These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should therefore be considered in light of various factors, including those set forth in this Annual Report under "Item 1A. Risk Factors," in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this Annual Report. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this Annual Report, or if earlier, as of the date they were made. We do not intend to,

Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any obligationduty to update or revise any forward-looking statements, unless requiredall of which are expressly qualified by securities law.the statements in this section, to reflect events or circumstances after the date of this Annual Report.

Our strategy is to create long-term value through the efficient development and acquisition of high-margin properties, combined with prudent balance sheet management and sustainable environmental practices. We have operated in the Permian Basin since 2008, drilling almost 650700 operated horizontal wells. Our extensive operating experience in the basin underpins our ability to successfully develop our properties, assess acquisition opportunities and operate safely and efficiently, ultimately maximizing our rates of returnreturns on our development program.

Beginning inSince late 2019, we acquiredhave significantly expanded our Permian Basin leasehold, acquiring approximately 140,000 net acres of capital efficient, oil-weighted properties toin both the northMidland and westDelaware basins. We have increased the scale of our business, while maintaining a strong capital structure and exercising capital discipline to maximize cash flow. Our larger acreage footprint expands opportunities to create value by acquiring or leasing acreage adjacent to our properties, enabling the addition of new drilling locations or improving the economics of existing locations. We will continue to evaluate additional prospective formations to potentially add additional economic inventory to existing leasehold.

The year 2023 was significant for Vital Energy as we executed six acquisitions in the Permian Basin for an aggregate consideration of approximately $1.6 billion. These acquisitions (i) enhanced the scale and durability of our business, (ii) added approximately 52,000 BOE/d of production, at the time of announcement, 88,000 net acres and 280 gross oil-weighted locations and (iii) established a new core operating position in the Delaware Basin. We began developing this acreage in 2023 as we integrated the acquisitions and quickly transitionedexpect approximately 45% of our development activitiesbudget in 2024 to be allocated to these capital-efficient areas. We have significantly increased our oil production as a percentage of total production, improved our operating margin and, as a result, generated Free Cash Flow and significantly reduced debt in 2022.new assets.

Our results in 2022 were driven by our2023 development program in Howard County. Wedelivered strong returns as new wells exceeded production expectations and well costs declined throughout the year. Base production exceeded expectations by 10% as we focused on developing large packagesutilizing digital technologies and specialized teams to optimize artificial lift operations.

Throughout 2023, we took steps to strengthen our balance sheet and liquidity. We funded approximately 60% of wells at conservative spacing to maximize both current and future productivity. Combined with continued efficiency gains in our drilling and completions operations and sustained strength in oil prices, our development program generated high returns and Free Cash Flow. Additionally, we divested non-operated properties in Howard County for $110.0 million, generating additional cash flow and enhancing controlthe value of our capital investments.

We integratebelieve that we have incorporated robust environmental, social and governance ("ESG") practices into our operations, and describedescribed these practices in the three ESG and Climate Risk Reportssustainability reports we have published to date, covering operations which occurred in 2019, 2020 and 2021, respectively.since 2020. The disclosures in these three reports are generally aligned to the Sustainability Accounting Standards Board, the Task Force on Climate Related Financial Disclosures, the International Petroleum Industry Environmental Conservation Association, the American Petroleum Institute,multiple globally recognized standards and the American Exploration and Production Council frameworks. Our 2020

2025. Additionally, ourOur 2022 report expanded our emissions reduction targets to include a 2025 target for the percentage of recycled water to be used in our completions operations as well as a 2030 combined Scope 1 and Scope 2 greenhouse gas intensity target. Our 2023 report describes the meaningful progress we've made toward our environmental targets, with our 2025 goals for greenhouse gas (GHG) emissions and methane intensity already being achieved. Beyond our emissions reduction targets, we also disclosed climate-related scenario analysis, Scope 3 emissions estimates, and EEO-1 workforce diversity data. Furthermore, weWe also described our pilot program forexpanded continuous emissions monitoring andprogram, the certification of portions of our oil and natural gas production as responsibly sourced through the Project Canary TrustWellTMTrustWell™ Certification pilot project,and being the first operator in the Permian Basin to achieve this certification. Relatedly, wethe Project Canary TrustWell™ Certification Low Methane Rating. We remain committed to achieving our emission reduction targets and continue to incorporate environmental measures into our executive compensation program.

Our business strategy is both clear and sustainable.we believe it is sustainable even in a low carbon economy. We will continue to focus on safely developing our highest return oil-weighted inventory while opportunistically adding more high-margin acreage as we seek to improve our margins and profitability. We are highly selective in the projects that we consider,Our priority is to generate cash flow, further reduce leverage and we will continuemake progress to monitor the marketa return of cash program for strategic opportunities that we believe could be accretive and enhance shareholder value. These opportunities may take the form of acquisitions, divestitures, mergers, redemptions, equity or debt repurchases, or other similar transactions, any of which could result in the utilization of our Senior Secured Credit Facility and/or further accessing the capital markets.stockholders.

We currently focus our exploration, development and production efforts in one geographic operating area, the Permian Basin.

We are currently focusing our development activities on horizontal drilling targets in the Wolfcamp, Spraberry, and SpraberryBone Spring formations. As of December 31, 2022,2023, we had an average working interest of 73%72% in Vital-operated active productive wells and 67%66% in all wells in which Vital has an interest, and our leases are 98%92% held by production.

The following table sets forth certain information regarding productive wells as of December 31, 2022.2023. Wells are classified as oil or natural gas wells according to the predominant production stream. All but sixteen100 of our wells are classified as oil wells, all of which also produce liquids-rich natural gas and condensate when in a producing status. We also own royalty and overriding royalty interests in a small number of wells in which we do not own a working interest.

On December 31, 2022,2023, we had twocontracted four drilling rigs drilling horizontal wells and one completions crew. We anticipate running two drilling rigs and two completions crews in the first quarter of 2023. For the remainder of 2023,crews. Throughout 2024, we anticipate running twofour drilling rigs and one to two completions crew.crews. We willmay adjust our drilling rig count and/or completions crews to maximize efficiencies and cash flow. If we decrease our drilling rig count and/or completions crews, it willmay have a negative impact on our production. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capital resources" and Note 15 to our consolidated financial statements included elsewhere in this Annual Report for additional information.

The following table summarizes our drilling activity with respect to the number of wells completed and turned-in line for the periods presented. Gross wells reflect the sum of all operated wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.

The following table presentstables present information regarding our oil, NGL and natural gas sales volumes, sales revenues, average sales prices, and selected average costs and expenses per BOE sold for the periods presented and corresponding changes for such periods. Our reserves and sales volumes are reported in three streams: crude oil, NGL and natural gas. For additional information on price calculations, see the information in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

In this Annual Report, the information with respect to our estimated proved reserves has been prepared by Ryder Scott Company, L.P. ("Ryder Scott"), our independent reserve engineers, in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC")SEC applicable to the reporting dates presented.

The following table summarizes our total estimated net proved reserves presented on a three-stream basis, net acreage and producing wells as of the date presented, and net average daily production presented on a three-stream basis for the period presented.

Our estimated proved reserves as of December 31, 20222023 assume our ability to fund the capital costs necessary for their development and are affected by pricing assumptions. See Note 6 to our consolidated financial statements included elsewhere in this Annual Report for additional discussion of our Realized Prices. See "Item 1A. Risk Factors—Risks related to our business—Estimating reserves and future net cash flows involves uncertainties. Negative revisions to reserve estimates, decreases in oil, NGL and natural gas prices or increases in service costs, may lead to decreased earnings and increased losses or impairment of oil and natural gas properties." The following table sets forth additional information regarding our estimated proved reserves as of the dates presented:

Under SEC rules, proved reserves are those quantities of oil, NGL and natural gas that by analysis of geoscience and engineering data can be estimated with "reasonable certainty" to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. Reasonable certainty implies a high degree of confidence that the quantities of oil, NGL and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual

production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and Ryder Scott, our independent reserve engineers, employed reliable technologies that have been demonstrated to yield results with consistency and repeatability.

In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers ("SPE Reserves Auditing Standards") and guidelines established by the SEC, Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserve information as of December 31, 2023, 2022 2021 and 20202021 included in this Annual Report. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE Reserves Auditing Standards.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our technical team meets regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott's preparation of the year-end reserve estimates. The Ryder Scott reserve report is reviewed with representatives of Ryder Scott and our internal technical staff before dissemination of the information.

Our Director of Reserves serves as the technical person primarily responsible for overseeing the preparation of our reserves estimates. She has more than 20 years of practical experience, with 89 years of this experience being in the estimation and evaluation of reserves. She has a Bachelor of Science in Petroleum Engineering from the Missouri University of Science and Technology. Our Director of Reserves reports to our Chief FinancialOperating Officer. Reserve estimates are reviewed and approved by our senior engineering staff, other members of senior management and our technical staff, our audit committee and our Chief Executive Officer.

We limit the portion of reserves categorized as "proved undeveloped" or "PUD" in order to emphasize operations on our most economic investments, maximize operational flexibility and maintain conservative assurance that all PUD locations will be converted despite potential commodity price volatility.

Our proved undeveloped reserves decreasedincreased from 86,592 MBOE as of December 31, 2021 to 79,401 MBOE as of December 31, 2022.2022 to 117,862 MBOE as of December 31, 2023. We estimate that we incurred $337.9$430.9 million of costs to convert 23,72226,824 MBOE of proved undeveloped reserves from 4453 locations into proved developed reserves in 2022.2023. New proved undeveloped reserves of 30,29130,247 MBOE were added during the year from 345 Spraberry and 3241 Wolfcamp locations. 13,15526,215 MBOE of negative revisions consisted of 9,78526,122 MBOE of negative revisions due to 1645 proved undeveloped locations that were removed due to change in the development plan and 3,37093 MBOE of negative revisions from a decrease in previously estimated quantities due to performance, price and other changes. A final investment decision has been made on all 153212 proved undeveloped locations, and they are scheduled to be developed within five years from the date they were initially recorded.

Estimated total future development and abandonment costs related to the development of proved undeveloped reserves as shown in our December 31, 20222023 reserve report are $1.3$1.7 billion. Based on this report and our PUD booking methodology, the capital estimated to be spent to develop the proved undeveloped reserves from spud date through production is $529.0 million in 2023, $321.0$566.8 million in 2024, $222.7$335.4 million in 2025, $128.6$398.3 million in 2026, and $14.6$271.3 million in 2027.2027 and $83.6 million in 2028. Based on our anticipated cash flows and capital expenditures, as well as the availability of capital markets transactions, all of the proved undeveloped locations are expected to be drilled and completed from 20232024 to 2026.2028. Reserve calculations at any end-of-year period are representative of our development plans at that time. ChangesWhile we have made our final investment decision to develop our PUDs, it is possible that changes in circumstance, including commodity pricing, oilfield service costs, drilling and production results, technology, acreage position and availability and other economic and regulatory factors may lead to changes in our development plans.

The following table sets forth our developed and undeveloped acreage as of December 31, 2022,2023, including acreage HBP. A majority of our developed acreage is subject to liens securing our Senior Secured Credit Facility.

The following table sets forth our gross and net undeveloped acreage as of December 31, 20222023 that will expire over the next four years unless production is established within the spacing units covering the acreage or the lease is renewed, renegotiated or extended under continuous drilling provisions prior to the primary term expiration dates.

Of the total undeveloped acreage identified as potentially expiring over the next five years as of December 31, 2022, 1,881 net acres have associated PUD reserves included in our reserve report as of December 31, 2022, which we anticipate drilling to hold or renewing the associated leases. These PUD reserves represent 35% of our total PUD reserves as of December 31, 2022.

We market the majority of production from properties we operate for both our account and the account of the other working interest owners. We sell substantially all of our production under contracts ranging from terms of one month to multiple years, all at monthly calculated market prices. We typically sell production to a relatively limited number of customers, as is customary in the exploration, development and production business; however, we believe that our customer diversification affords us optionality in our sales destination.

We have firm field transportation agreements that enable us or the purchasers of our oil production to transport oil from our production area to major market hubs, including Midland, Texas and Crane, Texas. If not fulfilled, we are subject to transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for our business. Our firm field transportation agreements are related to transportation commitments extending into 2024 with Medallion Pipeline Company, LLC ("Medallion") under which Medallion provides firm transportation capacity from our established Reagan County and Glasscock County acreage for redelivery to various major market hubs. In addition, we have a transportation commitment with Gray Oak Pipeline, LLC extending into 2027 to transport 35,000 barrels of oil per day of our production, or the oil purchased from third parties, from Crane, Texas to the U.S. Gulf Coast. We believe these commitments enhance our ability to efficiently market our crude oil at various locations both in and out of the Permian Basin and give us access to multiple pricing points for the sale of our crude oil.

WeAs shown in the table above, we have committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. We expect to fulfill our delivery commitments for the next one to three years with production from our existing proved developed and proved undeveloped reserves, which we regularly monitor to ensure sufficient availability. In addition, we monitor our current production, our anticipated future production and our future development plans in order to meet our delivery commitments. If production volumes are not sufficient to meet these contractual delivery commitments, and we elect not to, or are unable to, purchase third-party production to fulfill these contractual delivery commitment, we may be subject to firm transportation payments on excess pipeline capacity and other contractual penalties. See Note 15 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our transportation commitments.

We believe that we could sell our production to numerous companies, so that the loss of any one of our major purchasers would not have a material adverse effect on our financial condition and results of operations solely by reason of such loss. For discussion on purchasers that individually accounted for 10% or more of each (i) oil, NGL and natural gas sales and (ii) sales of purchased oil in at least one of the years ended December 31, 2023, 2022 2021 and 2020,2021, see Note 14 to our consolidated financial statements included elsewhere in this Annual Report. See also "Item 1A. Risk Factors—Risks related to our business—The inability of our significant customers to meet their obligations to us may materially adversely affect our financial results."

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on

properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under oil and gas leases or net profit interests.

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil, NGL and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.5% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 87.5%.

Demand for oil and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Our operations are substantially affected by federal, state and local laws and regulations. In particular, the production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The State of Texas has regulations governing environmental and conservation matters, including provisions for the pooling of oil and natural gas properties, the permitting of allocation wells, the establishment of maximum allowable rates of production from oil and natural gas wells (including the proration of production to the market demand for oil, NGL and natural gas), the regulation of well spacing, the handling and disposal or discharge of waste materials and plugging and

The regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the natural gas industry are regularly considered by the current administration, Congress, the states, the Environmental Protection Agency ("EPA"), the Federal Energy Regulatory Commission ("FERC") and the courts. We cannot predict when or whether any such proposals may become effective, under the current or any future administration. For example, on January 26, 2024, President Biden announced a temporary pause on pending decisions on new exports of liquified natural gas to countries that the United States does not have free trade agreements with, pending Department of Energy review of the underlying analyses for authorizations. The pause is intended to provide time to integrate certain considerations, including potential energy cost increases for consumers and manufacturers and the latest assessment of the impact of GHG emissions, to ensure adequate guards against health risks are in place. This pause has the potential to adversely impact our industry and consequently could adversely affect our financial condition and results of operation.

Our oil and gas pipelines are subject to construction, installation, operation and safety regulation by the U.S. Department of Transportation ("DOT") and various other federal, state and local agencies. Congress has enacted several pipeline safety acts over the years. Currently, the Pipeline and Hazardous Materials Safety Administration ("PHMSA") under DOT administers pipeline safety requirements for natural gas and hazardous liquid pipelines. These regulations, among other things, address pipeline integrity management and pipeline operator qualification rules. In June 2016, Congress approved pipeline safety

legislation, the "Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016" (the “2016 PIPES Act”), which provides the PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquids pipeline facilities. In December 2020, the “Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020” (the “2020 PIPES Act”), was signed into law. The 2020 PIPES Act extends the PHMSA’s statutory mandate through 2023. It continues the legislative and regulatory mandates that were established in the 2016 PIPES Act and creates new mandates for PHMSA to abide by. Some of the key PHMSA regulations enacted in response to these pieces of legislation include final rules published on October 1, 2019, which took effect on July 1, 2020 to expand PHMSA’s integrity management requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside high consequence areas. The rules also extend reporting requirements to certain previously unregulated hazardous liquid gravity and rural gathering lines. Also, on June 7, 2021, the PHMSA issued an advisory bulletin reminding pipeline owners and operators that they must take several steps to eliminate hazardous leaks and minimize releases of natural gas by December 27, 2021 pursuant to directives set forth in the 2020 PIPES Act. In addition, on November 15, 2021, the PHMSA published a final rule extending reporting requirements to all onshore gas gathering operators and establishing a set of minimum safety requirements for certain gas gathering pipelines with large diameters and high operating pressures. Additional final rules were announced in 2022, including a final rule regarding the installation of rupture-mitigation valves, published on April 8, 2022. On August 1, 2023, the PHMSA issued editorial and technical corrections clarifying the regulations promulgated in its April 8, 2022 final rule, which also codified the results of judicial review of that final rule.

Further, on August 24, 2022, the PHMSA published a final rule strengthening integrity management requirements for onshore gas transmission lines, bolstering corrosion control standards and repair criteria, and imposing new requirements for inspections after extreme weather events. On April 24, 2023, the PHMSA published necessary technical corrections to ensure consistency within and the intended effect of the August 24, 2022 final rule. In addition, PHMSA published a proposed rule in May 2023 that would impose more stringent leak detection and repair obligations to address methane leaks on pipelines subject to PHMSA regulation.

Compliance with these existing regulations, as well as with future rules, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operation or financial position. In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders could have an adverse impact on our business, financial condition, results of operation and cash flow.

States are largely pre-empted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards, and many states have undertaken responsibility to enforce the federal standards. The RRC is the agency vested with intrastate natural gas pipeline regulatory and enforcement authority in Texas. The Commission's regulations adopt by reference the minimum federal safety standards for the transportation of natural gas. In addition, on December 17, 2019, the Commission adopted rules requiring that operators of gathering lines take "appropriate" actions to fix safety hazards.

Our operations are subject to numerous stringent federal, state and local statutes and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures, the noncompliance with which carries substantial administrative, civil and criminal penalties and may result in injunctive obligations to remediate noncompliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling, completion and production process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, seismically active areas and other protected areas, require some form of remedial action to prevent or mitigate pollution from current or former operations such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

Certain of these laws and regulations impose strict liability (i.e., no showing of "fault" is required) that, in some circumstances, may be joint and several. Public interest in the protection of the environment has tended to increase over time. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Changes in environmental laws and regulations occur frequently, and to the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and clean-up requirements, our business and prospects, as well as the oil and natural gas industry in general, could be materially adversely affected.

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes, and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (referred to as "CERCLA" or the "Superfund law") and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed "responsible parties." These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict, 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 certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. Despite the "petroleum exclusion" of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties. Finally, it is not uncommon for neighboring landowners and other third parties to file common law based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

The Oil Pollution Act of 1990 (the "OPA") is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on "responsible parties" for all containment and clean-up costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA's hazardous waste regulations. These wastes, instead, are regulated under RCRA's less stringent solid waste provisions, state laws or other federal laws. It is also possible that these wastes, which could include wastes currently generated during our operations, will be designated as "hazardous wastes" in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration and production wastes as "hazardous wastes." Also, in December 2016,While no changes have been made with respect to this exemption to date, from time to time, the EPA agreed in a consent decree

has reconsidered whether or not to review its regulation of oilmaintain the current exemption for exploration and gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste are not necessary at this time.production wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the Safe Drinking Water Act ("SDWA"), the OPA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers ("Corps").

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. The State of Texas also maintains groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs.

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in connection with on-site storage of significant quantities of oil.

We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete. Hydraulic fracturing is a necessary part of the completion process for our producing properties in Texas because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. While hydraulic fracturing is not required to maintain any of our leasehold acreage that is currently held by production from existing wells, it will be required in the future to develop the provided non-producing and proved undeveloped reserves associated with this acreage. Nearly all of our proved undeveloped reserves associated with future completion, recompletion and refracture stimulation projects require hydraulic fracturing.

Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We have and continue to follow standard industry practices and applicable legal requirements. These protective measures include setting surface casing at a depth sufficient to protect fresh water formations and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This well design is intended to eliminate a pathway for the fracturing fluid to contact any aquifers. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval. Injections rates and pressures are monitored in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Our hydraulic fracturing operations are designed to be shut down immediately if an abrupt change occurred to the injection pressure or annular pressure.

Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements. In accordance with Texas regulations, we report the constituents of the hydraulic fracturing fluids utilized in our well completions on FracFocus (www.fracfocus.org). Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it by recycling or by discharging into the approved disposal wells. We currently do not discharge water to the surface. Based upon results of testing the performance of recycled flowback/produced water in our fracking operations, we endeavor to maximize the utilization of recycled flowback/produced water via our owned and operated recycling facilities in Glasscock and Reagan County or via contractual arrangements with third parties in Howard County.

The federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including production facilities, salt water disposal facilities, and compressor stations, through the issuance of permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, strict and stringent regulations governing emissions of toxic air pollutants at specified sources; emissions from specific sources such as tanks,

We have incurred additional capital expenditures, which were not material, to comply with these new regulations as they come into effect. We may also be required to incur additional capital expenditures in the next few years for air pollution control equipment needed to comply with new air regulations, maintaining or obtaining operating permits addressing other air emission related issues, which may have a material adverse effect on our operations and has the potential to delay the development of oil and natural gas projects.

In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases ("GHGs"). In August 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”)IRA into law. The IRA contains billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced

The EPA has also finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry and almost one-half of the states have taken measures to reduce GHG emissions primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. Also, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and gas operations. In addition, several states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake "ambitious efforts" to limit the average global temperature and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016. Although the United States withdrew from the Paris Agreement, effective November 4, 2020, President Biden issued an Executive Order on January 20, 2021 to rejoin the Paris Agreement, which took effect on February 19, 2021. On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its GHG emissions by 50-52 percent below 2005 levels in 2030. In November 2021, in connection with the 26th Conference of the Parties in Glasgow, Scotland, the United States and other world leaders made further commitments to reduce GHGs, including reducing global methane emissions by at least 30% by 2030. At the 28th Conference of the Parties (“COP 28”) in December 2023, the parties signed onto an agreement to transition away from fossil

fuels in energy systems and increase renewable energy capacity, although no timeline for doing so was set. In relation, many state and local leaders have stated their intent to intensify efforts to support the international climate commitments.

Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil, NGL and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law.law and claiming that their operations have contributed to climate change. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. Moreover, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the Company's causation of or contribution to the asserted damage, or to other mitigating factors. Additionally, demand for hydrocarbons, and therefore our products and services, may be reduced by actions taken at the federal, state or local levels to restrict, ban or limit products that rely on oil and natural gas.

Certain of our operations are subject to applicable requirements of the federal Occupational Safety and Health Act, as amended ("OSHA") and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA's hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that certain information be provided to employees, state and local government authorities and citizens.

The Endangered Species Act ("ESA") was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service ("FWS") may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. If newly listed species, such as the lesser prairie chicken, are located in areas where we operate or previously unprotected species, such as the dunes sagebrush lizard, are designated as endangered or threatened, or if we were to have a portion of our leases designated as critical or suitable habitat, it could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas, which could adversely impact the value of our leases. For example, in July 2023, FWS proposed listing the dunes sagebrush lizard as an endangered species. At this time we cannot predict the ultimate impact any final listing of the dunes sagebrush lizard under the ESA may have on our operations.

We believe we are in substantial compliance with currently applicable environmental federal, state and local laws and regulations and that we hold all necessary, valid and up-to-date permits, registrations and other authorizations required under such laws and regulations or are in the process of obtaining such items. However, current regulatory requirements may

change, currently unforeseen incidents may occur or past non-compliance with laws or regulations may be discovered, and such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impacts of compliance. Although we have not experienced any material adverse effect from compliance with environmental requirements and believe that the current costs of compliance are appropriately reflected in our budget, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws and regulations or environmental remediation matters during the years ended December 31, 2023, 2022 2021 or 2020.2021.

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (the "CFTC"), the SEC, and federal regulators of financial institutions (the "Prudential Regulators") adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.

The CFTC, the SEC and the Prudential Regulators have issued many rules to implement the Dodd-Frank Act, including rules (the "Adopted Derivatives Rules") (i) requiring clearing of hedges, or swaps, that are subject to the Dodd-Frank Act (currently, only certain interest rate and credit default swaps, which we do not presently have) (the "Mandatory Clearing Rule"), and also establishing an "end user" exception to the Mandatory Clearing Rule (the "End User Exception"), (ii) setting forth collateral requirements in connection with swaps that are not cleared (the "Margin Rule") and also an exception to the Margin Rule for end users that are not financial end users (the "Non-Financial End User Exception") and (iii) imposing position limits on certain

We qualify for the End User Exception and will utilize it if the Mandatory Clearing Rule is expanded to cover swaps in which we participate. We qualify for the Non-Financial End User Exception and will not be required to post margin in connection with uncleared swaps under the Margin Rule. Our existing and anticipated hedging positions constitute "bona fide hedging positions" under the Position Limit Rule, and we intend to undertake the filing, recordkeeping and reporting necessary to utilize the bona fide hedging position exemption under the Position Limit Rule, so we do not expect to be directly affected by any such rules. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations (including laws and regulations giving the European Union financial authorities the power to write down amounts we may be owed on hedging agreements with counterparties subject to such laws and regulations and/or require that we accept equity interests in such counterparties in lieu of cash in satisfaction of such amounts, collectively the "Foreign Regulations"), which may apply to our transactions with counterparties subject to such Foreign Regulations (the "Foreign Counterparties") and the U.S. adopted law and rules (the "U.S. Resolution Stay Rules") clarifying similar rights of U.S. banking authorities with respect to banking institutions subject to their regulation.

As of December 31, 2022,2023, we employed 289326 full-time employees, 141161 of which were based in our field offices. The remaining (nearly one-half) of our employees possess technical and professional backgrounds, often holding advanced degrees. Our professional staff includes geoscientists, petroleum and chemical engineers, land women and men, accountants, computer and data scientists, financial analysts, lawyers, human resource specialists and many more. None of our employees are represented by labor unions or covered by collective bargaining agreements.

We believe that having a diverse workforce will help our organization better accomplish our mission. To increasemission as it provides us with an opportunity to obtain unique perspectives, experiences and ideas that can help our hiring of traditionally underrepresented personnel and women, Vital proactively sources open positions on job sites specifically focused on diversity. This allows us to gain candidates from underrepresented talent pools to help fill our positions.organization succeed. At the end of our fiscal year 2022,2023, our workforce consisted of:

Vital Energy exists to helpIt is important that our people reach their fullest potential. We believe this starts with making sure people arestay healthy and safe. Most importantly, weWe know that an engaged, healthy, safe and well-trained workforce helps us accomplish our strategic goals. By taking action every dayWe seek to achieve these goals through all-hands safety meetings, hazard hunts, stop-work authority and root-cause analysis, we are building belief in this culture every day.analysis.

Vital believes that it is important to empower our employees. To attract and retain exceptional talent,achieve this result, we provide our employees a comprehensive total rewards program, which includes a comprehensive compensation package and benefits offeringoffering. Our total rewards program is designed to attract and retain exceptional talent to achieve Vital’s business strategy. We seek to accomplish this strategy through three primary tenets that uphold our compensation model: 1) providing competitive base salaries and benefits, 2) rewarding for both short-term and long-term performance and 3) tying individual performance and company performance to pay. Our compensation package.model includes a regular review of the market as part of our efforts to remain competitive within our industry for all jobs. Such market benchmarking consists of regular review against our annually selected peer group and against the broader market. These regular market total reward reviews include updates and analyses on compensation, benefits, practices, and industry trends which support and align Vital’s human capital needs. In addition to

competitive salaries, we offer both shortshort-term and long termlong-term incentive programs,programs. Our goal is for our compensation model to tie all employees' pay not only to their individual performance, but also to certain components of the business’s performance. Vital’s performance measures are designed to reflect environmental, safety, operational and financial priorities, which we believe align with our stockholders' priorities. We believe paying for performance leads to better business results, stronger capabilities, improved employee productivity, higher employee retention levels, heightened motivation and overall employee satisfaction. Vital also provides a generous company-matched 401K contributions,401(k) plan with immediate vesting, flexible working schedules and many more employee-focused programs.

Attracting, retaining and developing our workforce is crucial to all aspects of Vital's overall success and it is central to our long-term strategy. We offer tuition reimbursement benefits for extended educational learning opportunities. Additionally, we have a robust training program for our Lease Operators and Field Technicians that allows for consistency in our processes and gives the leadership team clarity when considering field employees for promotional opportunities. Administration of this program is a joint effort between leadership on the Production team and the Learning and Development staff that allows us to intentionally train our employees with the goal of promoting from within for all promotions in the field. Vital prides itself on the ability to promote our great employees.

We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC, which are available to the public from commercial document retrieval services and at the SEC's website at http:https://www.sec.gov. Our common stock is listed and traded on the New York Stock Exchange under the symbol "VTLE."

We also make available on our website (http:(https://www.vitalenergy.com) all of the documents that we file with the SEC and amendments to those reports, including related exhibits and supplemental schedules, filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Our Code of Conduct and Business Ethics, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines, Policy Statement Regarding Related Party Transactions and the charters of our audit committee, compensation committee, finance committee, and nominating, corporate governance, environmental and social committee are also available on our website and in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our executive office. Information contained on our website is not incorporated by reference into this Annual Report. We intend to disclose on our website any amendments or waivers to our Code of Conduct and Business Ethics or Code of Ethics for Senior Financial Officers that are required to be disclosed pursuant to Item 5.05 of Form 8-K.

The prices we receive for our oil, NGL and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Commodity prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil, NGL and natural gas has been volatile and will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. See "Cautionary Statement Regarding Forward-Looking Statements” for a list of the factors that significantly impact our business and could impact our business in the future, including those specifically related to pricing and production.

Lower oil, NGL and natural gas prices have reduced, and may in the future continue to reduce, our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil, NGL and natural gas reserves as existing reserves are depleted. A further decrease in oil, NGL and natural gas prices could render uneconomic a large portion of our exploration, development and exploitation projects. This has already resulted in us having to make significant downward adjustments to our estimated proved reserves, and we may need to make further downward adjustments in the future. Furthermore, lower oil, NGL and natural gas prices could lead to a reduced borrowing base under our Senior Secured Credit Facility, which could trigger repayments under such facility. Also, lower oil, NGL and natural gas prices would likely cause a decline in our stock price.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.

Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In the past, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects. With the volatility in oil and natural gas prices, and the likelihood that interest rates will continue to rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. See "Item 1. Business—Regulation of the oil and natural gas industry—“Greenhouse gas” emissions" for further discussion.

The impact of the changing demand for oil and natural gas services and products, together with a change in investor sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected.

Our growth strategy will, in part, rely on acquisitions. We expect to grow in the future by expanding the exploitation and development of our existing assets, in addition to growing through targeted acquisitions in the Permian Basin or in other basins. Our ability to achieve the anticipated benefits of our acquisitions, including the 2023 Acquisitions, depends in part on whether we can integrate the businesses we acquire into our existing business in an effective and efficient manner. We may not be able to accomplish this integration process successfully. The successful acquisition of producing properties requires an assessment of several factors, including (i) recoverable reserves; (ii) future oil, NGL and natural gas prices and their applicable differentials; (iii) timing of development; (iv) capital and operating costs; and (v) potential environmental and other liabilities.

The successful disposition of assets requires an assessment of several factors, including historical operations, potential environmental and other liabilities and impact on our business. The accuracy of these assessments is inherently uncertain. Our assessment will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller or buyer may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire or sell assets on an "as is" basis. Even in those circumstances in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller or buyer will not be able to fulfill its contractual obligations. Problems with assets we acquire or dispose of could have a material adverse effect on our business, financial condition and results of operations. See "Item 1. Business—Regulation of the oil and natural gas industry—Hazardous substance and waste handling" for further discussion.

Some of the assumptions that we have made, such as the nature of assets to be acquired, may not be realized. There could also be undisclosed or unknown liabilities and unforeseen expenses associated with the acquisition that were not discovered in the due diligence review conducted by us prior to entering into the transaction agreements. Further, transaction costs and other non-recurring expenses incurred in connection with acquisitions may be greater than we initially anticipate.

We may use more cash and other financial resources on integration and implementation activities than we expect. We may not be able to successfully integrate the assets acquired into our existing operations or realize the expected economic benefits of the acquisition, including those acquired in the 2023 Acquisitions, which may have a material and adverse effect on our business, financial condition and results of operations.

In instances where a portion of the acreage we are acquiring is undeveloped, our plans, development schedule and production schedule associated with the acreage may fail to materialize. As a result, our investment in these areas may not be as economic as we anticipate, and we could incur material write-downs of unevaluated properties.

We have agreed to indemnify the sellers of assets in recent transactions, including in connection with the 2023 Acquisitions, against certain liabilities related to (i) production, processing and other imbalances, (ii) obligations to pay working interests and related payments, (iii) obligations for plugging and abandonment of applicable wells and (iv) certain other items. In addition, we have agreed to indemnify the buyer of assets for breaches of certain specified fundamental representations and warranties and failure to perform covenants or obligations contained in the respective transaction agreement, subject to certain limitations, and certain other indemnities.

Our indemnification obligations are, in some cases, subject to limitations, but the amount of our maximum exposure could be material. In some instances, our indemnification obligations are not subject to any limitations. Significant indemnification claims by such sellers or buyers could materially and adversely affect our business, financial condition and results of operations.

Historically, one of the key drivers of external capital investment in the unconventional resource industry has been growth in production and reserves. WithHowever, in light of recent trends such as historical levels of volatility in oil and natural gas prices and the likelihood that risingsustained high interest rates will increaseincreasing the cost of borrowing, capital efficiency and free cash flow from earnings have become the key drivers for energy companies, particularly shale producers.producers like ourselves. Such shifts in focus sometimes require changes in planning and resource management, which may not occur instantaneously. Any delay in responding to such changes in market sentiment or perception may result in the investment community having a negative sentiment regarding our business plan, potential profitability and our ability to operate in a manner deemed "efficient," which may have a negative impact on the price of our common stock.

The reserves data included in this Annual Report represent estimates. Reserves estimation is a subjective process of evaluating underground accumulations of oil, NGL and natural gas that cannot be measured in an exact manner. Reserves that are "proved reserves" are those estimated quantities of oil, NGL and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions and that relate to specific locations for which the extraction of hydrocarbons must have commenced or the operator must be reasonably certain will commence within a five-year period.    

The estimation process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including more rapid production declines than previously expected and many other factors beyond the control of the operator. Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates. Production declines may be rapid and irregular when compared to a well's initial production or initial estimates. In addition, the estimates of future net cash flows from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct.

Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decrease earnings or result in losses through higher depletion expense. These revisions, as well as revisions in the assumptions of future cash flows of these reserves, may also trigger impairment losses on certain properties, which would result in a non-cash charge to earnings. See Note 19 to our consolidated financial statementsUnaudited Supplementary Information included elsewhere in this Annual Report.

Producing oil, NGL and natural gas reservoirs are generally characterized by rapidly declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration, development and exploitation activities and/or continually acquire properties containing proved reserves, our proved reserves will continue

to decline as those reserves are produced. Our future oil, NGL and natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

In our area of operation, the Permian Basin has been characterized by periods when oil and/or natural gas production has surpassed local transportation capacity, resulting in substantial discounts to the price received for commodity prices quoted for WTI oil and Henry Hub natural gas. The expansion and construction of pipeline facilities are affected by the availability and costs of necessary equipment, supplies, labor and other services, as well as the length of time to complete such projects. In addition, these projects can be affected by changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil and natural gas and any materials or products used to expand or construct pipeline facilities, such as certain imported steel mill products that may be subject to a 25% tariff. All of these factors could negatively impact our realized oil prices, as well as actual results of our operations.

The marketability of our oil, NGL and natural gas production depends on a variety of factors, including the availability, proximity, capacity and quality constraints of transportation, compression, natural gas processing, fractionation, export terminals and storage facilities owned by us or third parties. We do not control third-party facilities and pipelines that may be

Insufficient production from our wells to support the construction of pipeline facilities by third parties or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil, NGL and natural gas and thereby cause a significant interruption in our operations. If we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or specifications or encounter production-related difficulties, we may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil, NGL and natural gas produced from our fields, could materially and adversely affect our financial condition and results of operations.

A portion of our oil, NGL and gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of extreme weather conditions, such as the freezing of wells and pipelines in the Permian Basin or a decision by the Electric Reliability Council of Texas ("ERCOT") to implement statewide electricity blackouts due to supply/demand imbalances in the electricity grid caused by the extreme cold weather, accidents, loss or unavailability of pipeline or gathering system access and capacity, field labor issues or strikes. Alternatively, we might voluntarily curtail production in response to market conditions, including low oil, NGL and gas prices. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners to maintain our leases.

In addition, we have entered into agreements with third partythird-party pipelines and purchasers that require us to deliver for transportation or sale minimum amounts of oil and natural gas. Pursuant to these agreements, we must deliver specific amounts of oil or gas over the next eightsix years. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements or we may have to purchase oil from third parties to fulfill our delivery obligations. This could adversely impact our cash flows, profit margins and net income.

Although our management team has established certain potential drilling locations as a part of our long-range development plan, our ability to drill and develop these locations depends on a number of uncertainties, including oil, NGL and natural gas prices, the availability and cost of capital, drilling and production costs, our ability to leverage our data and development experience, the availability of drilling services and equipment, lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors. Because of these uncertainties, we do not know if the numerous potential drilling locations we have currently identified will ever be drilled or if we will be able to produce oil, NGL or natural gas from these or any other potential drilling locations. As such, it is likely that our actual drilling activities, especially in the long term, could materially differ from those presently anticipated. See "Item 1. Business—Regulation of the oil and natural gas industry—Water and other waste discharges and spills" for further discussion regarding the issuance of permits that can affect our ability to drill wells.

Our oil, NGL and natural gas production sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Certain purchasers individually account for 10% or more of our oil, NGL and natural gas sales in a given year. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. See Notes 2 and 14 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our accounts receivable and credit risk, respectively.

The demand for and availability of qualified and experienced personnel to drill and complete wells and conduct field operations, including, but not limited to, frac crews, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, NGL and natural gas prices, causing periodic shortages. From time to time, there have also been shortages of drilling and workover rigs, pipe, sand, water and equipment as demand for such items has increased along with the number of wells being drilled. We have committed in the past, and we may in the future commit, to drilling rig contracts with various third parties that contain penalties for early terminations. These penalties could negatively impact our financial statements upon contract termination. Shortages in rigs, crews, supplies and equipment, as well as related fees could result in delays or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Epidemics, outbreaks or other public health events that are outside of our control could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or other communicable disease, or any other public health crisis, such as COVID-19, pandemic and responses.

We are heavily dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such systems or programs were to fail or we were subject to cyberspace breaches or attacks, possible consequences include our loss of communication links,links; an inability to find, produce, process and sell oil, NGL and natural gas andgas; an inability to automatically process commercial transactions or

engage in similar automated or computerized business activities.activities; data loss or corruption; misdirected wire transfers; an inability to maintain our books or records; and an inability to prevent environmental damage. Any such consequence could have a material adverse effect on our business.business, reputation and financial condition.

Our revenues and our profitability are heavily dependent on the prices we receive from our sales of oil and natural gas. Oil prices are particularly sensitive to actual and perceived threats to global political stability and to changes in production from OPECOPEC+ member states. Russia's activities in Ukraine have caused, and could intensify,Specifically, volatility in global oil and gas prices may be created as a result of the ongoing war between Russia and increasesUkraine, continued hostilities in oil productionthe Middle East between Israel and Hamas and the potential impact to global shipping caused by Russia to finance its activitiesHouthi rebels in Ukraine or to destabilize global oil and gas pricesYemen. Such volatility could reduce the priceprices we receive from our sales of oil and natural gas and adversely affect our profitability.

Effective succession planning is important to our long-term success. Failure to ensure effective transfer of knowledge and smooth transitions involving senior management and technical personnel could hinder our strategic planning and execution and could have a material adverse impact on our operations. We do not maintain any key-man or similar insurance for any officer or other employee.

The unconventional oil and natural gas industry has seen a large increase in new technologies to enhance all aspects of operations. This has arguably accelerated as a result of the extended downturn in commodity prices, forcing companies to find new ways to more efficiently produce oil and natural gas. While such technologies can and often ultimately enhance operations, production and profitability, the utilization of such technologies, especially in their early phases, may result in unforeseen consequences and operational issues, resulting in negative consequences.

Our producing properties are geographically concentrated in the Permian Basin. As of December 31, 2022,2023, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional transportation constraints, supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing and storage capacity constraints, market limitations, water shortages, interruption of the processing or transportation of oil or natural gas, as well as impacts from extreme weather or other natural disasters impacting the Permian Basin, such as the freezing of wells and pipelines in the Permian Basin or a decision by ERCOT to implement statewide electricity blackouts due to supply/demand imbalances in the electricity grid caused by the extreme cold weather.

We could be impacted by the outcome of pending litigation as well as unexpected litigation or proceedings. Certain litigation claims may not be covered under our insurance policies, or our insurance carriers may seek to deny coverage. Because we cannot accurately predict the outcome of any action, it is possible that, as a result of pending and/or unexpected litigation, we will be subject to adverse judgments or settlements that could significantly reduce our earnings or result in losses. See "Item 3. Legal Proceedings" for a description of our pending litigation.litigation, as well as "Item 1. Business—Regulation of the oil and natural gas industry—“Greenhouse gas” emissions" for a discussion about climate change litigation brought against the oil and natural gas industry.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil, NGL and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil, NGL and natural gas, including the possibility of (i) environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination, (ii) abnormally pressured formations, (iii) mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse, (iv) fires, explosions and ruptures of pipelines, (v) disagreements regarding the royalty due to our royalty owners, (vi) personal injuries and death, (vii) electronic system disruption and cyber-securitycybersecurity threats, (viii) natural disasters and (ix) terrorist attacks targeting oil, NGL and natural gas related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The impact of litigation as well as the occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

We have developed, and willexpect to continue to develop, targets related to ESG initiatives, including our emissions reduction targets and strategy. Public statements related to these initiatives reflect our current plans, and are based on hypothetical expectations and assumptions and are not a guarantee the targets will be achieved or achieved on the stated timeline. Our efforts to research, establish, accomplish, and accurately report on these targets may expose us to operational, reputational, financial, legal, and other risks. Our ability to achieve our stated targets, including emissions reductions, is subject to numerous factors and conditions, somemany of which are outside of our control. Moreover, we may seek to enter into various contractual arrangements, including the purchase of various environmental credits or offsets, in an effort to meet any targets or goals that we may set. While we would generally seek to procure such offsets from verified registries, we cannot guarantee that sufficient quality offsets will be available or ultimately achieve the emission reductions that such offsets or credits may

Our business may face increased scrutiny from investors and other stakeholders related to our ESG initiatives, including our publicly announced targets, as well as our methodologies and timelines for pursuing those initiatives. If our ESG initiatives do not meet evolving investor or other stakeholder expectations and standards, our reputation, ability to attract or retain employees, and attractiveness as an investment or business partner may be negatively impacted. Similarly, our failure to achieve our announced targets within the announced timelines, or at all or comply with ethical, environmental, or other standards, including reporting standards, may adversely impact our business or reputation, or may expose us to government enforcement actions or private litigation.

Our exploration, development, marketing, transportation and acquisition activities require substantial capital expenditures.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, NGL and natural gas, we enter into commodity derivative instrument contracts for a portion of our oil, NGL and natural gas production, including puts, swaps, collars, basis swaps and, in the past, call spreads. In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and they are included on our consolidated balance sheet as assets or liabilities and in our consolidated statements of operations as gain (loss) on derivatives. Gain (loss) on derivatives are included in our cash flows from operating activities. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments, including a decrease in earnings if the price of commodities increases above the price of hedges that we have in place. As our current hedges expire, there is a significant uncertainty that we will be able to put new hedges in place that satisfy our hedge philosophy.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when (i) production is less than the volume covered by the commodity derivative instruments; (ii) the counter-party to the commodity derivative instrument defaults on its contractual obligations; (iii) there is an increase in the differential between the underlying price in

the derivative instrument and actual prices received; or (iv) there are issues with regard to legal enforceability of such instruments.

In addition, government regulation may adversely impact our ability to hedge these risks.

For additional information regarding our hedging activities, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes 11 and 12 to our consolidated financial statements included elsewhere in this Annual Report.

As of December 31, 2022,2023, we had total long-term indebtedness of $1.12$1.63 billion. We may be able to incur substantial additional indebtedness, including secured indebtedness, in the future. The restrictions on the incurrence of additional indebtedness contained in the indentures governing our senior unsecured notes and in our Senior Secured Credit Facility are subject to a number of significant qualifications and exceptions, and under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we face would increase and may make it more difficult to satisfy our existing financial obligations. In addition, the restrictions on the incurrence of additional indebtedness contained in the indentures governing the senior unsecured notes apply only to debt that constitutes indebtedness under the indentures. However, such increased debt may reduce the amount of outstanding debt allowed under the Senior Secured Credit Facility.

We require continued access to capital. Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce our cash flow and/or liquidity available for drilling and place us at a competitive disadvantage. Disruptions and volatility in the global financial markets and a downgrade in our credit ratings could negatively impact our costs of capital and ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt. A significant reduction in our cash

Our earnings are exposed to interest rate risk associated with borrowings under our Senior Secured Credit Facility. The terms of our Senior Secured Credit Facility provide for interest on borrowings at a floating rate equal to an adjusted base rate tied to Term SOFR, a forward-looking term rate that is based on the secure overnight financing rate determined by the Federal Reserve bank of New York. SOFR is a volume weighted measure of the cost of overnight borrowings collateralized by treasury securities and can fluctuate based on multiple factors. In response to inflation, the U.S. Federal Reserve increased rates several times in 2022 in an effort to curb inflationary pressure on the cost of goods and signaled that additional interest rate increases should be expected in 2023. On December 14, 2022, it raised interest rates by 0.50%, representingservices across the seventh increase in interest rates during 2022 to date. Raising or lowering of interest rates byUnited States. While the U.S. Federal Reserve generally causes an increase or decrease, respectively,indicated in SOFR and other floating interest rate benchmarks. As such, ifDecember 2023 that it may reduce benchmark interest rates increase, so willin 2024, the continuation of rates at current levels could raise the cost of capital and depress economic growth, either of which could negatively impact our interest costs.financial or operational results of our business. From time to time, we use interest rate swaps to reduce interest rate exposure with respect to our fixed and/or floating rate debt. If interest rates were to increase, so willwould our interest costs, which may have a material adverse effect on our results of operations and financial condition.