job function and responsibilities. Compensation for our executives and employees under our short-term and long-term incentive plans is determined based on individual performance and Company performance with respect to qualitative and quantitative metrics that include environmental, health, and safety measures. The Compensation Committee of our Board of Directors oversees our compensation programs and regularly modifies program design to incentivize achievement of our corporate strategy and the matters of importance to our stakeholders. Significant planning for succession of key personnel is performed each year, or more frequently as deemed necessary by management.

We believe that our relationship with our employees is strong. As of February 10, 2022, we had 506 full-time employees, none of whom were subject to a collective bargaining agreement. We are committed to diversity at all levels of our organization and we strive to provide equal employment opportunities to all employees and job applicants. On an annual basis, we retain a third party to analyze our workforce demographics and conduct discrimination and pay equity testing. No discriminatory practices have been identified and no evidence of discrimination or pay inequity has been found. Additionally, we have established procedures and controls designed to support our objective of remaining, at all times, in material compliance with federal, state, and local laws and governmental regulations.

The following charts present certain Board of Directors and workforce metrics as of December 31, 2021:


			Board of Directors Diversity (1)			Officer Gender Diversity (2)


			Employee Ethnic Diversity (1)			Employee Gender Diversity

____________________________________________

(1)Ethnic diversity data is determined under guidelines set forth by the United States Equal Employment Opportunity Commission and includes employees in the following categories: American Indian or Alaska Native, Asian, Black or African American, Hispanic or Latino, or the combination of two or more races (not Hispanic or Latino).

(2)Includes officers at the level of Vice President and above.

Seasonality

The price of crude oil is primarily driven by global socioeconomic factors and is less affected by seasonal fluctuations; however, demand for energy is generally higher in the winter and in the summer driving season. The demand and price for gas frequently increases during winter months and decreases during summer months. To lessen the impact of seasonal gas demand and

price fluctuations, pipelines, utilities, local distribution companies, and industrial users regularly utilize gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can divert gas that is traditionally placed into storage which, in turn, may increase the typical winter seasonal price. Seasonal anomalies, such as mild winters, or other unexpected impacts, such as the Pandemic, sometimes lessen or exacerbate these fluctuations.

Certain of our drilling, completion, and other operations are also subject to seasonal limitations. Seasonal weather conditions, government regulations, and lease stipulations could adversely affect our ability to conduct drilling activities in some of the areas where we operate. Please refer to Risk Factors in Part I, Item 1A of this report for additional discussion.

Competition

The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and gas properties. We believe our acreage positions provide a foundation for development activities that we expect to fuel our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our core operating areas. However, we face intense competition from many major and independent oil and gas companies, which in some cases have larger technical teams and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and gas reserves, but also have gathering, processing or refining operations, market refined products, provide, dispose of and transport fresh and produced water, own drilling rigs or production equipment, or generate electricity, all of which, individually or in the aggregate, could provide such companies with a competitive advantage.

We also compete with other oil and gas companies in securing drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells, as well as for the gathering, transporting, and processing of oil, gas, NGLs, and water. Consequently, we may face shortages, delays, or increased costs in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including renewable energy sources such as solar and wind-generated energy, and other fossil fuels such as coal. Competitive conditions may be affected by future energy, environmental, climate-related, financial, or other policies, legislation, and regulations.

In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to the evolving demographics of our industry. We are not insulated from competition for quality people, and we must compete effectively to be successful. Please refer to Human Capital above and Risk Factors in Part I, Item 1A of this report for additional discussion.

Government Regulations

Although our regulatory compliance obligations are mitigated by the fact that we do not own or operate oil and gas properties on federal lands, nearly every aspect of our business is subject to expansive federal, state, and local laws and governmental regulations. These laws and regulations frequently change in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential to increase our cost of conducting business and consequently could affect our profitability.

Energy Regulations

Texas, the state where we conduct operations and lease or own nearly all of our oil and gas assets, has adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells, imposing bond requirements in order to drill or operate wells, governing the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to Texas conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, Texas conservation laws establish maximum rates of production from oil and gas wells, generally limit or prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of gas in interstate commerce. FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for gas production.

Environmental, Health, and Safety Matters

General. Our operations are subject to stringent and complex federal, state, and local laws and regulations governing protection of the environment and worker health and safety, as well as the discharge of materials and emissions into the environment. These laws and regulations may, among other things:

•require the acquisition of various permits before drilling commences;

•restrict the types, quantities, and concentration of various substances and emissions that may be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;

•limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and

•require remedial measures to mitigate pollution from former and ongoing operations, such as closing pits and plugging abandoned wells.

These laws, rules, and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of conducting business and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes may result in more stringent, or different permitting, waste handling, disposal, and cleanup requirements for the oil and gas industry and could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules, and regulations to which our business is subject.

Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated with the exploration, development, and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release or threatened release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of, or transported, a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of environmental investigation and certain health studies. In addition, it is not uncommon for third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and gas exploration and production for many years. CERCLA excludes petroleum and natural gas from its definition of hazardous substances, and although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances or wastes may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third-parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties, and the substances disposed or released on them, may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, pay fines, remediate contaminated property, or perform remedial operations to prevent future contamination.

Water discharges. The federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or analogous state agencies. This includes the discharge of certain storm water without a permit which requires periodic monitoring and sampling. In addition, the Clean Water Act regulates wastewater generated by unconventional oil and gas operations during the hydraulic fracturing process and discharged to publicly-owned wastewater treatment facilities. The Clean Water Act also prohibits discharge of dredged or fill material into waters of the United States, including wetlands, except in accordance with the terms of a permit issued by the United States Army Corps of Engineers, or a state, if the state has assumed authority to issue such permits. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages, and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability.

Air emissions. The federal Clean Air Act (“CAA”) and comparable state laws and regulations regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements, such as requirements for emission reduction, capture and control. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of hazardous air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. Please refer to the Environmental section in Part II, Item 7 of this report for additional information about the regulation of air emissions from the oil and gas sector.

Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other GHGs endanger public health and welfare, and as a result, began adopting and implementing a comprehensive suite of regulations to restrict emissions of GHGs under existing provisions of the CAA. While President Trump’s administration had taken steps to rescind or review many of these regulations, President Biden’s administration has actively been reviewing those actions and taking steps to strengthen and expand the regulations, specifically targeting, among other things, the regulation of methane emissions from the oil and gas sector. Legislative and regulatory initiatives related to climate change could have an adverse effect on our operations and the demand for oil and gas. Please refer to Risk Factors - Risks Related to Oil and Gas Operations and the Industry - Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs in Part I, Item 1A of this report. In addition to the effects of regulation, the meteorological and physical effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms, flooding, and wildfires, and could adversely affect the demand for our products.

Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts on protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on these species. It is also possible that a federal or state agency could order a complete halt to activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling, completion, and production activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.

OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe we are in substantial compliance with the applicable requirements of OSHA and comparable laws.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice used to stimulate production of hydrocarbons from tight shale formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, even on private lands, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation’s public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-ground formations that may adversely affect drinking water sources.

Increased regulation and scrutiny on oil and gas activities involving hydraulic fracturing techniques could potentially lead to a decrease in the completion of new oil and gas wells, an increase in compliance costs, delays, and changes in federal income tax laws, all of which could adversely affect our financial position, results of operations, and cash flows. As new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local levels, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements, which could result in additional permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that we are ultimately able to produce from our reserves.

We believe the trend in local, state, and federal environmental legislation and regulation will continue toward stricter standards, particularly under President Biden’s administration. While we believe we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a

material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected in the future.

Environmental, Health, and Safety Initiatives. We are committed to exceptional safety, health, and environmental stewardship; making a positive difference in the communities where we live and work; and transparency in reporting our progress in these areas. We set annual goals for our safety, health, and environmental program focused on reducing the number of safety related incidents and the number and impact of spills of produced fluids. In addition, we set annual goals for GHG emissions intensity and methane emissions as a percentage of total methane produced, and as part of our current ESG initiatives, we have set near-term and medium-term goals that include reducing flaring and GHG emissions intensity, and maintaining low methane emissions intensity. We also periodically conduct audits of our operations to ensure regulatory compliance and we strive to provide appropriate training for our employees. Reducing air emissions as a result of leaks, venting, or flaring of gas during operations has become a major focus area as we consider this a best practice and seek to comply with regulations. While flaring is sometimes necessary, reducing these volumes is a priority for us. To avoid flaring when possible, we restrict testing periods and connect our production to gas pipeline infrastructure as quickly as possible after well completions. We have incurred in the past, and expect to incur in the future, capital costs related to environmental compliance. Such expenditures are included within our overall capital budget and are not separately itemized.

Available Information

Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC, and can also be located at www.sec.gov. We also make available through our website our Corporate Governance Guidelines, Code of Business Conduct and Conflict of Interest Policy, Financial Code of Ethics, and the Charters of the Audit, Compensation, Executive, and Environmental, Social and Governance committees of our Board of Directors. Information on our website is not incorporated by reference into this report and should not be considered part of this document.

ITEM 1A. RISK FACTORS

In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in us.

Risks Related to Commodity Prices and Global Macroeconomics

Oil, gas, and NGL prices are volatile, and declines in prices may adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow.

Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and gas properties depend heavily on the prices we receive for oil, gas, and NGL sales. Oil, gas, and NGL prices also affect our cash flows available for capital expenditures, debt reductions, and other expenditures, our borrowing capacity, and the volume and value of our oil, gas, and NGL reserves. In addition, we may have oil and gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly. Please refer to Significant Developments in 2021 and Reserves in Part I, Items 1 and 2, Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019 in Part II, Item 7, and Note 1 – Summary of Significant Accounting Policies, Note 8 – Fair Value Measurements, and Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 for specific discussion.

Historically, the markets for oil, gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in oil, gas, and NGL prices often result from relatively minor changes in the supply of and demand for oil, gas, and NGLs, market uncertainty, and other factors that are beyond our control, including:

•global and domestic supplies of oil, gas, and NGLs, and the productive capacity of the industry as a whole;

•the level of consumer demand for oil, gas, and NGLs;

•overall global and domestic economic conditions;

•weather conditions;

•the availability and capacity of gathering, transportation, processing, and/or refining facilities in asset-specific or localized areas;

•liquefied natural gas deliveries to and from the United States;

•the price and availability of alternative fuels or sources of energy;

•technological advances in, and regulations affecting, energy consumption and conservation;

•the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to maintain effective oil price and production controls;

•political instability or armed conflict in oil or gas producing regions, such as the escalating tensions currently occurring between Russia and Ukraine;

•actual or perceived epidemic or pandemic risks;

•strengthening and weakening of the United States dollar relative to other currencies;

•inflation;

•stockholder activism or activities by non-governmental organizations to limit sources of funding or restrict the exploration and production of oil, gas, and NGLs and related infrastructure; and

•governmental regulations and taxes.

Declines in oil, gas, and NGL prices would reduce our revenues and could also reduce the amount of oil, gas, and NGLs that we can produce economically, which could have a material adverse effect on our business, financial condition, liquidity, results of operations, and prospects.

The global COVID-19 Pandemic has impacted, and will likely continue to impact, us and our industry and could have a material adverse effect on our business, financial condition, liquidity, results of operations and prospects.

Since the beginning of 2020, the Pandemic has spread across the globe and disrupted markets and economies around the world, including the oil, gas, and NGL industry in which we operate. Approximately two years after its onset, the Pandemic remains a global health crisis and continues to evolve, and as a result, the markets for the commodities produced by our industry remain subject to heightened levels of uncertainty. Volatile market conditions are likely to persist and could impact our business, financial condition, liquidity, results of operations, prospects, or the timing of further recovery. Although demand for the commodities produced by our industry has increased, further negative financial markets and industry-specific impacts could result from future case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, and as a result, may require us to adjust our business plan. In addition to the risks directly related to the Pandemic that are discussed throughout this report, the Pandemic is likely to increase the likelihood and magnitude of the other risk factors described in this section.

Weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.

Historically, the United States and global economies and financial systems have experienced turmoil and upheaval characterized by extreme volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, inflation, and an unprecedented level of intervention by the United States federal government and other governments. Weakness or uncertainty in the United States economy or other large economies could materially adversely affect our business and financial condition. For example:

• the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

•the liquidity available under our Credit Agreement could be reduced if any lender is unable to fund its commitment;

• our ability, or the ability of our suppliers or contractors, to access the capital markets may be restricted or non-existent at a time when we or they would like, or need, to raise capital for our or their business, including for the exploration and/or development of reserves;

• our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection;

•in an inflationary environment, we could be impacted by increased borrowing costs as a result of rising interest rates; and

•variable interest rate spread levels, including for LIBOR (or any applicable replacement rate) and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our Credit Agreement.

Risks Related to Oil and Gas Operations and the Industry

If we are unable to replace reserves, we will not be able to sustain production.

Our future operations depend on our ability to find or acquire and develop oil, gas, and NGL reserves that are economically producible. Our properties produce oil, gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate or acquire and develop new oil, gas, and NGL reserves to replace those being depleted by production.

For future acquisitions we may complete, a successful outcome for our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price and transaction costs for the acquisition, future oil, gas, and NGL prices, the ability to reasonably estimate the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation, and development activities on the

acquired properties, and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating these variables with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. Our customary review in connection with acquisitions will not necessarily reveal, or allow us to fully assess, all existing or potential problems and deficiencies with such properties. We do not inspect every well, and even when we inspect a well, we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. We often acquire interests in properties on an “as-is” basis with limited remedies for breaches of representations and warranties.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Integrating acquired businesses and properties involves a number of unique risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems, and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.

Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.

We face intense competition from oil and gas exploration and production companies of all sizes for the capital, equipment, expertise, labor, and materials required to operate oil and gas properties. Many of our competitors have financial, technical, and other resources exceeding those available to us, and many oil and gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for exploratory and development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for properties. As a result, we may not be successful in acquiring and developing profitable properties. In addition, other companies may have a greater ability to continue drilling activities during periods of low oil or gas prices and to absorb the burden of current and future governmental regulations and taxation. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. Our inability to compete effectively with companies in any area of our business could have a material adverse impact on our business activities, financial condition, and results of operations.

The loss of personnel could adversely affect our business.

We depend to a large extent on the efforts and continued employment of our executive management team, other key personnel, and our general labor force. The loss of their services could adversely affect our business. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen, and other professionals. Competition for many of these professionals can be intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.

The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated, and the cost to develop our reserves may be more than we have estimated.

This report and certain of our other SEC filings contain estimates of our proved oil, gas, and NGL reserves and the present value of estimated future net revenues from those reserves. The process of estimating reserves is complex and estimates are based on various assumptions, including geological and geophysical characteristics, future oil, gas, and NGL prices, drilling and completion costs, gathering and transportation costs, operating expenses, capital expenditures, effects of governmental regulation, taxes, timing of operations, and availability of funds. Therefore, these estimates are inherently imprecise. In addition, our reserve estimates for properties with limited production history may be less reliable than estimates for properties with lengthy production histories.

Actual future production; prices for oil, gas, and NGLs; revenues; production taxes; development expenditures; operating expenses; and quantities of producible oil, gas, and NGL reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities of and present value related to proved reserves disclosed by us, and the actual quantities and present value may be significantly less than what we have previously estimated. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties, which we may not control.

As of December 31, 2021, 39 percent, or 191.8 MMBOE, of our estimated proved reserves were proved undeveloped. In order to develop our proved undeveloped reserves, as of December 31, 2021, we estimate approximately $1.4 billion of capital expenditures would be required. Although we have estimated our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated.

One should not assume that the standardized measure of discounted future net cash flows or PV-10 included in this report represent the current market value of our estimated proved oil, gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. Please refer to Reserves in Part I, Items 1 and 2 of this report for discussion regarding the prices used in estimating the present value of our proved reserves as of December 31, 2021, and to the caption Oil and Gas Reserve Quantities under Critical Accounting Policies and Estimates in Part II, Item 7 of this report for additional information.

The timing of production from oil and gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10. In addition, the 10 percent discount factor required by the SEC to calculate PV-10 for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and gas industry in general are subject.

Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.

We regularly sell non-core assets in order to increase capital resources available for core assets and other purposes and to create organizational and operational efficiencies. We also occasionally sell interests in core assets for the purpose of accelerating the development and increasing efficiencies in other core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties, the availability of purchaser financing and purchasers willing to acquire the assets on terms we deem acceptable, or other matters or uncertainties that could impact such dispositions, including whether transactions could be consummated or completed in the form or timing and for the value that we anticipate. At times we may be required to retain certain liabilities or agree to indemnify buyers in connection with such asset sales. The magnitude of such retained liabilities or of the indemnification obligations may be difficult to quantify at the time of the transaction and ultimately could be material.

We rely on third-party service providers to conduct drilling and completion and other related operations.

We rely on third-party service providers to perform necessary drilling and completion and other related operations. The ability of third-party service providers to perform such operations will depend on those service providers’ ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, gas, and NGLs, prevailing economic conditions, and financial, business, and other factors. In addition, sustained low commodity prices could cause third-party service providers to consolidate or declare bankruptcy, which could limit our options for engaging such providers. The failure of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations.

Title to the properties in which we have an interest may be impaired by title defects.

We generally rely on title due diligence reports when acquiring oil and gas leasehold interests, and we obtain title opinions prior to commencing initial drilling operations on the properties we operate. Title to the properties in which we have an interest may be impaired by title defects that may not be identified in the due diligence title reports or title opinions we obtain, or such defects may not be cured following identification. A material title defect can reduce the value of a property or render it worthless, thus adversely affecting our oil and gas reserves, financial condition, results of operations, and operating cash flow, and may also impair the value of or render adjacent properties uneconomic to develop. Undeveloped acreage has greater risk of title defects than developed acreage and title insurance is not generally available for oil and gas properties.

Oil and gas drilling, completion, and production activities are subject to numerous risks, including the risk that no commercially producible oil, gas, or NGLs will be found.

The cost of drilling and completing wells is often uncertain, and oil, gas, or NGLs drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors may include, but are not limited to:

•unexpected adverse drilling or completion conditions;

•title problems;

•disputes with owners or holders of surface interests on or near areas where we operate;

•pressure or geologic irregularities in formations;

•engineering and construction delays;

•equipment failures or accidents;

•hurricanes, tornadoes, flooding, or other adverse weather conditions;

•operational restrictions resulting from seismicity concerns;

•governmental permitting delays;

•supply chain issues, including cost increases and availability of equipment or materials;

•compliance with environmental and other governmental requirements; and

•shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.

The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if oil, gas, or NGLs are present, or whether they can be produced economically. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover drilling and completion costs. Even if sufficient amounts of oil, gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing a well, which could result in reduced or no production from the well, significant expenditure to repair the well, and/or the loss and abandonment of the well.

Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore or develop our properties.

Results in newer resource plays may be more uncertain than results in resource plays that are more developed and have longer established production histories. We, and the industry, generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in newer resource plays than other areas with longer histories of development and production. Drilling and completion techniques that have proven to be successful in other resource plays are being used in the early development of new plays; however, we can provide no assurance of the ultimate success of these drilling and completion techniques.

We may not be able to obtain any options or lease rights in potential drilling locations that we identify. Unless production is established within the spacing units covering undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire and we will lose our right to develop the related properties. Our total net acreage as of February 10, 2022, that is scheduled to expire over the next three years, represents less than one percent of our total net undeveloped acreage as of December 31, 2021. Although we have identified numerous potential drilling locations, we may not be able to economically drill for and produce oil, gas, or NGLs from all of them, and our actual drilling activities may materially differ from those presently identified, which could adversely affect our financial condition, results of operations and operating cash flow.

The results of our operations are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

Many of our operations involve utilizing the latest drilling and completion techniques as developed by us, other operators and our service providers in order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks we face while drilling include, but are not limited to, landing our well bore outside the desired drilling zone, deviating from the desired drilling zone while drilling horizontally through the formation, the inability to run our casing the entire length of the well bore, and the inability to run tools and recover equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, the inability to fracture stimulate the planned number of stages, the inability to run tools and other equipment the entire length of the well bore during completion operations, the inability to recover such tools and other equipment, and the inability to successfully clean out the well bore after completion of the final fracture stimulation.

In addition, exploration and drilling technologies we currently use or implement in the future may become obsolete. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected. We cannot be certain we will be able to implement exploration and drilling technologies on a timely basis or at a cost that is acceptable to us.

Ultimately, the success of exploration, drilling, and completion technologies and techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for oil, gas, and NGLs decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future.

Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which

could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, result in increased lease operating expenses and adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil, gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various economic and other market conditions, including declines in oil, gas, and NGL prices. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices of commodities we sell. We do not believe the loss of any single purchaser would materially impact our operating results, as we have numerous options for purchasers in each of our operating areas for our oil, gas, and NGL production. Please refer to Concentration of Credit Risk and Major Customers in Note 1 – Summary of Significant Accounting Policies, in Part II, Item 8 of this report for further discussion of our concentration of credit risk and major customers. Additionally, the inability of our co-owners to pay joint interest billings could negatively impact our cash flows and financial ability to drill and complete current and future wells.

We have entered into firm transportation contracts that require us to pay fixed sums of money to our counterparties regardless of quantities actually shipped, processed, or gathered. If we are unable to deliver the necessary quantities of oil, gas, NGL, or produced water to our counterparties, our results of operations, financial position, and liquidity could be adversely affected.

As of December 31, 2021, we were contractually committed to deliver a minimum of 10 MMBbl of oil and 89 Bcf of gas through 2024, and 14 MMBbl of produced water through 2027. We may enter into additional firm transportation agreements as we expand the development of our resource plays. We do not expect to incur any material shortfalls related to our existing contractual commitments. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions of operations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, or if we further limit our capital expenditures due to future commodity price declines or for other reasons, the requirements to pay for quantities not delivered could have a material impact on our results of operations, financial position, and liquidity.

Negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole could adversely affect our business, operations, and our ability to attract capital.

Certain segments of the public as a whole, and the investment community in particular, have developed negative sentiment towards our industry. In recent years, equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment management firms, sovereign wealth and pension funds, university endowments and other investment advisors, have adopted policies to discontinue or reduce their investments in the oil and gas sector based on social and environmental considerations. Furthermore, other influential stakeholders have pressured commercial and investment banks and other service providers to reduce or cease financing of oil and gas companies and related infrastructure projects.

Such developments, including increased focus on environmental, social and governance matters and initiatives aimed at limiting climate change and reducing air pollution, and changes in federal income tax laws could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.

We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not be fully insured.

Oil and gas operations are subject to many risks, including human error and accidents, that could cause personal injury, death, property damage, well blowouts, craterings, explosions, uncontrollable flows of oil, gas and NGLs, or well fluids, releases or spills of completion fluids, spills or releases from facilities and equipment used to deliver or store these materials, spills or releases of brine or other produced or flowback water, subsurface conditions that prevent us from stimulating the planned number of completion stages, accessing the entirety of the wellbore with our tools during completion, or removing materials from the wellbore to allow production to begin, fires, adverse weather such as hurricanes or tornadoes, freezing conditions, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, pollution, seismic events, releases of toxic gas such as hydrogen sulfide, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses.

In response to increased seismic activity in the Permian Basin in Texas, the Railroad Commission of Texas (“RRC”) has developed a seismic review process for injection wells near qualifying seismic activity. As a result of the seismic review process, the RRC may declare an area to be a Seismic Response Area (“SRA”) and may adjust limits for injection rates and pressure, require bottom-hole pressure tests, or modify, suspend, or terminate injection well permits within the SRA. If a SRA is declared within an area

of our operations, our ability to dispose of produced water may be adversely affected, and as a result, we may be forced to shut-in injection wells or find alternate produced water disposal options which could affect production and therefore oil, gas, and NGL production revenue, and could cause us to incur additional capital or operating expense. The declaration of SRAs has required us to adjust the areas where we seek permits for injection wells to areas or formations that are less desirable, and could further restrict the areas where we are able to obtain and operate under such permits without restrictions. Additionally, we could be subject to third-party claims and liability based on allegations that our operations caused or contributed to seismic events that resulted in damage to property or personal injury, or that are otherwise related to seismic events.

If we experience any of the problems with well stimulation, completion activities, and disposal referenced above, our ability to explore for and produce oil, gas, and NGLs may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations as a result of the need to shut down, abandon, or relocate drilling operations, the need to modify drill sites to lessen the risk of spills or releases, the need to investigate and/or remediate any spills, releases or ground water contamination that might have occurred, and the need to suspend our operations.

There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling, and disposal of materials, including produced water, solid and hazardous wastes, and petroleum hydrocarbons. We may incur joint and several, and/or strict liability under applicable United States federal and state environmental laws in connection with releases of hazardous substances at, on, under, or from our leased or owned properties, some of which have been used for oil and gas exploration and production activities for a number of years, often by third-parties not under our control. For our outside-operated properties, we are dependent on the operator for operational and regulatory compliance and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or therefrom could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including CERCLA or the Superfund law, RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under various implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury or property damage, including induced seismicity damage, allegedly caused by the release of petroleum hydrocarbons or other hazardous substances into the environment. As a result, we may incur substantial liabilities to third-parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses.

We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by environmental damage that occurs gradually over time is appropriate for us at this time given the nature of our operations and the nature and cost of such coverage. Further, we may elect not to obtain insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer an uninsured material loss.

Our operations are subject to complex laws and regulations, including environmental regulations, that result in substantial costs and other risks.

Federal, state, and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing, or marketing of oil, gas, and NGL production. Non-compliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to increased operational and compliance costs, substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability.

Governmental authorities regulate various aspects of drilling for and the production of oil, gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in oil and gas properties, rights-of-way and easements, disposal of produced water, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, restoration standards, and oil and gas operations. Public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Any such delay, suspension, or termination could have a materially adverse effect on our operations.

Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, including the designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate in, could result in material costs or claims with respect to properties we own or have

owned or limitations on exploration and production activities in certain locations. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several, strict liability under federal, state, and local environmental laws for emissions and for discharges of oil, gas, and NGLs or other pollutants into the air, soil, surface water, or groundwater as described in Government Regulations in Part I, Items 1 and 2 of this report. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on us.

The impact of extreme weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Our operations have been in the past, and may continue to be, adversely affected by the impact of extreme weather conditions. Additionally, lease stipulations designed to protect various wildlife or plant species may adversely impact our operations. In certain areas, drilling and other oil and gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs and completion equipment, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is a common practice in the oil and gas industry used to stimulate the production of oil, gas, and NGLs from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and gas properties, including our unconventional resource plays within our Midland Basin and South Texas assets. Hydraulic fracturing involves injecting water, sand, and certain chemicals under pressure to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and gas commissions. However, the EPA and other federal agencies have asserted federal regulatory authority over certain aspects of hydraulic fracturing activities, as outlined below.

The EPA has authority to regulate underground injections that contain diesel in the fluid system under the Safe Drinking Water Act. The EPA also has authority under the Clean Water Act to regulate wastewater generated by unconventional oil and gas operations during the hydraulic fracturing process and discharged to publicly-owned wastewater treatment facilities. If the EPA implements further regulations of hydraulic fracturing, 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 could even be prohibited from drilling and/or completing certain wells.

Certain states, including Texas, 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 drilling in general and/or hydraulic fracturing in particular. Recently, municipalities have passed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturing within city boundaries, setting the stage for challenges by state regulators and third-parties. Similar events and processes are playing out in several cities, counties, and townships across the United States. In the event that 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 could even be prohibited from drilling and/or completing certain wells.

In the recent past, several federal governmental agencies were actively involved in studies or reviews that focus on environmental aspects and impacts of hydraulic fracturing practices. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing such activities to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. In 2013, a court in California, and in 2020 the United States District Court for the District of Montana each held that the Bureau of Land Management (“BLM”) did not comply with NEPA because it did not adequately consider the impact of hydraulic fracturing and horizontal drilling before issuing leases. Similar cases continue to be filed. Courts in New York and Colorado reduced the level of evidence required before a court will agree to consider alleged damage claims from hydraulic fracturing by property owners. Litigation resulting in financial compensation for damages linked to hydraulic fracturing, including damages from induced seismicity, could spur future litigation and bring increased attention to the practice of hydraulic fracturing. Judicial decisions could also lead to increased regulation, permitting requirements, enforcement actions, and penalties. Additional legislation or regulation could also lead to operational delays or restrictions or increased costs in the exploration for, and production of, oil, gas, and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional state or local laws, or the implementation of new regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows.

We will continue to be subject to uncertainty associated with new regulatory suspensions, revisions or rescissions and inconsistent state and federal regulatory mandates that could adversely affect our production.

Federal and state regulatory initiatives relating to air quality and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.

There has been a trend toward increased air quality and GHG regulation and reduced emissions from oil and gas sources. These regulations include the New Source Performance Standards (“NSPS”), the National Emission Standards for Hazardous Air Pollutants programs, and ozone standards set under the National Ambient Air Quality Standards (“NAAQS”), among others. The adoption of additional state or local laws, or the implementation of new regulations could potentially cause a decrease in the completion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows. Please refer to the Environmental section in Part II, Item 7 of this report for additional information about the regulation of air emissions, particularly methane emissions from the oil and gas sector.

Requirements to reduce gas flaring could have an adverse effect on our operations.

Wells in the Midland Basin in Texas, where we have significant operations, produce natural gas, as well as oil and NGLs. Constraints in the gas gathering and processing network in certain areas of the Midland Basin have resulted in significant quantities of that gas being flared instead of gathered, processed, and sold. Further, we are subject to laws established by state and other regulatory agencies that restrict the duration and amount of natural gas that can be legally flared. These laws and regulations, including potential future regulations that may impose further restrictions on flaring, could limit the amount of oil and gas we can produce from our wells or may limit the number of wells or the locations that we can drill. Any future laws and regulations may increase our operational costs, or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

Our ability to produce oil, gas, and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.

The hydraulic fracturing process on which we and others in our industry depend to complete wells that will produce commercial quantities of oil, gas, and NGLs requires the use and disposal of significant quantities of water.

Our inability to secure sufficient amounts of water, or to dispose of, or recycle, the water produced from our wells, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of oil, gas, and NGLs.

Compliance with environmental regulations, surface use agreements, and permit requirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.

Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs.

While courts have generally declined to assign direct liability for climate change to large sources of GHG emissions, some have required increased scrutiny of such emissions by federal agencies and permitting authorities. There is a continuing risk of claims being filed against companies that have significant GHG emissions, and new claims for damages and increased government scrutiny, especially from state and local governments, will likely continue.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and the majority of states have already taken measures to reduce emissions of GHGs through various measures, including, primarily through the planned development of GHG emission inventories, participation in and/or regional GHG “cap and trade” programs, and/or transition to clean energy. The focus on legislating and/or regulating methane could result in increased scrutiny for sources emitting high levels of methane, including during permitting processes, analysis, regulation and reduction of methane emissions as a requirement for project approval, and actions taken by one agency for a specific industry establishing precedents for other agencies and industry sectors. In 2021, the EPA proposed requirements for methane emission reductions from existing oil and gas equipment.

Any court rulings, laws, or regulations that restrict or require reduced emissions of GHGs could lead to increased operating and compliance costs and could have an adverse effect on demand for the oil and gas that we produce.

Scientists have predicted that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our drilling,

completion, and production activities, including, for example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such events. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies, or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change. Federal regulations or policy changes regarding climate change preparation requirements could also impact our costs and planning requirements because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes.

Our ability to sell oil, gas, and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines, and other transportation systems owned or operated by third-parties or by other interruptions beyond our control, which could obstruct, limit, or eliminate our access to oil, gas, and NGL markets.

The marketability of our oil, gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, pipelines, and other transportation systems, which are generally owned or operated by third parties. Any significant interruption in service from, damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay, or discontinuance of development plans for our properties, increases in costs, or lower price realizations. Although we have some influence over the processing and transportation of our operated production, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil, gas, and NGL production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines or processing facilities, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, transport, or market oil, gas, and NGLs.

Production may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market or other conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flows and results of operations.

We have limited control over the activities on properties we do not operate.

Some of our properties are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator’s skill and expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount of expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the expenditures of such properties. These limitations and our dependence on the operator and other working interest owners in these projects could cause us to incur unexpected future costs.

Risks Related to Debt, Liquidity, and Access to Capital

Substantial capital is required to develop and replace our reserves.

We must make substantial capital expenditures to find, acquire, develop, and produce oil, gas, and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for oil, gas, and NGL sales, our success in locating, developing, and acquiring new reserves, and the orderly functioning of credit and capital markets. If our cash flows from operations are less than expected, we may reduce our planned capital expenditures. If we cannot access sufficient liquidity under our Credit Agreement, or raise additional funds through debt or equity financing or the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited.

Downgrades in our credit ratings by various credit rating agencies could impact our access to capital and materially adversely affect our business and financial condition.

Downgrades of our credit rating levels could have material adverse consequences on our business and future prospects and could:

•limit our ability to access capital markets, including for the purpose of refinancing our existing debt;

•cause us to refinance or issue debt with less favorable terms and conditions, which debt may restrict, among other things, our ability to make any dividend distributions or repurchase shares;

•negatively impact lenders’ willingness to transact business with us which could impact our ability to obtain favorable terms and conditions under our Credit Agreement;

•negatively impact current and prospective customers’ willingness to transact business with us;

•impose additional insurance, guarantee, bonding, and collateral requirements;

•limit our access to bank and third-party guarantees, surety bonds, and letters of credit; and

•cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding indebtedness.

We cannot provide assurance that any of our current credit ratings will remain in effect for any given period of time or that a credit rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant.

Our commodity derivative contract activities may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales.

To mitigate a portion of the exposure to potentially adverse market changes in oil, gas, and NGL prices and the associated impact on cash flows, we regularly enter into commodity derivative contracts. Our commodity derivative contracts include swap and collar arrangements for oil, gas, and NGLs. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

•our production is less than expected;

•one or more counterparties to our commodity derivative contracts default on their contractual obligations; or

•there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.

In addition, commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract, which we experienced in 2021. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional detail regarding our commodity derivative contracts.

Future oil, gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.

We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and development costs are capitalized when incurred. Exploratory well costs are initially capitalized, pending the determination of whether proved reserves have been discovered. If commercial quantities of proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed as dry holes.

The capitalized costs of our oil and gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net cash flows, we generally must write down the costs of each depletion pool to the estimated discounted future net cash flows of that depletion pool. Write downs for unproved properties are also evaluated for carrying costs in excess of fair value. This evaluation considers the potential for abandonment due to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. Declines in the prices of oil, gas, or NGLs, or unsuccessful exploration efforts, could cause proved and/or unproved property impairments in the future.

We review the carrying values of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter. Once incurred, a write-down of oil and gas properties held for use cannot be reversed at a later date, even if oil, gas, or NGL prices increase.

Lower oil, gas, or NGL prices could limit our ability to borrow under our Credit Agreement.

As of December 31, 2021, both the borrowing base and aggregate lender commitments under our Credit Agreement were $1.1 billion. The borrowing base is subject to semi-annual redetermination based on the bank group’s assessment of the value of our proved reserves, which in turn is impacted by oil, gas, and NGL prices. The next borrowing base redetermination date is scheduled for April 1, 2022. Divestitures of additional properties, incurrence of additional debt, or declines in commodity prices could limit our borrowing base and reduce the amount we can borrow under our Credit Agreement, which could in turn impact, among other things, our ability to service our debt, fund our capital program, or compete for the acquisition of new properties.

The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt.

As of December 31, 2021, we had $2.1 billion of aggregate principal amount outstanding of Senior Notes with maturities through 2028, as further discussed and defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report. Additionally, we had no outstanding balance on our revolving credit facility and $1.1 billion of available borrowing capacity under our Credit Agreement as of December 31, 2021. Our long-term debt represented 51 percent of our total book capitalization as of December 31, 2021.

The amounts of our indebtedness could have important consequences for our operations, including:

•making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;

•requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to capital investments;

•limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends;

•placing us at a competitive disadvantage compared to our competitors with less debt; and

•making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our Credit Agreement or from other sources, we might not be able to service our debt, issue additional debt, or fund our planned capital expenditures and other liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, divest assets, and/or restructure or refinance our debt. We might not be able to sell our equity, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our Credit Agreement and any future credit agreements, may prohibit us from pursuing any of these alternatives.

As discussed above, our Credit Agreement is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate adjustments to our borrowing base or arrange new financing, we may be forced to sell significant assets.

The agreements governing our debt arrangements contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.

Our debt agreements, including our Credit Agreement and the indentures governing our Senior Notes, contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests, including restrictions on incurring debt, issuing dividends, redeeming common stock, selling assets, creating liens, entering into transactions with affiliates, and merging, consolidating, or selling our assets. Our ability to borrow under our Credit Agreement is subject to compliance with certain financial and non-financial covenants, as outlined in the Credit Agreement. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion. These restrictions on our ability to operate our business could significantly harm us by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

Risks Related to Corporate Governance and Ownership of Public Equity Securities

The price of our common stock may fluctuate significantly, which may result in losses for investors.

From January 1, 2021, to February 10, 2022, the intraday trading prices per share of our common stock as reported by the New York Stock Exchange ranged from a low of $5.89 per share in January 2021 to a high of $38.25 per share in November 2021. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include, in addition to the other risk factors set forth herein, the following:

•changes in oil, gas, or NGL prices;

•changes in the outlook for regional, national, or global commodity supply and demand;

•variations in drilling, recompletion, and operating activity;

•changes in financial estimates by securities analysts;

•changes in market valuations of comparable companies;

•additions or departures of key personnel;

•increased volatility due to the impacts of algorithmic trading practices;

•future sales of our common stock;

•negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole;

•changes in the national and global economic outlook, including potential impacts from trade agreements; and

•international trade relationships, potentially including the effects of trade restrictions or tariffs affecting the raw materials we utilize and the commodities we produce in our business.

We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result.

Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment, which could adversely affect the price of our common stock.

Delaware corporate law and our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control of us or our management. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price investors are willing to pay in the future for shares of our common stock.

In addition, stockholder activism in our industry has been present in recent years, and if investors seek to exert influence or affect changes to our business that we do not believe are in the long-term best interests of our stockholders, such actions could adversely impact our business by, among other things, distracting our Board of Directors and management team, causing us to incur unexpected advisory fees and other related costs, impacting execution of our strategic objectives, and creating unnecessary market uncertainty.

We may not always pay dividends on our common stock.

Payment of future dividends remains at the discretion of our Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our Credit Agreement limiting our annual cash dividends to no more than $12.0 million, and to covenants in the indentures governing our Senior Notes that limit our ability to pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the current annual dividend rate or discontinue the payment of dividends altogether.

General Risk Factors

Our increasing dependence on digital technologies puts us at risk for a cyber incident that could result in information theft, data corruption, operational disruptions or financial loss.

We are subject to cybersecurity risks. The oil and gas industry is increasingly dependent on digital technology in all aspects of our business. We use digital technology to conduct certain aspects of our drilling development, production and gathering activities, manage drilling rigs and completion equipment, gather and interpret seismic data, conduct reservoir modeling, record financial and operating data, and maintain employee and other databases. Our service providers, including those who gather, process, and market our oil, gas, and NGLs, are also increasingly reliant on digital technology. Our and their reliance on this technology increasingly puts us at risk for technology system failures, data or network disruptions, cyberattacks and other breaches in cybersecurity. Power failures, telecommunication or other system failures due to hardware or software malfunctions, computer viruses, vandalism, terrorism, natural disasters, fire, flood, human error or other means could significantly impair our ability to conduct our business.

Cybersecurity attacks are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, cash, or other assets, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. Deliberate attacks on, or security breaches in our systems, infrastructure, the systems and infrastructure of third-parties, or cloud-based applications could lead to disclosure of confidential information, a corruption or loss of our proprietary data, delays in production or exploration activities, difficulty in completing or settling transactions, challenges in maintaining our books and records, environmental damage, communication or other operational disruptions, and liability to third parties. Any insurance we might obtain in the future may not provide adequate protection from these risks. Any such events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. As these cyber risks continue to evolve and our dependence on digital technologies grows, we may be required to expend significant additional resources to continue to modify or enhance our protective measures and remediate cyber vulnerabilities.

Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.

As an oil, gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these

events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel, or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.

The threat of terrorism and the impact of military and other actions have caused instability in world financial markets and could lead to increased volatility in prices for oil, gas, and NGLs, all of which could adversely affect the markets for our production. Energy assets might be specific targets of terrorist attacks. While we currently maintain insurance that provides limited coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms we consider reasonable, or at all. In addition, this insurance may not cover all of our losses for a terrorist attack. These developments have subjected our operations to increased risk and, depending on their occurrence and ultimate magnitude, could have a material adverse effect on our business, financial condition, or results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Exchange Act.

ITEM 3. LEGAL PROCEEDINGS

At times, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are likely to have a materially adverse effect upon our financial condition, results of operations, or cash flows.

SPM NAM LLC. et al., v. SM Energy Company, Case No. 2018-07160, in the 189th Judicial District of Harris County, Texas (the “Lawsuit”). Plaintiff SPM NAM LLC (“SPM”) filed the Lawsuit against the Company on February 1, 2018. The Lawsuit concerned the Acquisition and Development Funding Agreement dated August 2, 2016 (together with its amendments, the “ADFA”). The parties to the ADFA (and its amendments) were the Company; SPM; and certain affiliates of SPM: (1) Schlumberger Technology Corporation; (2) Smith International, Inc.; (3) M-I, L.L.C.; and (4) Cameron International Corporation (the “Schlumberger Service Providers”). SPM and the Schlumberger Service Providers were the plaintiffs, and the Company was the defendant. The Company settled this matter on August 6, 2021.

ITEM 4. MINE SAFETY DISCLOSURES

These disclosures are not applicable to us.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM.” For dividend information, please refer to the caption Uses of Cash in Overview of Liquidity and Capital Resources in Item 7 of this report. Information regarding the SM Energy Equity Incentive Compensation Plan, as amended and restated effective as of May 22, 2018 (the “Equity Plan”), and the securities authorized under the Equity Plan is included below.

PERFORMANCE GRAPH

The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2016, and ending December 31, 2021, with the cumulative total returns of the Dow Jones Exploration and Production Index (“DJUSOS”), and the Standard & Poor’s 500 Stock Index (“SPX”).

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNS

The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the SEC.

Holders. As of February 10, 2022, the number of record holders of our common stock was 100. A substantially greater number of holders of our common stock are beneficial holders, whose shares of record are held by banks, brokers, and other financial institutions.

Purchases of Equity Securities by Issuer and Affiliated Purchasers. The following table provides information about purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended December 31, 2021, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act.


PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS
Period	Total Number of Shares Purchased (1)	Weighted Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number of Shares that May Yet be Purchased Under the Program (2)
First quarter of 2021	—	—		—	3,072,184
Second quarter of 2021	—	—		—	3,072,184
Third quarter of 2021	219,462	$	21.56	—	3,072,184
10/01/2021 - 10/31/2021	—	—		—	3,072,184
11/01/2021 - 11/30/2021	—	—		—	3,072,184
12/01/2021 - 12/31/2021	143,806	30.18		—	3,072,184
Total	363,268	$	24.97	—	3,072,184

____________________________________________

(1)All shares purchased by us in 2021 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying Restricted Stock Units (“RSU” or “RSUs”) and Performance Share Units (“PSU” or “PSUs”) issued under the terms of award agreements granted under the Equity Plan.

(2)In July 2006, our Board of Directors approved an increase in the number of shares of common stock that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes, as defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time. During 2021, we did not repurchase any shares of our common stock.

ITEM 6. [RESERVED]

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

The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements.

Overview of the Company

General Overview

Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our short-term operational and financial goals include generating positive cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization. Our long-term vision is to sustainably grow value for all of our stakeholders. We believe that in order to accomplish this vision, we must be a premier operator of top-tier oil and gas assets. Our strategy for achieving these goals is to focus on high-quality economic drilling, completion, and production opportunities. Our investment portfolio is comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive impact in the communities where we live and work; and transparency in reporting our progress in these areas. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company’s ESG policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide performance-based metrics that include key financial, operational, and environmental, health, and safety measures. Please refer to our Definitive Proxy Statement on Schedule 14A for the 2022 annual meeting of stockholders to be filed within 120 days from December 31, 2021, for additional discussion.

The markets for the commodities produced by our industry strengthened in 2021 as a result of increased demand outpacing increased supply for each of the commodities we produce. Prices for the commodities produced by our industry improved from historic lows in 2020, with oil and natural gas prices reaching their highest average annual price since 2014. However, commodity markets remain subject to heightened levels of uncertainty related to the Pandemic and escalating tensions between Russia and Ukraine. Russian military incursion into Ukraine could give rise to regional instability and result in heightened economic sanctions by the U.S. and the international community that, in turn, could increase uncertainty with respect to global financial markets and production output from OPEC+ and other oil producing nations. Additionally, the Pandemic remains a global health crisis and continues to evolve. Despite the emergence of new variants, deployment of vaccines and vaccine boosters to slow the spread of the COVID-19 virus has resulted in substantial improvements in global financial markets and public health. Disruption in financial and commodity markets and industry-specific impacts could result from future case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, and as a result, may require us to adjust our business plan. Despite continuing impacts of the Pandemic, geopolitical issues, and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our top-tier Midland Basin and South Texas assets.

Throughout the Pandemic, the safety of our employees, contractors, and the communities where we work has remained our first priority. While our core business operations require certain individuals to be physically present at well site locations, the majority of our office-based employees have worked remotely since the onset of the Pandemic, in order to limit physical interactions and to mitigate the spread of COVID-19. We maintain and continually assess procedures designed to limit the spread of COVID-19, and we continue to communicate to and train all of our employees regarding best practices for maintaining a healthy and safe work environment. We believe that we meet or exceed Centers for Disease Control and Prevention and OSHA guidelines related to the prevention of the transmission of COVID-19. Throughout the Pandemic, we have operated without significant disruptions to our business, and we believe that our pre-existing control environment and internal controls continue to be effective.

2021 Financial and Operational Highlights

We remain focused on maximizing returns and increasing the value of our top-tier Midland Basin and South Texas assets. We expect to do this through continued development optimization and further delineation of our Midland Basin assets and through further development of our Austin Chalk formation in South Texas. We believe our assets provide strong returns and are capable of providing for growth of internally generated cash flows while allowing for flexibility of production levels, which aligns with our priorities of reducing debt, improving leverage metrics and maintaining strong financial flexibility.

Financial and Operational Results. Average net daily equivalent production for the year ended December 31, 2021, increased 11 percent to 140.7 MBOE, compared with 126.9 MBOE for 2020, comprised of a 19 percent increase from our Midland Basin assets

and a two percent decrease from our South Texas assets. The total increase resulted from an increased number of completions, strong well performance, and our continued focus on operational execution. Realized prices for oil, gas, and NGLs increased 83 percent, 169 percent, and 141 percent, respectively, for the year ended December 31, 2021, compared with 2020. As a result of increased realized prices, oil, gas, and NGL production revenue increased 131 percent to $2.6 billion for the year ended December 31, 2021, compared with $1.1 billion for 2020. We recorded a net derivative loss of $901.7 million for the year ended December 31, 2021, compared to a net derivative gain of $161.6 million for 2020. These amounts include a derivative settlement loss of $749.0 million for the year ended December 31, 2021, and a derivative settlement gain of $351.3 million for the year ended December 31, 2020. Operational activities during the year ended December 31, 2021, resulted in the following financial and operational results:

•Net cash provided by operating activities of $1.2 billion for the year ended December 31, 2021, which was in excess of net cash used in investing activities of $667.2 million for the same period. Please refer to Analysis of Cash Flow Changes Between 2021 and 2020 and Between 2020 and 2019 in Part II, Item 8 of this report below for additional discussion.

•A cash balance of $332.7 million and no outstanding balance on the revolving credit facility as of December 31, 2021, compared with a revolving credit facility balance of $93.0 million as of December 31, 2020.

•Net income of $36.2 million, or $0.29 per diluted share, for the year ended December 31, 2021, compared with a net loss of $764.6 million, or $6.72 per diluted share for 2020. Net income for the year ended December 31, 2021, was primarily a result of increased production volumes and improved pricing, substantially offset by net derivative losses of $901.7 million. Please refer to Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019 below for additional discussion regarding the components of net income (loss) for each period presented.

•Adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2021, of $1.2 billion, compared with $975.4 million for 2020. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income (loss) and net cash provided by operating activities.

•Total estimated proved reserves as of December 31, 2021, increased 22 percent from December 31, 2020, to 492.0 MMBOE, of which, 58 percent were liquids (oil and NGLs) and 61 percent were proved developed reserves. We added 139.1 MMBOE through extensions and infill as a result of continued success in and further development of our Austin Chalk and Midland Basin assets, partially offset by 51.4 MMBOE of production during 2021 and the removal of 40.6 MMBOE of proved undeveloped reserves reclassified to unproved reserves categories as a result of development plan optimization. Our proved reserve life index increased to 9.6 years as of December 31, 2021, compared with 8.7 years as of December 31, 2020. Please refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $7.0 billion as of December 31, 2021, compared with $2.7 billion as of December 31, 2020, which was an increase of 160 percent year-over-year. Please refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

Operational Activities. During 2021, we continued to experience strong well performance in the RockStar area of our Midland Basin position due to successful operational execution, enhanced completion designs, and execution of our development strategy to drill and complete long laterals resulting from successful infill leasing and acreage trades, which have increased the contiguous nature of our acreage position. A large portion of our water transportation and disposal needs continue to be satisfied by the water facilities we operate in a core area of our RockStar acreage. Our South Texas program benefited from successful development of the Austin Chalk formation and continued strong performance from Eagle Ford shale wells. Efficiency and optimization in completions and operations in both the Midland Basin and in South Texas continued throughout 2021, and effective partnerships with our key service providers have allowed us to maintain continuity of operations during the Pandemic.

Our Midland Basin program averaged three drilling rigs and two completion crews during 2021. We drilled 61 gross (49 net) wells and completed 97 gross (81 net) wells during 2021 and net equivalent production increased year-over-year by 18 percent to 34.4 MMBOE. Costs incurred during 2021 totaled $433.8 million, or 60 percent of our total 2021 costs incurred. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continue to focus primarily on developing the Spraberry and Wolfcamp formations.

Our South Texas program averaged one drilling rig and one completion crew during 2021. We drilled 32 gross (32 net) and completed 31 gross (28 net) wells during 2021 and net equivalent production decreased year-over-year by two percent to 16.9 MMBOE. Costs incurred during 2021 totaled $240.7 million, or 34 percent of our total 2021 costs incurred. Drilling and completion activities in South Texas during 2021 were primarily focused on developing the Austin Chalk formation.

The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the year ended December 31, 2021:


	Midland Basin		South Texas		Total
	Gross	Net	Gross	Net	Gross	Net
Wells drilled but not completed at December 31, 2020 (1)	66	58	31	28	97	86
Wells drilled	61	49	32	32	93	81
Wells completed	(97)	(81)	(31)	(28)	(128)	(109)

Other (2)	—	1	—	—	—	1
Wells drilled but not completed at December 31, 2021 (3)	30	27	32	32	62	59

____________________________________________

(1) The South Texas drilled but not completed well count as of December 31, 2020, included 13 gross (13 net) wells that were not included in our five-year development plan, 12 of which were in the Eagle Ford shale.

(2) Includes adjustments related to normal business activities, including working interest changes for existing drilled but not completed wells. Working interest changes can result from divestitures, joint development agreements, farm-outs, and other activities.

(3) The South Texas drilled but not completed well count as of December 31, 2021, includes 11 gross (11 net) wells that are not included in our five-year development plan, 10 of which are in the Eagle Ford shale.

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:


	For the Year Ended
	December 31, 2021
	(in millions)
Development costs	$	583.5
Exploration costs	125.4
Acquisitions
Proved properties	0.1
Unproved properties	9.0
Total, including asset retirement obligations (1)	$	718.0

____________________________________________

(1) Please refer to the caption Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the year ended December 31, 2021:


	Midland Basin		South Texas		Total
Net production volumes:
Oil (MMBbl)	25.2		2.7		27.9
Gas (Bcf)	55.4		52.9		108.4
NGLs (MMBbl)	—		5.4		5.4
Equivalent (MMBOE)	34.4		16.9		51.4
Average net daily equivalent (MBOE per day)	94.4		46.4		140.7
Relative percentage	67	%	33	%	100	%

____________________________________________

Note: Amounts may not calculate due to rounding.

Net equivalent production increased 11 percent for the year ended December 31, 2021, compared with 2020, comprised of an 18 percent increase from our Midland Basin assets and a two percent decrease from our South Texas assets. Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019 below for additional discussion on production.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effect of derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the years ended December 31, 2021, 2020, and 2019:


	For the Years Ended December 31,
	2021		2020		2019
Oil (per Bbl):
Average NYMEX contract monthly price	$	67.92	$	39.40	$	57.03
Realized price	$	67.72	$	37.08	$	54.10
Effect of oil derivative settlements	$	(18.73)	$	14.40	$	(0.90)

Gas:
Average NYMEX monthly settle price (per MMBtu)	$	3.84	$	2.08	$	2.63
Realized price (per Mcf)	$	4.85	$	1.80	$	2.39
Effect of gas derivative settlements (per Mcf)	$	(1.41)	$	0.11	$	0.21

NGLs (per Bbl):
Average OPIS price (1)	$	36.65	$	17.96	$	22.34
Realized price	$	33.67	$	13.96	$	17.26
Effect of NGL derivative settlements	$	(13.68)	$	1.28	$	4.43

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(1) Average OPIS prices per barrel of NGL, historical or strip, assumes a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

Commodity prices in 2021 significantly improved from historic lows experienced in 2020 as a result of the misalignment of supply and demand caused by the Pandemic and other macroeconomic events. Given the dynamic nature of the Pandemic, uncertainty surrounding the escalating tensions between Russia and Ukraine, and the potential impacts to global commodity and financial markets, we expect future benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future impacts that may result. In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other currencies. Our realized prices at local sales points may also be affected by infrastructure capacity in the area of our operations and beyond.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of February 10, 2022, and December 31, 2021:


	As of February 10, 2022		As of December 31, 2021
NYMEX WTI oil (per Bbl)	$	83.82	$	72.89
NYMEX Henry Hub gas (per MMBtu)	$	4.15	$	3.69
OPIS NGLs (per Bbl)	$	41.29	$	37.02

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows

us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

Outlook

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the three months ended December 31, 2021, and the preceding three quarters.


	For the Three Months Ended
	December 31,		September 30,		June 30,		March 31,
	2021		2021		2021		2021
	(in millions)
Net equivalent production (MMBOE)	14.6		14.3		12.4		10.0
Oil, gas, and NGL production revenue	$	852.4	$	759.8	$	562.6	$	423.2
Oil, gas, and NGL production expense	$	143.3	$	135.7	$	125.5	$	100.9
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	200.0	$	202.7	$	204.7	$	167.0
Exploration	$	12.6	$	8.7	$	8.7	$	9.3
General and administrative	$	37.1	$	25.5	$	24.6	$	24.7
Net income (loss)	$	424.9	$	85.6	$	(223.0)	$	(251.3)

____________________________________________

Note: Amounts may not calculate due to rounding.

Selected Performance Metrics


	For the Three Months Ended
	December 31,			September 30,			June 30,			March 31,
	2021			2021			2021			2021
Average net daily equivalent production (MBOE per day)	158.3			155.8			136.5			111.6
Lease operating expense (per BOE)	$	4.21		$	4.20		$	4.62		$	4.64
Transportation costs (per BOE)	$	2.61		$	2.41		$	3.01		$	2.94
Production taxes as a percent of oil, gas, and NGL production revenue	4.8		%	4.7		%	4.5		%	4.6		%
Ad valorem tax expense (per BOE)	$	0.22		$	0.38		$	0.45		$	0.52
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	13.74		$	14.14		$	16.48		$	16.62
General and administrative (per BOE)	$	2.55		$	1.78		$	1.98		$	2.46

____________________________________________

Note: Amounts may not calculate due to rounding.

Overview of Selected Production and Financial Information, Including Trends


	For the Years Ended December 31,			Amount Change Between		Percent Change Between
	2021	2020	2019	2021/2020	2020/2019	2021/2020		2020/2019
Net production volumes: (1)
Oil (MMBbl)	27.9	23.0	21.9	4.9	1.1	21	%	5	%
Gas (Bcf)	108.4	103.9	109.8	4.5	(5.9)	4	%	(5)	%
NGLs (MMBbl)	5.4	6.1