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 stakeholderlong-term value through the efficient development and acquisition of our Permian Basin acreage.high-margin properties, combined with prudent balance sheet management and sustainable environmental practices. We do this by optimizing our assets, managing our risk and seeking to acquire additional high-margin inventory.

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) conservative well-spacing that seeksadded 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 expect approximately 45% of our development budget in 2024 to balance location countbe allocated to these new assets.

Our 2023 development program delivered strong returns as new wells exceeded production expectations and well productivitycosts declined throughout the year. Base production exceeded expectations by 10% as we focused on utilizing digital technologies and (iii) strategic investments in midstream infrastructure. Keyspecialized teams to optimize artificial lift operations.

Throughout 2023, we took steps to strengthen our low costs are (i)balance sheet and liquidity. We funded approximately 60% of the contiguous naturevalue of our acreage which enables us to drill longer more capital efficient lateral wells, (ii) our high working interests and extensive interestsacquisitions in leases held by production that provide us the operational control necessary to enhance our returns through operational and cost efficiencies and (iii) the infrastructure in place in both our legacy acreage and more recently acquired acreage either owned by us or built around us by third-parties.

We believe that we have incorporated robust environmental, social and governance ("ESG") practices into our operations, and described these practices in the proceeds therefromsustainability reports we have published since 2020. The disclosures in these reports are generally aligned to among other things, repaymultiple globally recognized standards and communicate our then outstanding seniorambitious emissions reductions targets and outline goals for reducing both greenhouse gas intensity and methane emissions, as well as eliminating routine flaring by

unsecured notes. As2025. Our 2022 report expanded our emissions reduction targets to include a result,2025 target for the maturity dates onpercentage of recycled water to be used in our long-term debt were extendedcompletions 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. We also described our expanded continuous emissions monitoring program, the certification of portions of our oil and natural gas production as responsibly sourced through the Project Canary TrustWell™ Certification and being the first operator to 2025achieve the Project Canary TrustWell™ Certification Low Methane Rating. We remain committed to achieving our emission reduction targets and 2028.continue to incorporate environmental measures into our executive compensation program.

Our business strategy is clear and we believe it is sustainable even in a low carbon economy. We believe that this extension provides us with financial flexibility to execute on our strategy. Additionally, we have historically hedged our production to protect cash flows and diminish the effects of commodity price fluctuations. During 2020, our hedging program provided us with approximately $234 million of cash flow. In addition to the hedges entered into in 2020, we will continue to seek hedging opportunitiesfocus on a multi-year basis to further protectsafely developing our cash flows.

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

The following table sets forth certain information regarding productive wells as of December 31, 2020.2023. Wells are classified as oil or natural gas wells according to the predominant production stream. All but three100 of our wells are classified as oil wells, all of which also produce liquids-rich natural gas and condensate. Wells are classified as oil or natural gas wells according to the predominant production stream.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, 2020,2023, we had contracted four drilling rigs drilling horizontal wells and two completions crews. Throughout 2024, we anticipate running four drilling rigs and one to two completions crews. We may adjust our drilling rig drilling horizontal wells. We anticipate utilizing two horizontal drilling rigs during 2021. We do not anticipate utilizing any vertical drilling rigs in 2021.count and/or completions crews to maximize efficiencies and cash flow. If we decrease our drilling rig count and/or completioncompletions 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—ObligationsLiquidity and commitments"capital resources" and Note 16.b15 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.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, 20202023 assume our ability to fund the capital costs necessary for their development and are affected by pricing assumptions. See Note 6.a6 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

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, 2020, 20192023, 2022 and 20182021 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 Vice PresidentDirector of Planning and Business Development isReserves serves as the technical person primarily responsible for overseeing the preparation of our reservereserves estimates. HeShe has more than 3020 years of practical experience, with 299 years of this experience being in the estimation and evaluation of reserves. HeShe has a Bachelors and MastersBachelor of Science in Petroleum Engineering from Texas A&M University.the Missouri University of Science and Technology. Our Vice PresidentDirector of Planning and Business DevelopmentReserves 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.

In order to maximize operational flexibility through the commodity price declines, weWe limit the portion of reserves categorized as "proved undeveloped" or "PUD" to approximately two years of activity. This is shorter than the five years allowed by SEC rules, but allows usin 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 49,74979,401 MBOE as of December 31, 20192022 to 24,642117,862 MBOE as of December 31, 2020.2023. We estimate that we incurred $230$430.9 million of costs to convert 23,49126,824 MBOE of proved undeveloped reserves from 4253 locations into proved developed reserves in 2020.2023. New proved undeveloped reserves of 9,75330,247 MBOE were added during the year from (i) 5,808 MBOE from 75 Spraberry and 10 new41 Wolfcamp locations along with (ii) 3,945 MBOE from additional acreage acquired under proved locations in Howard County. 11,369locations. 26,215 MBOE of negative revisions consisted of (i) 8,24526,122 MBOE of negative revisions due to 45 proved undeveloped locations that were removed due to year-end pricingchange in the development plan and (ii) 3,12493 MBOE of negative revisions from a decrease in previously estimated quantities due to performance, price and price.other changes. A final investment decision has been made on all 61212 proved undeveloped locations, and they are scheduled to be drilled and completed in 2021 to 2023.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, 20202023 reserve report are $279.5 million.$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 $186.4 million in 2021, $84.1 million in 2022, $4.1 million in 2023, $0.9$566.8 million in 2024, and $0.2$335.4 million in 2025.2025, $398.3 million in 2026, $271.3 million in 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 in 2021from 2024 to 2023.2028. 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 certain information regarding our developed and undeveloped acreage as of December 31, 2020,2023, 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, 20202023 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 threefive years as of December 31, 2020, 3,6422023, 4,859 net acres have associated PUD reserves onincluded in our reserve report as of December 31, 2020,2023, which we anticipate drilling to hold or renewing the associated leases. These PUD reserves represent 39%7% of our total PUD reserves as of December 31, 2020.2023.

Of the total undeveloped acreage identified as potentially expiring over the next fourfive years as of December 31,2019, 3,79931, 2022, 1,881 net acres had associated PUD reserves on our reserve report as of December 31, 2019. All2022. Of the total undeveloped acreage potentially expiring in 2020 was retained by either drilling2023, there were no associated net acres that were not drilled to hold or renewing leases.otherwise retained.

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 movetransport oil from our production area to major market hubs, including Colorado City, Texas; Midland, Texas;Texas and Crane, Texas. If not fulfilled, we are subject to firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for our business. A portion of our commitmentsOur firm field transportation agreements are related to transportation commitments

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 16.c15 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, 2020, 20192023, 2022 and 2018,2021, see Note 1514 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 disposingdisposal or discharge of waste materials and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil, NGL and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, NGL and natural gas within its jurisdiction. Texas further regulates drilling and operating

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.

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 new 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. OnIn 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, PHMSA published final ruleswhich took effect on July 1, 2020 to expand itsPHMSA’s integrity management requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside high consequence areas. The rules once effective, 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 rulemakings are anticipated,final rules were announced in 2022, including rulemakings to adjust repair criteriaa 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 inspectionus to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of gas pipelines following extreme events,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 to extend regulatory safety requirements to certain gas gathering lines.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 Railroad Commission of TexasRRC 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, and 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 surface waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A "responsible party" includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities, but these liability limits may not apply if: a spill is caused by a party's gross negligence or willful misconduct; the spill resulted from a violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state statutes that impose liabilities with respect to oil spills.

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 to review its regulation of oil and gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste

arehas reconsidered whether or not necessary at this time.to maintain the current exemption for exploration and 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 maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

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

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 fracingfracking 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.sources; emissions from specific sources such as tanks, engines, dehydration units, and heaters; and maintenance requirements for such equipment. Also, on May 12,June 3, 2016, the EPA issuedpublished a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis,clarified the term “adjacent” and defined when sources are required to be deemed a major source, therebyaggregated. The consequences of these requirements are that smaller sites may need to be combined, triggering more stringent air permitting processes and requirements. These laws andCurrent air permitting regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtainemissions. Once obtained these air permits require compliance with strict and strictly comply with stringent air permit requirements orand utilize specific equipment or technologies to control and monitor emissions of certain pollutants. The need to obtain air permits has the potentialand emission control equipment prior to delayconstruction requires timely planning to ensure that the development of oil and natural gas projects.projects is not delayed.

We have incurred additional capital expenditures, which were not material, to ensure compliancecomply 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 in connectionneeded 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. Obtaining permits alsooperations and has the potential to delay the development of oil and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

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 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 biofuels and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell. In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA amends the Clean Air Act to impose a fee on the emission of methane that exceeds an applicable waste emissions threshold from sources required to report their GHG emissions to the EPA, including those sources in the offshore and onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA. In August 2023, the EPA also proposed revisions to the GHG reporting program, which propose to expand reporting to include new sources of emissions and revise the emissions factors used to calculate emissions reported to EPA under the program. These changes, if finalized, could increase the amount of GHG emissions we report and accordingly increase the amount we owe under the methane emission charge.

The EPA has also finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry and Congress has, from time to time, considered adopting legislation to reduce emissions. Almostalmost one-half of the states have already 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, someseveral 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

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 commitments set forth in the international accord.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.

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. We believe that we have measures, practices and policies in place to ensure that our operations are in substantial compliance with applicable federal OSHA and state occupational health and safety requirements.

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.

In summary, weWe believe we are in substantial compliance with currently applicable environmental federal, state and local laws and regulations.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, 2020, 20192023, 2022 or 2018.

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 itthe Dodd-Frank Act (currently, only certain interest rate and credit default swaps, which we do not presently havehave) (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 futures contracts, including the NYMEX "Henry Hub" gas contract and "Light Sweet Crude" oil contract, and economically equivalent swaps (the "Position Limit Rule"). The Position Limit Rule is scheduled to taketook effect March 15, 2021 withand the position limits, other than those for economically equivalent swaps provided for in the Position Limit Rule, takingtook effect on January 1, 2022.2022; the position limits for economically equivalent swaps took effect on January 1, 2023. The Position Limit Rule provides an exemption from the position limits for swaps that constitute "bona fide hedging positions" within the definition of such term under the Position Limit Rule, subject to the party claiming the exemption complying with the applicable filing, recordkeeping and reporting requirements of the Position Limit Rule.

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, weparticipate. 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, and ourRule. 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, when it becomes effective, 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, 2020,2023, we employed 257326 full-time employees, 123161 of which were based in our field offices. We also employed a total of 24 contract personnel who assist our full-time employees with respect to specific tasks and perform various field and other services. Nearly one-halfThe 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, and human resource specialists. Wespecialists and many more. None of our employees are not a party to anyrepresented by labor unions or covered by collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.agreements.

We believe that having a diverse workforce will help our organization better accomplish our mission. We are proudmission as it provides us with an opportunity to obtain unique perspectives, experiences and ideas that nearly 30% ofcan help our leadership positions are filled by women. To increase our hiring of traditionally underrepresented groups and women, Laredo 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 2020,2023, our workforce identified as or consisted of:

It is important that our people stay healthy and safe. We know that an engaged, healthy, safe and well-trained workforce is key to our world-class culture and helps us accomplish our strategic goals. Safety is a core part of Laredo's culture, and we pride ourselves on our commitmentWe seek to conduct all operations in a safe manner. We are always striving for an incident free workplace and we are proud of our record of safe operations. Our safety best practices include: annual job training, pre-jobachieve these goals through all-hands safety meetings, on-site contractor management and safety personnel, hazard hunts, bi-annual external safety audits, stop workstop-work authority after-action review and root causeroot-cause 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 offering and competitive compensation package. We recognize that by offering relevant and innovativeoffering. Our total rewards programsprogram 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 employees, we sendcompensation 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 model includes a message that we are listeningregular review of the market as part of our efforts to their needsremain competitive within our industry for all jobs. Such market benchmarking consists of regular review against our annually selected peer group and promoting flexibility as well as sound healthagainst the broader market. These regular market total reward reviews include updates and wellness opportunities.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. Demonstrating our commitment to our employees' health

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 "LPI."VTLE."

We also make available on our website (http:(https://www.laredopetro.com)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 Forfor 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, and 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. These factors include the following:

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 weinterest rates will be successfulcontinue to rise in optimizing our spacing, drillingthe near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and completions techniques in order to maximize our rate of return,free cash flow from operationsearnings 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 shareholder value.natural gas industry—“Greenhouse gas” emissions" for further discussion.

As we accumulateThe impact of the changing demand for oil and process geologicalnatural gas services and production data, we attempt to createproducts, together with a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. However, due to many factors, including some beyond our control, there is no guarantee that we will be able to find the optimal plan or one that provides continuous improvement. If we are unable to design and implement an effective spacing, drilling and completions strategy, itchange in investor sentiment, may have a material adverse effect on our productionbusiness, financial condition, results financial performance,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 and net asset value.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:

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.