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Form 10-K SM Energy Co For: Dec 31

February 22, 2024 8:56 AM EST
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
    Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2023
or
    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)
Delaware41-0518430
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
1700 Lincoln Street, Suite 3200, 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 classTrading Symbol(s)Name of each exchange on which registered
Common stock, $0.01 par valueSMNew 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 filerAccelerated filer
Non-accelerated filerSmaller 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.
If securities are registered pursuant to section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
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 116,456,585 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, 2023, the last business day of the registrant’s most recently completed second fiscal quarter, of $31.63 per share, as reported on the New York Stock Exchange, was $3,683,521,784. 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 8, 2024, the registrant had 115,746,540 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 2024 annual meeting of stockholders, to be filed within 120 days after December 31, 2023.
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TABLE OF CONTENTS
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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 (“Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (“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,” “seek,” “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:
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;
the amount and nature of future capital expenditures, the resilience of our assets to declining commodity prices, and the availability of liquidity and capital resources to fund capital expenditures;
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, and the effects of inflation on each of these;
armed conflict, political instability, or civil unrest in oil and gas producing regions and transportation channels, including instability in the Middle East, the wars between Russia and Ukraine and Israel and Hamas, and related potential effects on laws and regulations, or the imposition of economic or trade sanctions;
any changes to the borrowing base or aggregate lender commitments under our Seventh Amended and Restated Credit Agreement (“Credit Agreement”);
cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;
our drilling and completion activities and other exploration and development activities, each of which could be affected by supply chain disruptions and inflation, 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; 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.

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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.
Extension well. A well drilled to extend the limits of a known 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.
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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.
Lease operating expenses (“LOE”). 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 (“HH”). New York Mercantile Exchange Henry Hub, a common industry benchmark price for gas.
OPEC+. The Organization of the Petroleum Exporting Countries (“OPEC”) 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 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. This measure is presented because management believes it provides useful information to investors for analysis of the Company's fundamental business on a recurring basis.
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 proved reserves as of the end of the year divided by actual production for the preceding 12-month period.
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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.
SOFR. Secured Overnight Financing Rate.
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 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.
7


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 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.”
Our principal office is located at 1700 Lincoln Street, Suite 3200, Denver, Colorado 80203, and our telephone number is (303) 861-8140.
Strategy
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 long-term vision and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our team executes this strategy by prioritizing safety, technological innovation, and stewardship of natural resources, all of which are integral to our corporate culture. Our near-term goals include continuing to return value to stockholders through our Stock Repurchase Program, as defined below, and fixed dividend payments, and by focusing on continued operational excellence.
Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas and in the Maverick Basin of South Texas that we believe are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. We seek to maximize returns and increase the value of our top-tier assets through disciplined capital spending, strategic acquisitions, and continued development and optimization of our existing assets. We believe that our high-quality assets facilitate a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining financial flexibility.
We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with 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 goals that include safety and spill metrics, minimizing flaring and reducing greenhouse gas (“GHG” or “GHGs”) emissions intensity, and maintaining low methane emissions intensity. Additionally, we are implementing systems and technologies to track ESG metrics to improve future reporting and performance and to increase employee awareness. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the effectiveness of our ESG policies, programs and initiatives, monitors and responds to emerging issues, 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, environmental, health, and safety measures.
Significant Developments in 2023
Return of Capital Program. In 2023, we continued to execute on our goal of sustainably returning capital to our stockholders through our Stock Repurchase Program and fixed quarterly dividend payments. Our Stock Repurchase Program commenced in September 2022, and originally authorized the repurchase of up to $500.0 million in aggregate value of our common stock through December 31, 2024 (“Stock Repurchase Program”). During the year ended December 31, 2023, we repurchased and subsequently retired 6.9 million shares of our common stock at a cost of $228.0 million, excluding excise taxes, commissions, and fees. As of the filing of this report, $214.9 million remains available for repurchases of our outstanding common stock under the Stock Repurchase Program. During the year ended December 31, 2023, we paid dividends of $0.60 per share, an increase from $0.16 per share paid during the year ended December 31, 2022. Additionally, in November 2023, we announced a 20 percent increase to our fixed dividend to $0.72 per share annually, to be paid in quarterly increments of $0.18 per share, beginning in the first quarter of 2024. Please refer to Note 3 – Equity in Part II, Item 8 of this report for additional discussion.
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Acquisition Activity. During 2023, we acquired approximately 20,000 net acres of oil and gas properties in Dawson and northern Martin counties, Texas. Additionally, in the Midland Basin, we added approximately 9,100 net acres through organic leasing activity, we completed an asset exchange, and we acquired additional working interests in certain wells. Please refer to Note 16 – Acquisitions in Part II, Item 8 of this report for additional discussion.
Reserves and Capital Investment. Our total estimated net proved reserves were 604.9 MMBOE as of December 31, 2023, which was an increase of 13 percent from 537.4 MMBOE as of December 31, 2022. This increase primarily consisted of revisions of previous estimates of 113.9 MMBOE related to infill reserves in both our South Texas and Midland Basin programs, partially offset by 55.5 MMBOE of production during 2023. Our proved reserve life index increased to 10.9 years as of December 31, 2023, compared with 10.1 years as of December 31, 2022. Please refer to Areas of Operation and Reserves below for additional discussion regarding revisions of previous estimates due to infill, price, and performance revisions, the removal of certain proved undeveloped reserve cases that are no longer within our development plan over the next five years, and additions from extensions and discoveries. Costs incurred increased 28 percent from 2022 to $1.2 billion in 2023. 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.
Production, Pricing and Revenue, and Commodity Derivatives. Our average net daily equivalent production in 2023 increased five percent compared with 2022 to 152.0 MBOE, consisting of 65.1 MBbl of oil, 362.7 MMcf of gas, and 26.4 MBbl of NGLs, as a result of an increased number of completions. Oil production as a percentage of total production decreased to 43 percent in 2023 from 45 percent in 2022, as a result of production from our South Texas assets becoming a higher percentage of total production in 2023.
Realized prices before the effect of net derivative settlements (“realized price” or “realized prices”) for oil, gas, and NGLs decreased 19 percent, 61 percent, and 35 percent, respectively, for the year ended December 31, 2023, compared with 2022. As a result of decreased realized prices, oil, gas, and NGL production revenue decreased 29 percent to $2.4 billion for the year ended December 31, 2023, compared with $3.3 billion for 2022. Oil production revenue was 77 percent and 68 percent of total production revenue for the years ended December 31, 2023, and 2022, respectively.
We recorded a net derivative gain of $68.2 million for the year ended December 31, 2023, compared to a net derivative loss of $374.0 million for the year ended December 31, 2022. These amounts include a net derivative settlement gain of $26.9 million for the year ended December 31, 2023, and a net derivative settlement loss of $710.7 million for the year ended December 31, 2022.
Please refer to Areas of Operation below and Overview of the Company in Part II, Item 7 of this report for additional discussion.
Outlook
Our long-term vision and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets. We are focused on operational execution, maintaining and expanding our portfolio quality and depth, and returning capital to stockholders through our Stock Repurchase Program and fixed dividend, while maintaining a strong balance sheet.
We expect our total 2024 capital program to be between $1.16 billion and $1.20 billion, excluding acquisitions, which we expect to fund with cash flows from operations and cash on hand. We plan to focus our 2024 capital program on highly economic oil development projects in both our Midland Basin and South Texas assets, including the assets we acquired during 2023. We expect to repurchase additional shares of our outstanding common stock through our Stock Repurchase Program during 2024, under which $214.9 million remains available for repurchases through December 31, 2024, as of the filing of this report.
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Areas of Operation
Area Map 1.24.24.jpg
____________________________________________
(1)As of December 31, 2023.
Our 2023 operations were concentrated in the Midland Basin and South Texas, as described below. The following table summarizes estimated net proved reserves, net production volumes, and costs incurred for the year ended December 31, 2023, for these areas:
Midland Basin
South Texas
Total (1)
Net proved reserves
Oil (MMBbl)159.2 70.9 230.1 
Gas (Bcf)654.8 877.2 1,532.0 
NGLs (MMBbl)0.2 119.3 119.5 
MMBOE (1)
268.5 336.4 604.9 
Relative percentage
44 %56 %100 %
Proved developed %62 %52 %56 %
Net production volumes
Oil (MMBbl)17.5 6.3 23.8 
Gas (Bcf)59.8 72.6 132.4 
NGLs (MMBbl)— 9.6 9.7 
MMBOE (1)
27.5 28.0 55.5 
Avg. daily equivalents (MBOE/d) (1)
75.4 76.7 152.0 
Relative percentage
50 %50 %100 %
Costs incurred (in millions) (2)
$768.1 $423.5 $1,235.0 
___________________________________________
(1)Amounts may not calculate due to rounding.
(2)Asset costs incurred do not sum to total costs incurred primarily due to corporate charges incurred on exploration activities and costs related to exploration efforts outside of our core areas of operation that are excluded from this table. For total costs incurred, please refer to Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.
Total estimated net proved reserves at December 31, 2023, increased 13 percent from December 31, 2022. Total net equivalent production increased five percent for the year ended December 31, 2023, compared with 2022. Costs incurred for the year ended December 31, 2023, increased 28 percent compared with 2022, primarily as a result of increases in capital activity related to the development of both our Midland Basin and South Texas assets, acquisitions of proved and unproved properties and leasing activity in the Midland Basin, and inflation.
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Midland Basin. Our Midland Basin assets, located in the Permian Basin in West Texas, are comprised of approximately 110,000 net acres, and include our RockStar assets in Howard and Martin counties, our Sweetie Peck assets in Upton and Midland counties, and our Klondike assets, which we acquired in 2023, in Dawson and northern Martin counties (“Midland Basin”). In 2023, drilling and completion activities were focused within our RockStar and Sweetie Peck assets, and we began drilling on our newly acquired Klondike acreage. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations. We expect our 2024 capital activity in the Midland Basin to be focused on highly economic oil development projects.
In 2023, costs incurred were $768.1 million, and we averaged three drilling rigs and one completion crew. We drilled 54 gross (37 net) wells, completed 64 gross (54 net) wells, and acquired additional working interests in five net wells during the year ended December 31, 2023. As of December 31, 2023, 39 gross (29 net) wells had been drilled but not completed in our operated Midland Basin program. Net equivalent production for the year ended December 31, 2023, was 27.5 MMBOE, a seven percent decrease from 29.7 MMBOE for the year ended December 31, 2022. Estimated net proved reserves increased four percent to 268.5 MMBOE at December 31, 2023, from 257.4 MMBOE at December 31, 2022. Positive revisions of previous estimates primarily consisted of 43.4 MMBOE of infill and 21.3 MMBOE resulting from changes to decline curve estimates based on reservoir engineering analysis, partially offset by negative revisions of 18.2 MMBOE related to well performance and production of 27.5 MMBOE.
South Texas. Our South Texas assets are comprised of approximately 155,000 net acres located in Dimmit and Webb counties, Texas (“South Texas”). In 2023, our operations in South Texas were focused on production from the Austin Chalk formation and the Eagle Ford shale formation, and further development of the Austin Chalk formation. Our overlapping acreage position in the Maverick Basin in South Texas 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 our 2024 capital activity in South Texas to be focused primarily on developing the Austin Chalk formation.
In 2023, costs incurred were $423.5 million, and we averaged two drilling rigs and one completion crew. We drilled 46 gross (46 net) wells and completed 38 gross (37 net) wells, and as of December 31, 2023, 37 gross (37 net) wells had been drilled but not completed in our operated South Texas program. Net equivalent production for the year ended December 31, 2023, was 28.0 MMBOE, a 20 percent increase from 23.2 MMBOE for the year ended December 31, 2022. Estimated net proved reserves increased 20 percent to 336.4 MMBOE at December 31, 2023, from 280.0 MMBOE at December 31, 2022. Positive revisions of previous estimates consisted of 70.4 MMBOE of infill and 44.0 MMBOE of performance revisions resulting from changes to decline curve estimates based on reservoir engineering analysis. Additions of 30.1 MMBOE were the result of continued success in our development of the Austin Chalk formation. These increases were partially offset by production of 28.0 MMBOE, negative price revisions of 24.5 MMBOE, and negative revisions of 9.9 MMBOE related to well performance. As a result of revising our development plan, partially in response to decreased benchmark gas prices and certain lease obligations, we removed 25.8 MMBOE of net proved undeveloped reserves that were no longer in our five-year development plan. These net proved undeveloped reserves primarily related to our Eagle Ford assets and were replaced with certain infill revisions to net proved undeveloped reserves associated with different locations that were added to our five-year development plan. Additionally, infill revisions replaced converted net proved undeveloped reserves.
Office Space. As of December 31, 2023, we leased and owned office space as summarized in the table below:
Approximate Square Footage LeasedApproximate Square Footage Owned
Corporate - Denver, CO
59,000 — 
Midland, TX
59,000 — 
Houston, TX and Catarina, TX, respectively
21,000 12,000 
Total139,000 12,000 
Reserves
Reserve estimates are inherently imprecise. Estimates for new discoveries and undeveloped locations are considered more imprecise than reserve estimates for producing oil and gas properties. Accordingly, we expect these estimates to change as new information becomes available. The table below presents the standardized measure of discounted future net cash flows and PV-10. PV-10 is a non-GAAP financial measure that is reconciled to the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure. PV-10 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 before consideration of tax characteristics specific to individual 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 net 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 table below should be read along with Risk Factors in Part I, Item 1A of this report.
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The following table summarizes estimated net proved reserves, the standardized measure of discounted future net cash flows (GAAP), PV-10 (non-GAAP), the prices used in the calculation of net proved reserves estimates, and reserve life index as of December 31, 2023, 2022, and 2021:
As of December 31,
202320222021
Net reserve volumes:
Proved developed
Oil (MMBbl)118.5 110.4 110.7 
Gas (Bcf)948.5 902.1 833.0 
NGLs (MMBbl)64.7 57.1 50.7 
MMBOE (1)
341.2 317.8 300.2 
Proved undeveloped
Oil (MMBbl)111.6 95.4 88.8 
Gas (Bcf)583.5 500.8 410.4 
NGLs (MMBbl)54.8 40.7 34.5 
MMBOE (1)
263.6 219.6 191.8 
Total proved (1)
Oil (MMBbl)230.1 205.8 199.5 
Gas (Bcf)1,532.0 1,402.9 1,243.5 
NGLs (MMBbl)119.5 97.8 85.2 
MMBOE604.9 537.4 492.0 
Net proved developed reserves percentage
56 %59 %61 %
Net proved undeveloped reserves percentage
44 %41 %39 %
Reserve data (in millions):
Standardized measure of discounted future net cash flows (GAAP)$6,280.1 $9,962.1 $6,962.6 
PV-10 (non-GAAP):
Proved developed PV-10
$4,965.1 $8,234.8 $5,407.2 
Proved undeveloped PV-10
2,411.4 3,919.7 2,751.4 
Total proved PV-10 (non-GAAP)$7,376.5 $12,154.5 $8,158.6 
12-month trailing average prices: (2)
Oil (per Bbl)
$78.22 $93.67 $66.56 
Gas (per MMBtu)
$2.64 $6.36 $3.60 
NGLs (per Bbl)
$27.72 $42.52 $36.60 
Reserve life index (years) (3)
10.9 10.1 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 net proved reserves.
(3)Please refer to the reserve life index term in the Glossary section of this report for information describing how this metric is calculated.
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The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 (non-GAAP) of total estimated net 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,
202320222021
(in millions)
Standardized measure of discounted future net cash flows (GAAP)
$6,280.1 $9,962.1 $6,962.6 
Add: 10 percent annual discount, net of income taxes
5,294.5 7,551.5 4,844.9 
Add: future undiscounted income taxes
2,000.0 3,888.3 2,130.3 
Pre-tax undiscounted future net cash flows
13,574.6 21,401.9 13,937.8 
Less: 10 percent annual discount without tax effect
(6,198.1)(9,247.4)(5,779.2)
PV-10 (non-GAAP)$7,376.5 $12,154.5 $8,158.6 
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, 2023, we did not have any net proved undeveloped reserves that had been on our books in excess of five years, and substantially all of our net proved undeveloped reserves were on acreage that was not expected to expire, or that was 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 net proved undeveloped reserves. Of the 263.6 MMBOE of total net proved undeveloped reserves as of December 31, 2023, approximately 36.8 MMBOE of net proved undeveloped reserves in the Midland Basin and 87.3 MMBOE of net proved undeveloped reserves in South Texas were offset by more than one development spacing area from the nearest proved 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, 2023, estimated net proved undeveloped reserves increased 44.1 MMBOE, or 20 percent, compared with December 31, 2022. The following table provides a reconciliation of our net proved undeveloped reserves for the year ended December 31, 2023:
Total
(MMBOE)
Total net proved undeveloped reserves:
Beginning of year219.6 
Revisions of previous estimates98.8 
Conversions to proved developed(43.1)
Removed for five-year rule(30.8)
Additions from extensions and discoveries22.7 
Sales of reserves(5.3)
Purchases of minerals in place1.8 
End of year (1)
263.6 
____________________________________________
(1)Amount may not calculate due to rounding.
Revisions of previous estimates. During 2023, revisions of previous estimates totaled 98.8 MMBOE. Positive revisions consisted of 103.8 MMBOE of infill reserves, of which 60.5 MMBOE and 43.3 MMBOE of estimated net proved undeveloped reserves
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were attributable to our South Texas and Midland Basin programs, respectively, and 13.3 MMBOE of performance revisions resulted from changes to decline curve estimates based on reservoir engineering analysis. Negative revisions consisted of 14.2 MMBOE that resulted from well performance related to infill development, and price revisions of 4.0 MMBOE that resulted primarily from decreases in benchmark gas and NGL prices.
Conversions to proved developed. Our 2023 conversion rate was 20 percent and primarily resulted from the development of proved reserves in our Midland Basin program and in our Austin Chalk assets in our South Texas program. During 2023, we incurred $740.2 million on projects with reserves booked as proved undeveloped at the end of 2022, of which $515.9 million was spent on converting net proved undeveloped reserves to proved developed reserves by December 31, 2023. At December 31, 2023, drilled but not completed wells represented 41.2 MMBOE of total estimated net proved undeveloped reserves. We expect to incur $212.6 million of additional capital expenditures in completing these drilled but not completed wells, and we expect all estimated net proved undeveloped reserves to be converted to proved developed reserves within five years from their initial booking as net proved undeveloped reserves.
Removed for five-year rule. As a result of our testing and delineation efforts in 2023, we revised certain aspects of our future development plan to focus on maximizing returns and the value of our assets. We removed 30.8 MMBOE of estimated net proved undeveloped reserves and reclassified these locations to unproved reserve categories based on development schedule revisions made partially in response to decreased benchmark gas prices and certain lease obligations. Of the 30.8 MMBOE, 25.8 MMBOE primarily related to our Eagle Ford assets in our South Texas program, and 5.0 MMBOE related to our Midland Basin program.
Additions from extensions and discoveries. During 2023, we added 22.7 MMBOE of estimated net proved undeveloped reserves, of which 21.9 MMBOE were in South Texas, and resulted from extensions from our continued success in delineating the Austin Chalk formation.
As of December 31, 2023, estimated future development costs relating to our net proved undeveloped reserves totaled $2.8 billion, and we expect to incur approximately $860.6 million, $585.6 million, and $555.7 million in 2024, 2025, and 2026, 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 (“Audit Committee”), 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 teams’ 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 since 1937. 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 person at Ryder Scott primarily responsible for overseeing our reserves audit is a Senior Vice President who received a Bachelor of Science degree in Petroleum Engineering and a Business Foundations Certificate from The University of Texas at Austin in 2002. She is a registered Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers. The 2023 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. 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.
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Production
The following table summarizes our net production volumes and realized prices for oil, gas, and NGLs produced and sold during the periods presented, and related production expense on a per BOE basis:
For the Years Ended December 31,
202320222021
Net production volumes
Oil (MMBbl)23.824.027.9
Gas (Bcf)132.4125.9108.4
NGLs (MMBbl)9.78.05.4 
Equivalent (MMBOE) (1)
55.553.051.4
Midland Basin net production volumes (2)
Oil (MMBbl)17.5 19.1 25.2 
Gas (Bcf)59.8 63.5 55.4 
NGLs (MMBbl)— — — 
Equivalent (MMBOE) (1)
27.5 29.7 34.4 
Maverick Basin net production volumes (2)
Oil (MMBbl)6.24.82.7
Gas (Bcf)72.562.452.8
NGLs (MMBbl)9.68.05.4 
Equivalent (MMBOE) (1)
27.923.216.9
Realized price
Oil (per Bbl)$76.28 $94.67 $67.72 
Gas (per Mcf)$2.48 $6.28 $4.85 
NGLs (per Bbl)$23.02 $35.66 $33.67 
Per BOE$42.60 $63.18 $50.58 
Production expense per BOE
Lease operating expense$5.13 $5.03 $4.39 
Transportation costs$2.46 $2.83 $2.71 
Production taxes$1.89 $3.07 $2.36 
Ad valorem tax expense$0.67 $0.79 $0.38 
____________________________________________
(1)Amounts may not calculate due to rounding.
(2)For each of the years ended December 31, 2023, 2022, and 2021, total estimated net proved reserves attributed to our Midland Basin field and our Maverick Basin field each exceeded 15 percent of our total estimated net proved reserves expressed on an equivalent basis.
Productive Wells
As of December 31, 2023, we had working interests in 898 gross (795 net) productive oil wells and 528 gross (494 net) productive gas wells. Productive wells are wells producing in commercial quantities or wells capable of commercial production that are temporarily shut-in. Multiple completions in the same wellbore are counted as one well, and as of December 31, 2023, 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.

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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 2023, 2022, and 2021, 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,
202320222021
GrossNetGrossNetGrossNet
Development wells
Oil74 62 68 57 107 91 
Gas21 21 18 18 11 
Non-productive— — — — — — 
95 83 86 75 118 99 
Exploratory wells
Oil
Gas
Non-productive (1)
— — 
11 10 10 10 
Total106 93 93 81 128 109 
____________________________________________
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.
(1)    For the year ended December 31, 2023, one gross (one net) well was unsuccessful due to technical issues during the drilling phase and was not included in the drilled or completed well counts.
In addition to the wells completed in 2023 (included in the table above), we were actively participating in the drilling of seven gross (seven net) wells and had 81 gross (70 net) drilled but not completed wells as of January 31, 2024. Drilled but not completed wells as of January 31, 2024, represent wells that were being completed or were waiting on completion. The drilled but not completed well count as of January 31, 2024, includes nine gross (nine net) wells that were not included in our five-year development plan as of December 31, 2023, eight of which are in the Eagle Ford shale.
Title to Properties
As of December 31, 2023, over 97 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, 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.
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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, 2023:
Developed Acres (1)
Undeveloped Acres (2)(3)
Total
GrossNetGrossNetGrossNet
Midland Basin:
RockStar69,938 63,204 384 368 70,322 63,572 
Sweetie Peck19,905 16,854 13,513 9,038 33,418 25,892 
Klondike
6,619 5,687 18,107 15,008 24,726 20,695 
Midland Basin Total (4)
96,462 85,745 32,004 24,414 128,466 110,159 
South Texas89,703 89,107 68,470 65,730 158,173 154,837 
Other (5)
10,499 10,499 90,078 25,606 100,577 36,105 
Total196,664 185,351 190,552 115,750 387,216 301,101 
____________________________________________
(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 8, 2024, 2,077, 7,946, and 12,131 net acres of our undeveloped acreage is scheduled to expire by December 31, 2024, 2025, and 2026, 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, 2023, total Midland Basin acreage excludes 1,213 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 Delivery 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, 2023, 2022, and 2021, 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 recognizes our employees as our most valuable assets, encourages personal and professional development, promotes innovation and leadership among all employees and, in turn, supports our efforts to attract and retain talent. Through our culture, we promote:
integrity and ethical behavior in the conduct of our business;
environmental, health, and safety priorities;
prioritizing the success of others and the team;
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 all employees are responsible for upholding Company-wide standards and values. We have policies designed to promote ethical conduct and integrity, which employees are
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required to read and acknowledge on an annual basis. The health and safety of our employees and contractors is our highest priority. We strive to achieve performance excellence in environmental, health, and safety management, and compensation of all employees is tied to annual environmental, health, and safety performance goals.
Personal and professional development is an important part of our culture and is employee driven, manager facilitated, and organizationally supported. Employees are routinely provided training opportunities to develop skills in leadership, safety, and technical acumen, which help strengthen our efforts to conduct business with high ethical standards. During 2023, many of our employees participated in two leadership and talent development programs that included more than 4,300 hours of aggregate training, exclusive of safety and other specialized technical training.
We measure employee engagement and satisfaction through periodic surveys, administered by an independent third-party vendor.
We are proud of our many outstanding employees who invest their time, talents, and financial resources in their communities. Our annual charitable giving program includes a monetary match of our employees’ personal contributions to qualified organizations and up to 12 hours per employee of Company-granted time to volunteer in the communities where we live and work.
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.
As of February 8, 2024, we had 544 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. We regularly perform internal analyses of our workforce demographics and, at times, we retain a third party to 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 applicable federal, state, and local laws and governmental regulations.
The following charts present certain Board of Directors and workforce metrics as of February 8, 2024:
Board of Directors Diversity
Officer Diversity (1)
Employee Diversity
434543467146825587001
____________________________________________
Note: Ethnic diversity data is determined under guidelines set forth by the United States Equal Employment Opportunity Commission and includes 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).
(1)Includes officers at the level of Vice President and above.
Seasonality
The price of crude oil is primarily driven by global socioeconomic and geopolitical 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 generally increases during winter months and decreases during summer months. To lessen the effect of seasonal gas demand and price fluctuations, pipelines, utilities, local distribution companies, and industrial users regularly utilize gas storage facilities and forward
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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 or extreme winters sometimes lessen or exacerbate these fluctuations.
Certain of our drilling, completion, and other operational activities 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 highly 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 professionals in our workforce, including specialized roles in the oil and gas industry such as geologists, geophysicists, engineers, and others. Throughout the general labor market, 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. The oil and gas industry is not insulated from the 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.
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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.
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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 took 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, and could result in significant litigation and related expenses in Part I, Item 1A of this report. Meteorological or extreme weather events (whether or not related to climate change), pose additional risks to our operations, which have included temporary shut-ins of certain wells and temporary capacity constraints at third-party purchasers impacting their ability to take delivery of 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
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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 minimizing 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 goals that include minimizing flaring, reducing 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. Minimizing 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, minimizing 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, Human Rights Policy, 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 SM Energy.
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, return of capital, 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 2023 and Reserves in Part I, Items 1 and 2, Comparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021 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;
inflation and other economic factors that contribute to market volatility;
weather conditions;
the availability and capacity of gathering, transportation, processing, storage, and/or refining facilities in asset-specific or localized areas;
liquefied natural gas deliveries to and from the United States;
the increased demand for, 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 OPEC+ to maintain effective oil price and production controls;
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political instability or armed conflict involving oil or gas producing countries or regions, such as instability in the Middle East, and the wars between Russia and Ukraine and Israel and Hamas;
shipping channel constraints and disruptions to and from oil and gas producing countries or regions;
actual or perceived epidemic or pandemic risks;
strengthening and weakening of the United States dollar relative to other currencies;
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.
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 initially capitalized are expensed as dry hole costs. During the years ended December 31, 2023, and 2022, we recorded amounts related to certain unsuccessful exploration activity to exploration expense.
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, which could have a material adverse effect on our business, financial condition, liquidity, and results of operations.
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.
Weakness in economic conditions, continued inflation, 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 heightened levels of intervention by the United States federal government and other governments. Weakness or uncertainty in the United States economy or other large economies could have a material adverse effect on our business and financial condition. For example:
•    inflation has increased the costs of our drilling and completion activities, and the costs of oilfield services, equipment, and materials in recent years and could continue or worsen and further impact our financial condition, liquidity, and results of operations, and could limit our pool of economic development opportunities;
a potential economic recession could impact demand for oil, gas, and NGLs, and cause commodity price volatility;
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 one or more of our lenders 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;
the Federal Reserve could change interest rates, as they did during 2022 and 2023, which could impact borrowing costs;
variable interest rate spread levels, including for SOFR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our Credit Agreement; and
changes in tax laws and regulations could require us to adjust our business plan.
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Global geopolitical tensions may create heightened volatility in oil, gas, and NGL prices and could adversely affect our business, financial condition and results of operations.
Global geopolitical tensions, including instability in the Middle East, and the wars between Russia and Ukraine and Israel and Hamas, could lead to significant market and other disruptions, including, but not limited to: significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, shipping channel constraints and disruptions, political and social instability, political and economic sanctions, geopolitical shifts, embargoes, changes in consumer or purchaser preferences, the potential destruction of critical oil-related infrastructure, as well as increases in cyberattacks and espionage. These factors could impact our operations and the financial condition of our business as well as the global economy.
Risks Related to Oil and Gas Operations and the Industry
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 success in drilling and completing new wells 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.
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 material 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 material adverse effect on us.
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.
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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 the National Environmental Policy Act (“NEPA”) because it did not adequately consider the impact of hydraulic fracturing and horizontal drilling before issuing leases. In 2022, the federal Ninth Circuit Court of Appeals held that two federal agencies violated NEPA, in part, by failing to evaluate the environmental impacts of well stimulation treatments such as hydraulic fracturing before authorizing unconventional oil drilling offshore. Similar cases continue to be filed. In addition, 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.
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, and could result in significant litigation and related expenses.
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
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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. In 2022, the EPA released a supplemental proposal expanding its initial requirements as well as updating requirements, and in 2023, proposed updates to GHG reporting requirements. The 2022 and 2023 proposals are meant to work in tandem with the programs included in the Inflation Reduction Act of 2022 (“IRA”).
The IRA imposes fees on emissions of GHGs, including methane, that exceed applicable thresholds. Our GHG emissions in 2023 did not exceed the thresholds set forth by the IRA, however, there is no assurance that we will be able to meet our goals or that we will not exceed the thresholds set forth by the IRA in the future. This and any court rulings, laws, or regulations that restrict or require reduced emissions of GHGs or introduce new climate-related regulations such as a carbon pricing system, could have an adverse effect on demand for the oil and gas that we produce, and could lead to increased operating and compliance costs, and litigation costs, which could have a material adverse impact on our business. We have a long-term goal to reduce our Scope 1 and 2 GHG emissions intensity by 50 percent by 2030, compared with base year 2019 levels, and we have an annual goal to limit our methane emissions intensity to 0.04 (metric tonnes CH4/MBOE).
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.
Requirements to reduce gas flaring could have an adverse effect on our operations.
In the Permian Basin in Texas, where we have significant operations, there have been, and could be in the future, constraints in gas takeaway capacity which has historically led to increased gas flaring. 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. We have committed to zero routine flaring at all of our operated locations, and non-routine flaring not to exceed one percent of total annual gas production, based on the full year average. Additionally, we set annual targets to limit our flaring that are tied to compensation for all employees. There is no assurance that we will be able to meet our goals with respect to flaring and any failure to meet such goals could cause reputational or other harm to our business. Any future laws or commitments may increase our operational costs, or restrict our production, which could have a material adverse effect on our financial condition, results of operations and cash flows.
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.
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 and/or completions operations or are unable to dispose of or recycle the water we produce 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.
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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.
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 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, 2023, we were contractually committed to deliver a minimum of 5 MMBbl of oil through July of 2026 and 11 MMBbl of produced water through June of 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.
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.
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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.
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 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, completion and other capital expenditures, gathering and transportation costs, operating expenses, 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, 2023, 44 percent, or 263.6 MMBOE, of our estimated proved reserves were proved undeveloped. In order to develop our net proved undeveloped reserves, as of December 31, 2023, we estimate approximately $2.8 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
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regarding the prices used in estimating the present value of our proved reserves as of December 31, 2023, and to the caption Oil and Gas Reserve Quantities under Critical Accounting 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. Future periods of sustained low commodity prices could occur and 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:
supply chain issues, including cost increases and availability of equipment or materials;
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, wildfires or other adverse weather conditions;
operational restrictions resulting from seismicity concerns;
governmental permitting delays;
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.
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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 material 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 8, 2024, that is scheduled to expire over the next three years, represents approximately 19 percent of our total net undeveloped acreage as of December 31, 2023. 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.
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 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, wildfires, 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 occur, we could sustain substantial losses.
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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 an 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.
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
Lower oil, gas, or NGL prices could limit our ability to borrow under our Credit Agreement.
As of December 31, 2023, the borrowing base and aggregate lender commitments under our Credit Agreement were $2.5 billion and $1.25 billion, respectively. 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, 2024. Divestitures of 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.
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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 have a material adverse effect on our business and financial condition.
Downgrades of our credit ratings 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 may restrict, among other things, our ability to make any dividend payments 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 typically include price 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. Please refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report for additional detail regarding our commodity derivative contracts.
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, 2023, we had $1.6 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. We had no outstanding balance on our revolving credit facility and had $1.2 billion of available borrowing capacity under our Credit Agreement as of December 31, 2023. Our long-term debt represented 30 percent of our total book capitalization as of December 31, 2023.
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;
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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. At times when we have an outstanding balance, 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, repurchasing 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.
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 toward 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.
Risks Related to Corporate Governance and Ownership of Public Equity Securities
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.
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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.
The price of our common stock may fluctuate significantly, which may result in losses for investors.
From January 1, 2023, to February 8, 2024, the intraday trading prices per share of our common stock as reported by the New York Stock Exchange ranged from a low of $24.66 per share in March 2023 to a high of $43.73 per share in October 2023. 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;
inflation;
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.
We may not always pay dividends on our common stock or repurchase common stock under our Stock Repurchase Program.
Payment of future dividends remains at the discretion of our Board of Directors, and common stock repurchases under our Stock Repurchase Program remain at the discretion of our Board of Directors and certain authorized officers of the Company. Decisions regarding the payment of dividends and the repurchase of common stock will continue to depend on our earnings, capital requirements, financial condition, general market and economic conditions, applicable legal requirements, the market price of our common stock, and other factors. The payment of dividends and the repurchase of our common stock are each subject to covenants in our Credit Agreement and in the indentures governing our Senior Notes that could limit our ability to make certain restricted payments including dividends and common stock repurchases. Our Board of Directors may determine in the future to reduce the current annual dividend rate or discontinue the payment of dividends altogether. The value of shares authorized for repurchase by the Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of our shares will be repurchased.
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, and our business, are increasingly dependent on digital technology. 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
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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.
Please refer to Cybersecurity Risk Management, Strategy, and Governance in Item 1C of this report for discussion of the Audit Committee’s role in cybersecurity governance. We did not experience any material cybersecurity incidents during 2023, however there can be no assurance that the measures we have taken to address information technology (“IT”) and cybersecurity risks will prove effective in the future.
We are incorporating artificial intelligence technologies into our processes and these technologies may present business, compliance, and reputational risks.
Our business increasingly utilizes artificial intelligence (“AI”), machine learning, and automated decision making to improve our processes. Issues in the development and use of AI, combined with an uncertain regulatory environment, may result in new or enhanced governmental or regulatory scrutiny, litigation, confidentiality or security risks, reputational harm, liability, or other adverse consequences to our business operations, all of which could adversely affect our business, results of operations, and financial condition.
In addition, it is possible that AI and machine learning-technology could, unbeknownst to us, be improperly utilized by employees while carrying out their responsibilities. The use of AI can lead to unintended consequences, including the unauthorized use or disclosure of confidential and proprietary information, or generating content that appears correct but is factually inaccurate, misleading, or otherwise flawed, which could harm our reputation and business and expose us to risks related to inaccuracies or errors in the output of such technologies. It is not possible to predict all of the risks related to the use of AI, machine learning and automated decision making, and developments in the regulatory frameworks governing the use of such technologies and in related stakeholder expectations may adversely affect our ability to develop and use such technologies or subject us to liability. If we fail to successfully integrate AI into our business processes, or if we fail to keep pace with rapidly evolving AI technological developments, including attracting and retaining talented data scientists, data engineers, and programmers, we may face a competitive disadvantage.
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, including armed attacks on shipping channels. 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. Depending on their occurrence and ultimate magnitude, terrorist threats or attacks 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 1C. CYBERSECURITY RISK MANAGEMENT, STRATEGY, AND GOVERNANCE
Risk Management and Strategy
We believe that mitigating cybersecurity risks is the responsibility of every employee. We take a preventative approach with respect to cybersecurity threats by building a resilient cybersecurity culture and strong IT infrastructure. Our processes for assessing, identifying, and managing material risks from cybersecurity threats include:
monitoring the threat landscape and taking measures to enhance our cybersecurity program to adapt to new and developing risks;
ongoing training, testing, and utilizing other forms of social engineering awareness and education for our employees;
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using cybersecurity systems and tools to monitor endpoints and environment logs in a centralized security information and event management system with capabilities for reporting and alerting on known threats and anomalous behaviors;
assessing the cybersecurity practices and external ratings and assessments of certain of our third-party technology and data vendors and service providers, and maintaining preventative controls and monitoring systems related to these partners;
creating and testing various incident response plans to hypothetical cybersecurity attacks in order to quickly assess and respond to potential and actual threats;
utilizing third-party experts to perform penetration testing and scanning of our systems for vulnerabilities;
obtaining third-party security maturity assessments, benchmarking, and security effectiveness ratings of our cybersecurity program; and
maintaining a retainer for incident response services with a trusted cybersecurity partner in order to quickly respond, investigate, contain, and recover in the event of a cybersecurity incident.
We have structured our cybersecurity risk management program according to the National Institute of Standards and Technology Cybersecurity Framework. We strive to employ cybersecurity best practices, including implementing new technologies to proactively monitor new threats and vulnerabilities and reduce risk; maintaining a Cybersecurity Incident Response Plan, Disaster Recovery Plan, and Business Continuity Plan; and regularly updating our response planning and protocols. We have integrated our cybersecurity processes into our overall risk management program, thereby establishing a comprehensive approach by which we determine and implement strategies designed to manage external, strategic, operational and financial risks to our business, including cybersecurity threats.
We utilize a wide range of protective cybersecurity technologies and tools, including, but not limited to, encryption, firewalls, endpoint detection and response, security information and event management, multi-factor authentication, and threat intelligence feeds. In addition, we use an information security risk management approach that includes monitoring security threats and trends in the industry, analyzing potential security risks that could impact the business, partnering with industry recognized security organizations, and coordinating an appropriate response should the need arise.
Cybersecurity threats and incidents could have a material impact on our financial condition and results of operations. A successful cyber-attack could lead to operational disruptions, financial losses, regulatory penalties, reputational damage, and legal liabilities. In some cases, the costs associated with investigating and remediating a cybersecurity incident, as well as potential litigation and regulatory fines, could result in a material impact to our financial condition and results of operations. During 2023, we did not experience any cybersecurity incidents that materially affected or are reasonably likely to materially affect us, including our business strategy, results of operations or financial condition, however, there can be no assurance that the measures we have taken to address IT and cybersecurity risks will prove effective in the future. For additional discussion of the IT and cybersecurity risks facing our business, please refer to Risk Factors in Part 1, Item 1A of this report.
We prioritize investment in cybersecurity risk management and governance. We continually assess the adequacy of our resources and capabilities to address emerging threats, regulatory requirements, and changes in technology. As cybersecurity threats evolve, we may need to further enhance our processes and technologies, which could require additional financial resources.
Governance
Our Board of Directors receives regular updates on relevant IT matters affecting the Company, including cybersecurity risks and mitigation strategies. In addition to the general oversight provided by the full Board of Directors, the Audit Committee is responsible for oversight of our risk assessment and management processes, including with respect to IT and cybersecurity risks. The Audit Committee receives a quarterly cybersecurity report and regular updates from our Vice President and Chief Information Officer and our Director of Cybersecurity Risk and Business Continuity, which includes, among other information, the steps management has taken, and the specific guidelines and policies that have been established, to monitor, control, mitigate and report exposure to IT and cybersecurity risk.
We have established a Cyber Incident Response Team (“CIRT”) to provide an efficient, effective, and orderly response to technology related incidents and our Cybersecurity Incident Response Plan contains protocols for communication within this team and reporting to executive management and the Audit Committee.
The CIRT is led by our Vice President and Chief Information Officer and Director of Cybersecurity Risk and Business Continuity. Together, these professionals are responsible for assessing and managing cybersecurity risks and they lead a team of specialized technologists entrusted with ensuring the functionality, continuity, and security of our technology infrastructure and data. Our Vice President and Chief Information Officer is a seasoned IT professional with over 28 years of experience encompassing all facets of IT within the energy industry. His extensive background comprises managing IT service delivery, designing and administering secure solutions, establishing robust IT and Internet of Things infrastructures, and effectively managing technology-related risks. His skill set includes proficiency in threat mitigation, comprehensive risk assessment, and integration of cybersecurity strategies into business operations designed to safeguard critical assets and sensitive data. He reports to our Executive Vice President and Chief Financial Officer. Our Director of Cybersecurity Risk and Business Continuity has over 23 years of experience in the IT field with a
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majority of that time focused on designing, building and maintaining technology systems. His experience includes implementing security solutions and processes with a focus on adapting to the evolving cybersecurity threat landscape. He is a skilled leader and reports to our Executive Vice President and Chief Financial Officer.
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 material adverse effect upon our financial condition, results of operations, or cash flows.
ITEM 4. MINE SAFETY DISCLOSURES
These disclosures are not applicable to us.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is 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, 2018, and ending December 31, 2023, 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
859
The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the SEC.
Holders. As of February 8, 2024, the number of record holders of our common stock was 102. 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.
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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 months, and the year ended December 31, 2023, 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 (2)
Maximum Number or Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (as of the period end date) (2)
First quarter of 2023
1,413,758 $28.32 1,413,758 $402,780,476 
Second quarter of 2023
2,550,976 $26.95 2,550,706 $334,036,922 
Third quarter of 2023
2,600,605 $40.07 2,351,642 $237,700,848 
10/01/2023 - 10/31/2023— $— — $237,700,848 
11/01/2023 - 11/30/2023614,729 $37.16 614,729 $214,854,687 
12/01/2023 - 12/31/2023— $— — $214,854,687 
Total7,180,068 $32.85 6,930,835 
____________________________________________
(1)249,233 shares purchased by us in 2023 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying Restricted Stock Units (“RSU” or “RSUs”) issued under the terms of award agreements granted under the Equity Plan.
(2)Our Stock Repurchase Program, which authorizes us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2024, permits us to repurchase our shares from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of our Credit Agreement and the indentures governing our Senior Notes. The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, is determined by certain authorized officers of the Company at their discretion and depends on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of our shares will be repurchased. During the year ended December 31, 2023, we repurchased and subsequently retired 6,930,835 shares of our common stock under the Stock Repurchase Program at a weighted-average share price of $32.89 for a total cost of $228.0 million, excluding excise taxes, commissions and fees.
Our payment of cash dividends to our stockholders and repurchases of our common stock are each subject to certain covenants under the terms of our Credit Agreement and Senior Notes. Based on our current performance, we do not anticipate that any of these covenants will limit our potential repurchases of our common stock or our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.
During the year ended December 31, 2023, we paid $71.6 million in dividends to our stockholders. Dividends paid reflects $0.60 per share during the year ended December 31, 2023. During 2023, our Board of Directors approved a 20 percent increase to our fixed dividend to $0.72 per share annually, to be paid in quarterly increments of $0.18 per share, beginning in the first quarter of 2024. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.
ITEM 6. [RESERVED]
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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 long-term vision and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our team executes this strategy by prioritizing safety, technological innovation, and stewardship of natural resources, all of which are integral to our corporate culture. Our near-term goals include continuing to return value to stockholders through our Stock Repurchase Program and fixed dividend payments, and by focusing on continued operational excellence.
Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas and in the Maverick Basin of South Texas that we believe are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. We seek to maximize returns and increase the value of our top-tier assets through disciplined capital spending, strategic acquisitions, and continued development and optimization of our existing assets. We believe that our high-quality assets facilitate a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining financial flexibility.
We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with 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 effectiveness of our ESG policies, programs and initiatives, monitors and responds to emerging issues, 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, environmental, health, and safety measures. Please refer to our Definitive Proxy Statement on Schedule 14A for the 2024 annual meeting of stockholders to be filed within 120 days from December 31, 2023, for additional discussion.
We are impacted by global commodity and financial markets that remain subject to heightened levels of uncertainty and volatility. While the rate of inflation in the United States has decreased since the beginning of the year and the average rate of inflation in 2023 was lower than it was in 2022, inflation continues to impact certain aspects of our business. Continued oil production curtailment agreements among OPEC+, instability in the Middle East, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, United States Federal Reserve monetary policy, shipping channel constraints and disruptions, and changes in global oil inventory in storage have driven commodity price volatility, contributed to instances of supply chain disruptions and fluctuations in interest rates, and could have further industry-specific impacts that may require us to adjust our business plan. Future impacts of these and other events on commodity and financial markets are inherently unpredictable. Despite continuing uncertainty, we expect to maximize the value of our high-quality asset base and sustain strong operational performance and financial stability. We remain focused on returning capital to stockholders through cash flow generation.
Outlook
We expect our total 2024 capital program to be between $1.16 billion and $1.20 billion, excluding acquisitions, which we expect to fund with cash flows from operations and cash on hand. We plan to focus our 2024 capital program on highly economic oil development projects in both our Midland Basin and South Texas assets, including the assets we acquired during 2023. We expect to repurchase additional shares of our outstanding common stock through our Stock Repurchase Program during 2024, under which $214.9 million remains available for repurchases through December 31, 2024, as of the filing of this report.
2023 Financial and Operational Highlights
During 2023, we increased the amount of capital we returned to our stockholders, compared with 2022, through repurchases of our outstanding common stock under our Stock Repurchase Program and our fixed quarterly dividend payments, and we expanded our Midland Basin asset position. During the year ended December 31, 2023, we repurchased and subsequently retired 6.9 million shares of our common stock at a cost of $228.0 million, excluding excise taxes, commissions, and fees; we paid dividends of $0.60 per share, an increase from $0.16 per share paid during the year ended December 31, 2022; and we announced a 20 percent increase to our fixed dividend to $0.72 per share annually, to be paid in quarterly increments of $0.18 per share, beginning in the first quarter of 2024. Additionally, we executed strategic acquisitions, exchanges, and leasing activity in the Midland Basin, enabling us to enhance
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our capital efficiency by blocking up acreage and maintaining high working interests. Please refer to Note 3 – Equity and Note 16 – Acquisitions in Part II, Item 8 of this report for additional discussion.
Financial and Operational Results. Average net daily equivalent production for the year ended December 31, 2023, increased five percent to 152.0 MBOE, compared with 145.1 MBOE for 2022 as a result of an increased number of completions in 2023 compared with 2022. The total increase consisted of a 20 percent increase from our South Texas assets, partially offset by a seven percent decrease from our Midland Basin assets. These changes were a result of the timing of well completions, and the timing of capital expenditures during 2022 and 2023.
Realized prices for oil, gas, and NGLs decreased 19 percent, 61 percent, and 35 percent, respectively, for the year ended December 31, 2023, compared with 2022, as a result of decreases in benchmark commodity prices during 2023. Total realized price per BOE decreased 33 percent for the year ended December 31, 2023, compared with 2022, resulting in a 29 percent decrease in oil, gas, and NGL production revenue, which was $2.4 billion for the year ended December 31, 2023, compared with $3.3 billion for 2022. Oil, gas, and NGL production expense of $10.16 per BOE for the year ended December 31, 2023, decreased 13 percent compared with 2022, primarily as a result of decreases in production tax expense per BOE, transportation costs per BOE, and ad valorem tax expense per BOE, partially offset by an increase in LOE per BOE.
We recorded a net derivative gain of $68.2 million for the year ended December 31, 2023, compared to a net derivative loss of $374.0 million for 2022. These amounts include a net derivative settlement gain of $26.9 million for the year ended December 31, 2023, and a net derivative settlement loss of $710.7 million for the year ended December 31, 2022.
Operational activities during the year ended December 31, 2023, resulted in the following:
Net cash provided by operating activities of $1.6 billion, compared with $1.7 billion for 2022.
Net income of $817.9 million, or $6.86 per diluted share, compared with net income of $1.1 billion, or $8.96 per diluted share for 2022.
Adjusted EBITDAX, a non-GAAP financial measure, of $1.7 billion, compared with $1.9 billion for 2022. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
Total estimated net proved reserves as of December 31, 2023, increased 13 percent from December 31, 2022, to 604.9 MMBOE, of which, 58 percent were liquids (oil and NGLs) and 56 percent were proved developed reserves. The increase primarily consisted of revisions of previous estimates of 113.9 MMBOE related to infill reserves in both our South Texas and Midland Basin programs, partially offset by 55.5 MMBOE of production during 2023. Our proved reserve life index increased to 10.9 years as of December 31, 2023, compared with 10.1 years as of December 31, 2022. 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 $6.3 billion as of December 31, 2023, compared with $10.0 billion as of December 31, 2022, which was a decrease of 37 percent year-over-year primarily driven by decreases in benchmark commodity prices during 2023. Please refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.
Operational Activities. During 2023, successful operational execution resulted in strong well performance in the RockStar and Sweetie Peck areas of our Midland Basin position, and allowed us to maximize capital efficiency. Our South Texas program benefited from continued successful delineation and development of the Austin Chalk formation in addition to sustained strong performance of our Eagle Ford shale wells. Our continued success in both our Midland Basin and South Texas programs is attributable to our top-tier assets and technical teams, and our commitment to geoscience, technology, and innovation.
In our Midland Basin program, we averaged three drilling rigs and one completion crew during 2023. We added a fourth drilling rig at the end of the third quarter to begin drilling on our newly acquired Klondike acreage. We drilled 54 gross (37 net) wells, completed 64 gross (54 net) wells, and acquired additional working interests in five net wells during 2023. Average net daily equivalent production volumes decreased year-over-year by seven percent to 75.4 MBOE. Costs incurred during 2023 totaled $768.1 million, or 62 percent of our total 2023 costs incurred. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin were focused primarily on developing the Spraberry and Wolfcamp formations.
In our South Texas program, we averaged two drilling rigs and one completion crew during 2023. We drilled 46 gross (46 net) wells and completed 38 gross (37 net) wells during 2023. Average net daily equivalent production volumes increased year-over-year by 20 percent to 76.7 MBOE. Costs incurred during 2023 totaled $423.5 million, or 34 percent of our total 2023 costs incurred. Drilling and completion activities in South Texas during 2023 were primarily focused on delineating and developing the Austin Chalk formation.
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The table below provides a summary of changes in our drilled but not completed well count and current year drilling, completion, and acquisition activity in our operated programs for the year ended December 31, 2023:
Midland Basin
South Texas (1)
Total
GrossNetGrossNetGrossNet
Wells drilled but not completed at December 31, 2022
49 40 29 28 78 69 
Wells drilled
54 37 46 46 100 83 
Wells completed
(64)(54)(38)(37)(102)(91)
Wells acquired (2)
— — — — 
Wells drilled but not completed at December 31, 2023
39 29 37 37 76 66 
____________________________________________
Note: Amounts may not calculate due to rounding.
(1)    As of December 31, 2022, and 2023, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan, eight of which were in the Eagle Ford shale.
(2)    Amount relates to additional working interests acquired in drilled but not completed wells during the year ended December 31, 2023.
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, 2023
(in millions)
Development costs$931.8 
Exploration costs172.6 
Acquisitions
Proved properties65.0 
Unproved properties65.6 
Total, including asset retirement obligations (1)
$1,235.0 
____________________________________________
(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, 2023:
Midland BasinSouth TexasTotal
Net production volumes:
Oil (MMBbl)17.5 6.3 23.8 
Gas (Bcf)59.8 72.6 132.4 
NGLs (MMBbl)— 9.6 9.7 
Equivalent (MMBOE)27.5 28.0 55.5 
Average net daily equivalent (MBOE per day)75.4 76.7 152.0 
Relative percentage50 %50 %100 %
____________________________________________
Note: Amounts may not calculate due to rounding.
Net equivalent production increased five percent for the year ended December 31, 2023, compared with 2022, comprised of a 20 percent increase from our South Texas assets, partially offset by a seven percent decrease from our Midland Basin assets. Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021 below for additional discussion of production.
Acquisition Activity. During 2023, we acquired approximately 20,000 net acres of oil and gas properties in Dawson and northern Martin counties, Texas. Additionally, in the Midland Basin, we added approximately 9,100 net acres through organic leasing activity, we completed an asset exchange, and we acquired additional working interests in certain wells. Please refer to Note 16 – Acquisitions in Part II, Item 8 of this report for additional discussion.
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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 net 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 effect of net derivative settlements, for the years ended December 31, 2023, 2022, and 2021:
For the Years Ended December 31,
202320222021
Oil (per Bbl):
Average NYMEX contract monthly price$77.62 $94.23 $67.92 
Realized price$76.28 $94.67 $67.72 
Effect of oil net derivative settlements
$(1.13)$(21.46)$(18.73)
Gas:
Average NYMEX monthly settle price (per MMBtu)$2.74 $6.64 $3.84 
Realized price (per Mcf)$2.48 $6.28 $4.85 
Effect of gas net derivative settlements (per Mcf)
$0.37 $(1.36)$(1.41)
NGLs (per Bbl):
Average OPIS price (1)
$27.71 $43.48 $36.65 
Realized price$23.02 $35.66 $33.67 
Effect of NGL net derivative settlements
$0.48 $(3.06)$(13.68)
____________________________________________
(1)    Effective January 1, 2023, average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% Ethane, 28% Propane, 6% Isobutane, 11% Normal Butane, and 13% Natural Gasoline. For periods prior to 2023, average OPIS price per barrel of NGL, historical or strip, assumed a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline. These product mixes represent the industry standard composite barrel for the respective periods presented and do not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
Oil prices in 2023 decreased compared with 2022 and increased compared with 2021. Gas and NGL prices in 2023 decreased compared with both 2022 and 2021. Given the uncertainty surrounding global financial markets, production output from OPEC+, global shipping channel constraints and disruptions, instability in the Middle East, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, changes in oil inventory in storage, and the potential impacts of these issues on global commodity and financial markets, we expect 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, which could include further inflation, supply chain disruptions, fluctuations in interest rates, and industry-specific impacts. In addition to supply and demand fundamentals, as global commodities, the prices for oil, gas, and NGLs are 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 areas 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 8, 2024, and December 31, 2023:
As of February 8, 2024As of December 31, 2023
NYMEX WTI oil (per Bbl)$74.58 $71.53 
NYMEX Henry Hub gas (per MMBtu)$2.63 $2.67 
OPIS NGLs (per Bbl)$28.29 $25.77 
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
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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 7 – 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.
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, 2023, and the preceding three quarters:
For the Three Months Ended
December 31,September 30,June 30,March 31,
2023202320232023