EDGAR 10-K Filing

Company CIK: 1528129
Filing Year: 2025
Filename: 1528129_10-K_2025_0001528129-25-000045.json

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ITEM 1. BUSINESS
Item 1. Business
Except where the context indicates otherwise, amounts, numbers, dollars and percentages presented in this Annual Report are rounded and therefore approximate. Unless the context otherwise requires, references in this Annual Report to "Vital," the "Company," "we," "our," "us," or similar terms refer to Vital Energy, Inc. and its subsidiaries at the applicable time, including former subsidiaries and predecessor companies, as applicable.
Overview
Vital Energy, Inc., together with its wholly-owned subsidiaries, is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties in the Permian Basin of West Texas. The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of December 31, 2024, we had assembled 286,796 largely contiguous net acres in the Permian Basin, most of which is prospective for multi-zone development in Crane, Glasscock, Howard, Midland, Reagan, and Upton counties in the Midland Basin and Pecos, Reeves, and Ward counties in the Delaware Basin. We have identified one operating segment: exploration and production.
Business strategy and 2024 operational highlights
Our strategy is to create long-term value for our shareholders through the efficient development and acquisition of high-margin properties, combined with prudent balance sheet management and sensible emissions targets. We have operated in the Permian Basin since 2008, drilling 760 operated horizontal wells. Our extensive operating experience in the basin underpins our ability to successfully develop our properties, assess attractive acquisition opportunities and operate safely and efficiently, ultimately maximizing returns on our development program.
Since late 2019, we have significantly expanded our Permian Basin leasehold, acquiring approximately 165,000 net acres of capital efficient, oil-weighted properties in both the Midland and Delaware 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 prospective formations to add additional economic inventory to our existing leasehold.
We executed large, high-value acquisitions in 2023 and 2024, including our single largest transaction in the Company’s public history with the acquisition of the assets of Point Energy Partners. Successful integration of these assets enhanced the scale and durability of our business, driving total production growth of 39%, revenue growth of 27% and increased estimated proved reserves of 12% in 2024.
We have incorporated appropriate emissions targets into our operations. By 2024, we achieved our 2025 targets for greenhouse gas intensity, methane emissions and water recycling and established a combined Scope 1 and 2 emissions target for 2030 that is 62% below our 2019 baseline.
Throughout 2024, we strengthened our balance sheet and liquidity. We issued $1 billion of new senior unsecured notes due 2032, utilizing proceeds to redeem near-term maturities, resulting in no term-debt maturities until 2029. The lenders party to our senior secured credit facility increased their elected commitments by $250 million to $1.5 billion and we have hedged approximately 75% of our anticipated 2025 oil production at $75 per barrel WTI.
We believe our business strategy is clear and sustainable. We will continue to focus on safely developing our highest return oil-weighted inventory and optimizing all of our properties to improve margins and profitability. Our priorities are to generate cash flow, reduce leverage and build long-term value for our shareholders.
Operating areas
We currently focus our exploration, development and production efforts in one geographic operating area, the Permian Basin.
Well data
We are currently focusing our development activities on horizontal drilling targets in the Wolfcamp, Spraberry, and Bone Spring formations. As of December 31, 2024, we had an average working interest of 74% in Vital-operated active productive wells and 69% in all wells in which Vital Energy has an interest, and our leases are 91% held by production.
The following table sets forth certain information regarding productive wells as of December 31, 2024. Wells are classified as oil or natural gas wells according to the predominant production stream. All but 101 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.
Total productive wells Average WI %
Gross Net
Vertical Horizontal Total Total
Permian-Midland Basin:
Operated 941 991 1,932 1,410 73 %
Non-operated 157 66 223 56 25 %
Permian-Delaware Basin:
Operated 27 445 472 378 80 %
Non-operated 1 51 52 7 13 %
Total 1,126 1,553 2,679 1,851 69 %
Drilling activity
As of December 31, 2024, we had five drilling rigs and two completions crews contracted to drill and complete horizontal wells in the Permian Basin. Throughout 2025, we anticipate running four to six drilling rigs and one to three completions crews. We may 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 may 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 these gross wells.
Years ended December 31,
2024 2023 2022
Gross Net Gross Net Gross Net
Development wells:
Productive 87 73.4 62 58.8 49 47.1
Dry - - - - - -
Total development wells 87 73.4 62 58.8 49 47.1
Exploratory wells:
Productive - - - - - -
Dry - - - - - -
Total exploratory wells - - - - - -
Sales volumes, revenues, prices and expenses history
The following tables 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."
Midland Basin Delaware Basin(2)
Total
Sales volumes:
Year ended December 31, 2022:
Oil (MBbl) 13,838 - 13,838
NGL (MBbl) 8,028 - 8,028
Natural gas (MMcf) 49,259 - 49,259
Total oil equivalents (MBOE)(1)
30,076 30,076
Year ended December 31, 2023:
Oil (MBbl) 15,908 986 16,894
NGL (MBbl) 8,891 237 9,128
Natural gas (MMcf) 54,021 1,383 55,404
Total oil equivalents (MBOE)(1)
33,802 1,454 35,256
Year ended December 31, 2024:
Oil (MBbl) 15,756 6,829 22,585
NGL (MBbl) 10,372 2,898 13,270
Natural gas (MMcf) 61,421 17,373 78,794
Total oil equivalents (MBOE)(1)
36,364 12,623 48,987
_______________________________________________________________________________
(1)The numbers presented are based on actual amounts and may not recalculate using the rounded numbers presented in the table above.
(2)Delaware Basin production is the result of oil and natural gas properties acquired during the year ended December 31, 2023. See Note 4 to our consolidated financial statements included elsewhere in this Annual Report for additional information on our acquisitions of oil and natural gas properties.
Years ended December 31,
2024 2023 2022
Sales volumes:
Average daily oil equivalent sales volumes (BOE/D)(1)
133,845 96,591 82,400
Average daily oil sales volumes (Bbl/D)(1)
61,708 46,284 37,912
Sales revenues (in thousands):
Oil $ 1,728,971 $ 1,328,518 $ 1,351,207
NGL $ 190,775 $ 136,901 $ 234,613
Natural gas $ 15,544 $ 63,214 $ 208,554
Average sales prices(1):
Oil ($/Bbl)(2)
$ 76.55 $ 78.64 $ 97.65
NGL ($/Bbl)(2)
$ 14.38 $ 15.00 $ 29.22
Natural gas ($/Mcf)(2)
$ 0.20 $ 1.14 $ 4.23
Average sales price ($/BOE)(2)
$ 39.51 $ 43.36 $ 59.66
Oil, with commodity derivatives ($/Bbl)(3)
$ 76.56 $ 76.99 $ 70.32
NGL, with commodity derivatives ($/Bbl)(3)
$ 14.29 $ 15.00 $ 24.29
Natural gas, with commodity derivatives ($/Mcf)(3)
$ 0.95 $ 1.34 $ 2.83
Average sales price, with commodity derivatives ($/BOE)(3)
$ 40.70 $ 42.87 $ 43.48
Selected average costs and expenses per BOE sold(1):
Lease operating expenses $ 9.15 $ 7.41 $ 5.78
Production and ad valorem taxes 2.41 2.64 3.69
Oil transportation and marketing expenses 0.92 1.17 1.79
Gas gathering, processing and transportation expenses 0.36 0.06 -
General and administrative (excluding LTIP) 1.75 2.26 1.91
Total selected operating expenses $ 14.59 $ 13.54 $ 13.17
General and administrative (LTIP):
LTIP cash $ 0.05 $ 0.11 $ 0.11
LTIP non-cash $ 0.27 $ 0.28 $ 0.24
General and administrative (transaction expenses) $ 0.01 $ 0.32 $ -
Depletion, depreciation and amortization $ 15.15 $ 13.14 $ 10.36
_______________________________________________________________________________
(1)The numbers presented are based on actual amounts and may not recalculate using the rounded numbers presented in the table above.
(2)Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point.
(3)Price reflects the after-effects of our commodity derivative transactions on our average sales prices. Our calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods.
Reserves
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 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.
December 31, 2024 Year ended December 31, 2024
Estimated proved reserves(1)
Producing wells Average daily production
MBOE % Oil Net
acreage Gross Net (BOE/D) % Oil % NGL % Natural gas
Total Permian Basin 455,275 40 % 286,796
2,679 1,851 133,845 46 % 27 % 27 %
_____________________________________________________________________________
(1)See "-Our operations-Estimated proved reserves" for discussion of the prices utilized to estimate our reserves.
Our estimated proved reserves as of December 31, 2024 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:
December 31, 2024 December 31, 2023
Proved developed:
Oil (MBbl) 118,966 104,993
NGL (MBbl) 101,229 89,449
Natural gas (MMcf) 587,785 555,472
Total proved developed (MBOE) 318,159 287,021
Proved undeveloped:
Oil (MBbl) 64,174 54,790
NGL (MBbl) 38,421 31,954
Natural gas (MMcf) 207,124 186,710
Total proved undeveloped (MBOE) 137,116 117,862
Estimated proved reserves:
Oil (MBbl) 183,140 159,783
NGL (MBbl) 139,650 121,403
Natural gas (MMcf) 794,909 742,182
Total estimated proved reserves (MBOE) 455,275 404,883
Percent developed 70 % 71 %
Technology used to establish proved reserves
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 employed reliable technologies that have been demonstrated to yield results with consistency and repeatability.
Qualifications of technical persons and internal controls over reserves estimation process
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 estimated 100% of our proved reserve information as of December 31, 2024, 2023 and 2022 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 10 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 Operating 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.
Proved undeveloped reserves
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 increased from 117,862 MBOE as of December 31, 2023 to 137,116 MBOE as of December 31, 2024. We estimate that we incurred $667 million of costs to convert 40,914 MBOE of proved undeveloped reserves from 73 locations into proved developed reserves in 2024. New proved undeveloped reserves of 60,083 MBOE were added during the year in the Delaware and Midland Basins. An additional 27,072 MBOE were added from acquisitions of proved undeveloped reserves during the year. Negative revisions of 26,987 MBOE reflected (i) 27,033 MBOE of negative revisions due to proved undeveloped locations that were removed due to a change in the development plan following consideration of recent acquisitions, (ii) 3,312 MBOE of negative revisions from changes in previously estimated quantities due to performance, price and other changes and (iii) 3,358 MBOE of positive revisions due to proved undeveloped locations that were removed from the development plan in prior years. A final investment decision has been made on all 199 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, 2024 reserve report are $1.8 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 $539 million in 2025, $403 million in 2026, $372 million in 2027, $342 million in 2028 and $135 million in 2029. 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 2025 to 2029. Reserve calculations at any end-of-year period are representative of our development plans at that time. While 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.
Acreage
The following table sets forth our developed and undeveloped acreage as of December 31, 2024, including acreage HBP. A majority of our developed acreage is subject to liens securing our Senior Secured Credit Facility.
Developed acres Undeveloped acres Total acres %
HBP
Gross Net Gross Net Gross Net
Permian-Midland Basin 218,973 184,933 35,084 19,434 254,057 204,367 90 %
Permian-Delaware Basin 112,100 76,386 7,796 6,043 119,896 82,429 93 %
Total 331,073 261,319 42,880 25,477 373,953 286,796 91 %
The following table sets forth our gross and net undeveloped acreage as of December 31, 2024 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.
Years ended December 31,
2025 2026 2027 2028
Gross Net Gross Net Gross Net Gross Net
Permian-Midland Basin - - 16,213 11,042 12,358 5,817 5,766 2,263
Permian-Delaware Basin 2,850 2,448 3,368 2,727 30 159 908 164
Total 2,850 2,448 19,581 13,769 12,388 5,976 6,674 2,427
Of the total undeveloped acreage identified as potentially expiring over the next five years as of December 31, 2024, 4,670 net acres have associated PUD reserves included in our reserve report as of December 31, 2024, which we anticipate drilling to hold or renewing the associated leases. These PUD reserves represent 10% of our total PUD reserves as of December 31, 2024.
Of the total undeveloped acreage identified as potentially expiring over the next five years as of December 31, 2023, 4,859 net acres had associated PUD reserves on our reserve report as of December 31, 2023. Of the total undeveloped acreage expiring in 2024, there were no associated net acres that were not drilled to hold or otherwise retained.
Marketing
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 are 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. The following table presents our material firm sale and transportation commitments as of December 31, 2024:
Total 2025 2026 2027 2028 and after
Crude oil (MBbl):
Sales commitments 9,125 9,125 - - -
Transportation commitments:
Field 5,154 1,374 1,374 1,374 1,032
To U.S. Gulf Coast 28,700 12,775 12,775 3,150 -
Natural gas (MMcf):
Sales commitments 37,485 9,027 8,114 7,396 12,948
Natural gas liquids (MBbl):
Sales commitments 5,356 1,460 1,460 1,460 976
Total commitments (MBOE) 54,583 26,239 16,962 7,217 4,166
As 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, 2024, 2023 and 2022, 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."
Title to properties
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%.
Seasonality
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.
Regulation of the oil and natural gas industry
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 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 activities by, among other things, requiring permits and bonds for the drilling and operation of wells and regulating the location of wells, method of drilling and casing wells, surface use and restoration of properties upon which wells are drilled and plugging and abandonment of wells. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
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 ("LNG") 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 was 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. In July 2024, a federal judge in Louisiana stayed the pause, allowing the Department of Energy to continue reviewing pending export permit applications. In December 2024, the Department of Energy published its 2024 LNG Export Study analyzing potential effects of LNG exports to inform its public interest review of, and ultimately decisions on, applications to export LNG to countries that the United States does not have a free trade agreement with. The Department of Energy is accepting public comments on its 2024 LNG Export Study and has stated that it does not intend to revise the study in response to public comments. However, we cannot predict what actions the Trump administration may take with respect to the 2024 LNG Export Study and the timing with respect to the same. As a result, the ultimate impact of the 2024 LNG Export Study on our business is uncertain.
Oil and gas pipelines
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. On January 17, 2025, PHMSA published a final rule imposing more stringent leak detection and repair obligations to address methane leaks on pipelines subject to PHMSA regulation; however, implementation of this final rule is uncertain at this time following the change in U.S. presidential administration.
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.
Environmental and occupational health and safety matters
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.
Hazardous substance and waste handling
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 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." While no changes have been made with respect to this exemption to date, from time to time, the EPA has reconsidered whether or not 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.
Water and other waste discharges and spills
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 scope of waters regulated under the Clean Water Act has fluctuated in recent years. On June 29, 2015, the EPA and the Corps jointly promulgated final rules expanding the scope of waters protected under the Clean Water Act. However, on October 22, 2019, the agencies repealed the 2015 rules, and on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rules, and significantly reduced the waters subject to federal regulation under the Clean Water Act. On August 30, 2021, a federal court struck down the replacement rule and on January 18, 2023, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015. However, the January 2023 rule was challenged and is currently enjoined in 27 states. Separately, in May 2023 the U.S. Supreme Court released its opinion in Sackett v. EPA, which involved issues relating to the legal tests used to determine whether wetlands qualify as WOTUS. The Sackett decision invalidated certain parts of the January 2023 rule and significantly narrowed its scope, resulting in a revised regulation being issued in September 2023. However, due to the injunction on the January 2023 rule, the implementation of the September 2023 rule currently varies by state. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act. To the extent the rules expand the range of properties subject to the Clean Water Act's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
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.
Hydraulic fracturing
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 minimize 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.
Hydraulic fracturing is generally not regulated at the federal level, though from time to time legislation has been proposed in recent sessions of Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic fracturing and require public disclosure of the chemicals used in the fracturing process. The SDWA regulates the underground injection of substances through the Underground Injection Control Program (the "UIC"). However, hydraulic fracturing is generally exempt from regulation under the UIC, and thus the process is typically regulated by state oil and gas commissions. Nevertheless, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the UIC, and the EPA has issued guidance for such injection activities. The EPA has separately issued a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants.
Furthermore, from time to time certain governmental reviews have been conducted that focus on environmental aspects of hydraulic fracturing practices. For example, in 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Notwithstanding the lack of comprehensive federal regulation of hydraulic fracturing to date, any further regulation of hydraulic fracturing activities could restrict, limit or otherwise increase our operating costs and accordingly could have a material impact on our business, financial condition, and results of operation.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, in Texas, the RRC has adopted rules requiring the disclosure of chemicals used in the hydraulic fracturing process, as well as rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Recently, there has been increased scrutiny of the use of the injection wells for the disposal of produced water from hydraulic fracturing and the potential for injection well operations to result in seismic activity. The RRC has issued rules that, among other things, require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The rules also clarified the RRC's authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits and temporarily suspend operations for waste disposal wells and, in September 2021, the RRC curtailed the amount of water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin and has since indefinitely suspended some permits there and expanded the restrictions to other areas. More recently, in December 2023, the RRC suspended the permits of 23 deep disposal wells in the seismic response area covering Culberson and Reeves Counties. These restrictions on the disposal of produced water could result in increased operating costs, forcing us or our service providers to truck produced water, recycle it or pump it through the pipeline network or other means, all of which could be costly.
In addition, a number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have induced seismic activity and adversely impacted drinking water supplies, use of surface water, and the environment generally. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If these or any other new laws or regulations that
significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to drill and produce from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing is enacted into law.
Air quality
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, engines, dehydration units, and heaters; and maintenance requirements for such equipment. Also, on June 3, 2016, the EPA published 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 clarified the term “adjacent” and defined when sources are required to be aggregated. The consequences of these requirements are that smaller sites may need to be combined, triggering more stringent air permitting processes and requirements. Current air permitting regulations require us to obtain pre-approval for the construction or modification of projects or facilities expected to produce or increase air emissions. Once obtained these air permits require compliance with strict and stringent requirements and utilize specific equipment or technologies to control and monitor emissions of certain pollutants. The need to obtain air permits and emission control equipment prior to construction requires timely planning to ensure that the development of oil and natural gas projects is not delayed.
In recent years, the regulation of methane emissions from oil and gas operations has been subject to increased scrutiny. Following a series of rulemakings imposing various emission standards and leak detection and repair (“LDAR”) requirements for first volatile organic compounds and then methane, in December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities in the oil and gas sector, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc. Under the final rules, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. In January 2023, CarbonMapper became the first EPA approved third party under the "super emitter" program. Fines and penalties for violations of these rules can be substantial. The final methane rule is currently being challenged by 23 states and a coalition of industry groups in the U.S. Circuit Court of Appeals for the D.C. Circuit and may be repealed or modified by the Trump Administration. Moreover, compliance with the new rules may affect the amount we owe under the Inflation Reduction Act of 2022's (“IRA") methane fee described below because compliance with the EPA’s methane rules would exempt an otherwise covered facility from the requirement to pay the methane fee. The requirements of the EPA’s final methane rules have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows. Failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief.
The above standards, as well as any future laws and their implementing regulations, require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions and impose stringent air permit requirements. These regulations also mandate the use of specific equipment or technologies to minimize, eliminate, or control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.
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.
Greenhouse gas ("GHG") emissions
In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. Although the Biden Administration took legislative, regulative and executive action to address GHG emissions and climate change, policy priorities, such as climate change, are likely to change depending on political administration. 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 starts in calendar year 2024 at $900 per ton of methane, increases to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA. The EPA finalized regulations implementing the IRA’s methane emissions charge in November 2024. We cannot predict what actions Congress may take with respect to the IRA’s methane emissions charge and the timing with respect to the same. The Trump administration may also seek to revise or repeal the methane emissions charge implementing rule though we cannot predict whether such action will occur or its timing. As a result, the ultimate impact of the IRA’s methane emissions charge and its implementing rule on our business is uncertain. In May 2024, the EPA finalized revisions to the GHG reporting program, which 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, 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 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.
Additionally, the United States Securities and Exchange Commission released its final rule on climate-related disclosures on March 6, 2024, requiring the disclosure of certain climate-related risks and financial impacts, as well as greenhouse gas emissions. Large accelerated filers will be required to incorporate the applicable climate-related disclosures into their filings beginning in fiscal year 2025, with additional requirements relating to the disclosure of Scope 1 and 2 greenhouse gas emissions, if material, and attestation reports for certain large accelerated filers subsequently phasing in. However, the future of the SEC climate rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges; moreover, the Trump administration may seek to repeal the rule though we cannot predict whether such action will occur or its timing. On his first day in office, President Trump issued several Executive Orders, rescinding many of the previous administration's climate-related initiatives. As a result, the ultimate impact of the SEC rule, or any similar climate-related disclosure requirements imposed in the future, on our business is uncertain and may result in increased compliance costs and increased costs of and restrictions on access to capital. Even absent any significant GHG-related rulemaking in the near-term at the federal level, states may continue to aggressively pursue the regulation of GHG emissions. For instance, in October 2023, California passed climate-related disclosure laws requiring public and private companies doing business in California with total annual revenues exceeding certain thresholds to make disclosures, including GHG emissions data and climate-related financial risks. Other U.S. states are considering or in various stages of enacting similar climate-related disclosure laws. To the extent that the Company is required to make disclosures under any of these jurisdictions, these new and proposed laws may result in additional costs to comply with these disclosure requirements as well as increased costs of
and restrictions on access to capital. Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to alleged climate-related damages resulting from our operations, statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions or progress towards our sustainability targets, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions.
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. Further, in December 2023, 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. However, on January 20, 2025, President Trump signed an Executive Order calling for withdrawal of the United States from the Paris Agreement and revocation of any related financial commitments thereunder as part of a broader series of executive orders announcing a deregulatory approach with respect to climate change matters. State or local governments may, however, elect to continue to participate in international climate change initiatives or pursue state- or regional-level climate change-related regulations.
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, although this trend has waned in recent years. 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 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. Moreover, public statements with respect to emissions reduction goals or progress, other environmental targets or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” (i.e., misleading information or false claims overstating potential ESG benefits). For example, the SEC has recently taken enforcement action against companies for ESG-related misconduct, including alleged greenwashing. Certain regulators, such as the SEC and various state agencies, as well as nongovernmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG-related statements, goals or standards were misleading, false or otherwise deceptive. Certain employment practices and social initiatives are also the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and frameworks applicable to such initiatives continue to evolve. More recent political developments could mean that the Company faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Such sentiment may focus on the Company’s environmental commitments (such as reducing GHG emissions) or its pursuit of certain employment practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. The complex regulatory and legal frameworks applicable to such initiatives continue to evolve. Consideration of ESG-related factors in the Company’s decision-making could
be subject to increasing scrutiny and objection from such anti-ESG parties. 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 or even negative perceptions of the Company or our business resulting from any allegations 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.
Occupational Safety and Health Act
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.
Endangered Species Act
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 or dunes sagebrush lizard, are located in areas where we operate or previously unprotected species, such as the monarch butterfly, 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 December 2024, FWS proposed listing the monarch butterfly as a threatened species. At this time we cannot predict the ultimate impact any final listing of the monarch butterfly under the ESA may have on our operations.
Summary
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, 2024, 2023 or 2022.
Regulation of derivatives
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 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 took effect March 15, 2021 and the position limits, other than those for economically equivalent swaps provided for in the Position Limit Rule, took effect on January 1, 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. 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.
Human capital
At Vital Energy, we believe our people set us apart from our peers. We seek to energize the potential of our people through the "Vital Way," which is intended to bring together unique and sound ideas, approaches and individual experiences, fuel innovation and maximize operational performance. We strive to empower our people through Vital’s core values of Unafraid, Unshakable and Unbiased. Accordingly, Vital’s key human capital objectives are to attract, retain, motivate and develop the highest quality talent possible. We seek to foster a collegial work environment to help our employees attain their highest level of productivity, creativity and efficiency. To support these objectives, our board of directors oversees our human capital strategy. Our Nominating, Corporate Governance, Environmental and Social Committee has been delegated the responsibility of reviewing strategies and policies related to human capital management, including with respect to our employment practices, workplace culture, talent development and retention, and the safety of our workforce. Our Compensation Committee has also been delegated the responsibility of overseeing our total rewards program and promoting its alignment with Vital's strategic objectives and stockholders' interest.
We are committed to cultivating a workplace culture built on safety, equal employment opportunity and continuous improvement. Our Code of Conduct and Business Ethics provides a foundation to uphold these values supported by regular training on topics such as anti-harassment, whistleblower procedures, conflict of interest avoidance, and anti-trust compliance.
Employee feedback plays a crucial role in shaping our initiatives. Through engagement surveys and employee-led focus groups, we’ve gained valuable insights into areas such as workload and flexibility, workplace culture, communication, recognition, and rewards. These efforts guide us in creating meaningful practices that align with the needs and aspirations of our workforce. To further foster transparency and collaboration, we host regular town halls where employees hear directly from our leadership team on key updates and initiatives. Together, these actions reflect our dedication to building an environment where everyone feels valued and empowered to succeed.
Workforce Composition
As of December 31, 2024, we employed 405 full-time employees, 199 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.
Equal Employment Opportunity
We believe that our commitment to equal employment opportunity will help our organization better accomplish our mission as it provides us with an opportunity to obtain unique perspectives, experiences and ideas that can help our organization succeed.
At Vital Energy, we are dedicated to providing a collaborative workplace where open communication and mutual respect are at the core of our culture. We believe that by working together, we are stronger, and we strive to create an environment where challenges can be addressed collaboratively and respectfully.
Diversity of thought is fundamental to the Vital Way. We are committed to honoring this value as we grow and evolve. By embracing our employees' many perspectives and ideas, we aim to foster innovation, strengthen our community, and ensure that every employee feels valued and empowered to contribute to our shared success.
Health and Safety
It is important that our people stay healthy and safe. We know that an engaged, healthy, safe and well-trained workforce helps us accomplish our strategic goals. We seek to achieve these goals through all-hands safety meetings, hazard hunts, stop-work authority and root-cause analysis.
Total Rewards
We believe in empowering our employees by offering a comprehensive total rewards program designed to attract and retain exceptional talent to achieve Vital’s business strategy. This program includes a competitive compensation package and a wide range of benefits aimed at fostering employee satisfaction and engagement. Our compensation model is built on three core principles: (i) providing competitive base salaries and benefits, (ii) rewarding both short-term and long-term performance and (iii) linking pay to individual performance and company performance. To maintain competitiveness within our industry, we conduct regular market benchmarking against an annually selected peer group and the broader market. These reviews help us stay aligned with trends in compensation, benefits, and best practices ensuring our model supports Vital’s evolving human capital needs. In addition to competitive salaries, our model features both short-term and long-term incentive programs that connect employee pay to individual performance. These performance measures reflect our environmental, safety, operational and financial priorities, aligning with our stockholder expectations and fostering a shared commitment to Vital’s success. We believe our pay for performance approach drives better business outcomes, strengthens employee capabilities, improves productivity, and boosts retention, motivation and overall employee satisfaction. Our total rewards program also includes a company-matched 401(k) plan with immediate vesting, flexible working schedules, and a variety of employee-focused initiatives, underscoring our commitment to fostering a supportive and a rewarding workplace.
Learning and Development
At Vital Energy, attracting, retaining, and developing top talent is fundamental to our success and central to our long-term strategy. To support our employees’ growth, we offer tuition reimbursement benefits for extended educational opportunities. We also provide an in-depth training program for our Lease Operators and Field Technicians. This program ensures consistency in processes and offers leadership clear insights when evaluating field employees for promotional opportunities. Administered collaboratively by our Production leadership and Learning and Development teams, the program reflects our commitment to intentionally training and promoting from within. We take pride in recognizing and advancing the exceptional talent within our workforce, reinforcing our belief in the value of internal growth and development.
Available information
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 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 (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, in our Sustainability Reports or in any other reports discussed herein 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.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risks described elsewhere in this Annual Report, were actually to occur, our business, financial condition or results of operations could be materially adversely affected and the trading price of our shares could decline resulting in the loss of part or all of your investment. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial may also adversely affect us.
Risks related to our business
Oil, NGL and natural gas prices are volatile. Volatility in oil, NGL and natural gas prices has adversely affected, and may continue to adversely affect, our business, financial condition and results of operations and may in the future affect our ability to meet our capital expenditure obligations and financial commitments as well as negatively impact our stock price.
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.
Conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.
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 elevated interest rates 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.
We may be subject to risks in connection with acquisitions and dispositions of assets.
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 Point Acquisition, 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.
Acquisitions may not achieve the intended results and our results may suffer if we do not effectively manage our expanded operations following such transactions.
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. Further, we make certain assumptions regarding the estimated proved reserves we acquire which are based in part on commodity prices at the time of any such acquisition. To the extent commodity prices thereafter decline, we may have to make downward adjustments to our estimated proved reserves.
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 Point Acquisition, 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.
In addition, integrated acquired businesses and assets involves a number of special risks and unforeseen difficulties that can arise in integrating operations and systems and in retaining and assimilating employees. These difficulties include, among other things:
•Operating a larger organization;
•Coordinating geographically disparate organizations, system and facilities;
•Integrating corporate, technology and administrative functions;
•Diverting management's attention from regular business concerns;
•Diverting financial resources away from existing operations;
•Increasing our indebtedness; and
•Incurring potential environmental or regulatory liabilities and title problems.
Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results. The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage our business. If our management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.
Continuing or worsening inflationary pressures and associated changes in monetary policy have resulted in and may result in additional increases to our drilling and completions costs and costs of oilfield services, equipment, and materials, which in turn have caused and may continue to cause our capital expenditures and operating costs to rise.
The U.S. inflation rate increased in 2021 and 2022 before declining in 2023 and 2024. These inflationary pressures have resulted in and may result in additional increases to our drilling and completions costs and costs of oilfield services, equipment, and materials, which in turn have caused and may continue to cause our capital expenditures and operating costs to rise. Further, the costs of oilfield services, equipment and materials may be increased as a result of the imposition or increase of tariffs on certain raw materials. The Federal Reserve and other central banks increased interest rates in 2022 and 2023 to curb inflation. The Federal Reserve reduced benchmark interest rates in 2024 and has indicated that it may further reduce rates in 2025. However, there is no guarantee that interest rates will decline, and to the extent interest rates increase, the cost of capital could increase and economic growth could be depressed, either of which -or the combination thereof - could hurt the financial and operating results of our business.
As a result of the volatility in prices for oil, NGL and natural gas, we have taken and may be required to take further write-downs of the carrying values of our properties.
We use the full cost method of accounting for our oil and natural gas properties, with the full cost ceiling based principally on the estimated future net cash flows from our proved oil, NGL and natural gas reserves, which exclude the effect of our commodity derivative transactions, discounted at 10% under required SEC guidelines for pricing methodology. The SEC pricing methodology is the unweighted arithmetic average first-day-of the month commodity price for each month within the trailing 12-month period adjusted for differentials. We review the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC on a quarterly basis. In the event the unamortized cost, or net book value, of our evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, the excess is expensed in the period such excess occurs. Once incurred, a write-down of evaluated oil and natural gas properties is not reversible and constitutes a non-cash charge to earnings. In the fourth quarter of 2024, our unamortized cost of evaluated oil and natural gas properties exceeded the full cost ceiling and, as such, we recorded a non-cash full cost ceiling impairment during the year ended December 31, 2024.
Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we have been required to, and may be required to further, write-down the carrying value of our properties. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Pricing and reserves" and Note 6 to our consolidated financial statements included elsewhere in this Annual Report for additional information.
There is no guarantee that we will be successful in optimizing our well spacing, drilling and completions techniques in order to maximize our rate of return, cash flows from operations and stockholder value.
As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flows from operations and stockholder 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, it may have a material adverse effect on our production results, financial performance, stock price and net asset value.
Competition in the oil and natural gas industry is intense, making it difficult for us to acquire properties, market oil, NGL and natural gas and secure trained personnel.
Our ability to acquire additional drilling locations and to find and develop reserves in the future may depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive, concentrated geographic environment for acquiring properties, marketing oil, NGL and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil, NGL and natural gas industry, especially in our focus areas. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil, NGL and natural gas properties and exploratory locations and to evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, procuring goods and services, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
Recent transactions may expose us to contingent liabilities.
We have agreed to indemnify the sellers of assets in recent transactions, including in connection with the Point Acquisition, 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.
We may be unable to quickly adapt to changes in market/investor priorities.
Historically, one of the key drivers of external capital investment in the unconventional resource industry has been growth in production and reserves. However, in light of recent trends such as historical levels of volatility in oil and natural gas prices and sustained high interest rates increasing the cost of borrowing, capital efficiency and free cash flow from earnings have become the key drivers for energy companies, particularly shale 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.
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 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 Unaudited Supplementary Information included elsewhere in this Annual Report.
Unless we replace our oil, NGL and natural gas production, our reserves and production will continue to decline, which would adversely affect our future cash flows and results of operations.
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.
Insufficient transportation capacity in the Permian Basin, and the challenges to alleviating such transportation constraints, could cause significant fluctuations in our realized oil prices and our results of operations.
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 production is dependent upon transportation, processing and storage, certain of which we do not control. If these services are unavailable, our operations could be interrupted and our revenues reduced.
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 utilized for the transportation to market of the products originating at our leases. Our failure to provide or obtain such services on acceptable terms could materially harm our business.
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 decrease in our production of oil, NGL and natural gas could negatively impact our ability to meet our contractual obligations to deliver oil, NGL and natural gas and our ability to retain our leases.
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-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 five 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.
The potential drilling locations that we have tentatively internally identified for our future wells will be drilled, if at all, over many years. This makes them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
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.
The inability of our significant customers to meet their obligations to us may materially adversely affect our financial results.
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 unavailability or high cost of additional oilfield services, including personnel, drilling rigs, equipment and supplies, as well as fees for the cancellation of such services, could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
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.
Our business and operations may be further impacted by epidemics, outbreaks and other public health events.
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, may cause disruptions to our business and operations, which may include (i) shortages of employees, (ii) unavailability of contractors or subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by government and health authorities, including quarantines, to address an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees.
Our business could be negatively impacted by disruption of electronic systems, security threats, including cybersecurity threats, and other disruptions.
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. We also rely on the information systems of our third-party vendors, contractors and other partners to support these aspects of our operations. Moreover, some of our networks and systems are managed by third-party service providers and are not under our direct control. A failure or substandard performance of any of these systems due to outages, natural disasters, acts of war, or usage error, or a successful cyberattack or breach targeting us or our third-party partners, could lead to loss of communication links; an inability to find, produce, process and sell oil, NGL and natural gas; an inability to automatically process commercial transactions or engage in similar automated or computerized business 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 events could lead to operation disruptions, regulatory scrutiny or financial losses, all of which could have a material adverse effect on our business, reputation and financial condition.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our or third-party facilities and infrastructure and threats from terrorist acts. These threats may materialize as successful attacks. In particular, cybersecurity attacks are dynamic and evolving and include, but are not limited to, malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. As cyberattacks evolve, we may need to allocate additional resources to strengthen our security measures, address vulnerabilities and investigate or resolve potential cybersecurity threats. Although we utilize various procedures and controls to detect, monitor and protect against these threats and to mitigate our exposure to such threats, including through the implementation of continuous monitoring of threat detection, regular security audit, employee security training and incident response exercises and plans, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing, detecting such threats or effectively mitigating their impact. In the event of a successful attack, our ability to quickly detect, respond to and recover from the incident may be limited, leading to prolonged disruptions and increased costs associated with containment, investigation and recovery efforts. Though we and our service providers have experienced certain cybersecurity incidents, we are not aware of any previous cybersecurity threats or incidents that have materially affected or are reasonably likely to materially affect us or our operational and financial results. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that we will remain unaffected in the future, as no security measure is infallible. If any of these threats were successful, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations, which could result in liability from data privacy or cybersecurity claims, regulator penalties, damage to our reputation or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences and have a material adverse effect on our reputation, financial position, results of operations or cash flows.
Moreover, the growing regulatory landscape around data protection adds additional complexity to safeguarding our information. Compliance with various data privacy and cybersecurity regulations may impose significant costs, and any perceived or actual failure to comply could result in regulatory penalties, litigation and reputational harm.
Our business could be negatively impacted by hydrocarbon price volatility as the result of, or with the intensification of global geopolitical tensions that may create heightened volatility in oil and natural gas prices.
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 OPEC+ member states. Specifically, volatility in oil and gas prices may be created as a result of the ongoing war between Russia and Ukraine, continued or intensified conflict in the Middle East and the potential impact to global shipping caused by
Houthi rebels in Yemen. Such volatility could reduce the prices we receive from our sales of oil and natural gas and adversely affect our profitability.
The loss of senior management or technical personnel and the failure to attract, train and retain qualified personnel could adversely affect our operations.
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.
We may not always foresee new operational/technical issues as new technology enables greater operational capabilities.
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 in a concentrated geographic area, making us vulnerable to risks associated with operating in one major geographic area.
Our producing properties are geographically concentrated in the Permian Basin. As of December 31, 2024, 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.
Our balance sheet includes a significant amount of deferred tax assets, which are primarily related to net operating losses. Fluctuations in our tax obligations and effective tax rate and realization of our deferred tax assets may result in volatility of our operating results and adversely affect our financial condition.
We have significant deferred tax assets, which are substantially comprised of federal net operating losses ("NOL"). We must generate sufficient earnings of the appropriate character in order to utilize our deferred tax assets. We recorded a pre-tax loss for the year ended December 31, 2024, which was mainly due to a significant non-cash full cost ceiling impairment. If we were to continue experiencing pre-tax losses over an extended period of time, we may not be able to demonstrate the ability to utilize our deferred tax assets and, as a result, may need to record a valuation allowance against them. Recording a valuation allowance could adversely affect our results of operations in a material way in the period the valuation allowance is recorded.
If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising prior to the ownership change to offset future taxable income. In addition, our ability to use net operating loss carryforwards to reduce future tax payments may be limited if our taxable income does not reach sufficient levels.
As of December 31, 2024, the Company had federal NOL carryforwards totaling $897.0 million, $530.2 million of which will begin to expire in 2035 and $366.8 million of which will not expire but may be limited in future periods, and state of Oklahoma NOL carryforwards totaling $459.3 million, none of which will expire. An ownership change would establish an annual limitation on the amount of our federal and Oklahoma pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate, periodically promulgated by the IRS. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more "5% shareholders" (as defined in the Internal Revenue Code) at any time during a rolling three-year period. Future changes in our stock ownership may materially limit our NOLs and other tax attributes, which may harm our financial condition and results of operation by effectively increasing our tax obligations. We will continue to review the realizability of the NOLs and other tax attributes.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
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, 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 cybersecurity 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.
Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks.
We have developed, and expect to continue to develop, voluntary targets related to ESG initiatives, including our emissions reduction targets and strategy, which are often aspirational. Public statements related to these initiatives reflect our current plans, and are based on expectations and assumptions and hypothetical scenarios 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, many 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 represent. Additionally, emission accounting methodologies are subject to change, resulting in increases in our reported emissions. Moreover, we cannot guarantee that all of our relevant stakeholders will agree with the ultimate approach we may select to meeting our ESG-related targets or goals. Any of these issues could adversely impact our ability to meet any ESG-related targets we may set or give rise to reputational risks.
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.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. While such ratings do not impact all investors' investment or voting decisions,
unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative sentiment toward us, our customers and our industry and to the diversion of investment to other industries, which could have a negative impact on our revenue and profits and our access to and costs of capital. Furthermore, while we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and services, we cannot guarantee that such participation or certification will have the intended results on our ESG profile.
Risks related to our financing and indebtedness
Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms or at all.
Our exploration, development, marketing, transportation and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, proceeds from equity offerings, proceeds from debt offerings, borrowings under our Senior Secured Credit Facility and proceeds from asset dispositions. We do not have commitments from anyone to contribute equity capital to us. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of oil, NGL and natural gas and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to sustain our operations at current levels. We may not be able to obtain debt or equity financing on terms favorable to us or at all. The failure to obtain additional capital could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our oil, NGL and natural gas production or reserves and, in some areas, a loss of properties.
Currently, we receive a level of cash flow stability as a result of our hedging activity. To the extent we are unable to obtain future hedges at beneficial prices or our commodity derivative activities are not effective, our cash flows and financial condition may be adversely impacted.
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.
We may incur significant additional amounts of debt.
As of December 31, 2024, we had total long-term indebtedness of $2.48 billion. We may 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.
Increases in our cost of and ability to access capital, including as a result of ESG matters, could adversely affect our business.
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 flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results. Further,while membership in certain alliances or similar organizations is in flux, certain financial institutions have announced their intention to cease investment banking and corporate lending activities in the North American oil and gas sector or have established climate-related funding commitments or screens for ESG performance that could have the effect of limiting their investment in us or our industry. If we are unable to meet such ESG standards for investment, lending, ratings or voting criteria and policies set by these parties, we may lose investors, investors may allocate a portion of their capital away from us, we may become a target for ESG-focused activism, we may face increased costs of or limitations on access to capital or insurance necessary to sustain or grow our business, the price of our common stock or debt securities may be adversely impacted, demand for our services and products may be adversely impacted, and our reputation may be adversely affected, all of which could adversely impact our future financial results. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk-Interest rate risk" for additional information regarding interest rate risk. See Note 7 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding our debt and borrowing base.
Borrowings under our Senior Secured Credit Facility expose us to interest rate risk.
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 services across the United States. While the U.S. Federal Reserve reduced benchmark interest rates in 2024 and has indicated that it may further reduce rates in 2025, the continuation of rates at elevated levels could raise the cost of capital and depress economic growth, either of which could negatively impact our 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 would our interest costs, which may have a material adverse effect on our results of operations and financial condition.
We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.
Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure that we will generate sufficient cash flows from operations or that future funding will be available to us under our Senior Secured Credit Facility, equity or debt offerings or other actions in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness at or before maturity. We cannot assure that we will be able to refinance any of our indebtedness on commercially reasonable terms or at all.
Any significant reduction in our borrowing base under our Senior Secured Credit Facility as a result of a periodic borrowing base redetermination or otherwise will negatively impact our liquidity and, consequently, our ability to fund our operations, as well as our ability to repay borrowings under our Senior Secured Credit Facility or any other obligation if required.
Availability under our Senior Secured Credit Facility is currently subject to a borrowing base which is subject to scheduled semiannual (May 1 and November 1) and other elective borrowing base redeterminations based upon, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the Senior Secured Credit Facility. The lenders under our Senior Secured Credit Facility can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Senior Secured Credit Facility. Reductions in estimates of our oil, NGL and natural gas reserves will result in a reduction in our borrowing base (if prices are kept constant). Reductions in our borrowing base could also arise from other factors, including but not limited to (i) lower commodity prices or production, (ii) increased leverage ratios, (iii) inability to drill or unfavorable drilling results, (iv) changes in oil, NGL and natural gas reserves engineering, (v) increased operating and/or capital costs, (vi) the lenders' inability to agree to an adequate borrowing base or (vii) adverse changes in the lenders' practices (including required regulatory changes) regarding estimation of reserves.
We anticipate borrowing under our Senior Secured Credit Facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise will negatively impact our liquidity and our ability to fund our operations and, as a result, would have a material adverse effect on our financial position, results of operation and cash flow. Further, if the outstanding borrowings under our Senior Secured Credit Facility were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results. In addition, we keep cash at certain banks that are not FDIC insured or such deposits that exceed the FDIC insured amount. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and capital resources" for additional information regarding our liquidity. See Note 7 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding our debt and borrowing base.
We have incurred losses from operations for various periods since our inception and may do so in the future.
We incurred net losses in certain years of operation since our inception. Our development of and participation in an increasingly larger number of locations has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire oil, NGL and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical accounting estimates."
Our debt agreements contain restrictions that limit our flexibility in operating our business.
Our debt agreements contain, and any future indebtedness we incur may contain, various covenants that limit the manner in which we operate our business and our ability to engage in specified types of transactions. These covenants limit our ability to, among other things (i) incur additional indebtedness; (ii) pay dividends on, repurchase or redeem stock; (iii) make certain investments; (iv) sell, transfer or dispose of assets; (v) hedge our production; (vi) consolidate or merge; and (vii) enter into certain transactions with our affiliates.
A breach of any of these covenants could result in a default under one or more of these agreements and, in the case of our Senior Secured Credit Facility, permit the lenders to cease making loans to us. A default, if not waived, could result in acceleration of our indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it on terms acceptable to us. Furthermore, we have pledged substantially all of our assets as collateral to secure the debt under our Senior Secured Credit Facility and if we were unable to repay such debt, the lenders could proceed against such collateral. The proceeds from the sale or foreclosure upon such collateral will first be used to repay debt under our Senior Secured Credit Facility, and we may not have sufficient assets to repay such debt to our unsecured indebtedness thereafter.
Risks related to regulation of our business
If we are unable to drill new allocation wells, it could have a material adverse impact on our future production results.
In the State of Texas, allocation wells allow an oil and gas producer to drill a horizontal well under two or more leaseholds that are not pooled. We are active in drilling and producing allocation wells. If regulations regarding allocation wells are made, the RRC denies or significantly delays the permitting of allocation wells or if legislation is enacted that negatively impacts the current process under which allocation wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production, rates of return and other projected capital efficiencies.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and water disposal wells could prohibit projects or result in materially increased costs and additional operating restrictions or delays because of the significance of hydraulic fracturing and water disposal wells in our business.
Hydraulic fracturing is a practice that is used to stimulate production of oil and/or natural gas from tight formations. The process, which involves the injection of water, proppants and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal, state and local jurisdictions have adopted, or are considering adopting, regulations that could further restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. See "Item 1. Business-Regulation of the oil and natural gas industry-Hydraulic fracturing" for a further description of federal and state regulations addressing hydraulic fracturing. Additionally, there are certain governmental reviews either under way or being proposed that focus on environmental aspects of hydraulic fracturing practices, which could spur initiatives to further regulate hydraulic fracturing. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation or regulations governing hydraulic fracturing or water disposal wells are enacted into law.
Our operations are substantially dependent on the availability, use and disposal of water. New legislation and regulatory initiatives or restrictions relating to water disposal wells could have a material adverse effect on our future business, financial condition, operating results and prospects.
Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Texas has previously experienced, and may experience again, low inflows of water. As a result of these conditions, some local water districts may begin restricting the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGL and natural gas, which could have an adverse effect on our results of operations, cash flows and financial condition.
Additionally, our operational and production procedures produce large volumes of water that we must properly dispose. The Clean Water Act, the Safe Drinking Water Act, the Oil Pollution Act, 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 U.S. Environmental Protection Agency (the "EPA") or the state. Furthermore, the State of Texas maintains groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
Because of the necessity to safely dispose of water produced during operational and production activities, these regulations, or others like them, could have a material adverse effect on our future business, financial condition, operating results and prospects. See "Item 1. Business-Regulation of the oil and natural gas industry" for a further description of the laws and regulations that affect us.
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing-related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In an effort to control induced seismic activity and recent increase in earthquakes in the Permian Basin, which have been linked by the U.S. and local seismologist to wastewater disposal in oil fields, in September 2021, the RRC curtailed the amount of produced water companies were permitted to inject into some wells in the Permian Basin, and has since indefinitely suspended some permits there and expanded the restrictions to other areas.
Because we dispose of large volumes of produced water gathered from our drilling and production operations, these restrictions on the use of produced water and a moratorium on new produced water wells, together with the adoption and implementation of any new laws or regulations, could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or pump it through the pipeline network or other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, which may require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business, financial condition and results of operations. See "Item 1. Business-Regulation of the oil and natural gas industry-Hydraulic fracturing" for a further description of local regulations addressing seismic activity.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the Natural Gas Act of 1938 (the "NGA") exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission ("FERC"). We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and, therefore, are exempt from the FERC's jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.
The adoption of climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the oil, NGL and natural gas we produce, while potential physical effects of climate change could disrupt our operations and cause us to incur significant costs in preparing for or responding to those effects.
In August 2022, President Biden signed into law the IRA. 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. In addition, the IRA imposes the first ever federal fee on emission of GHGs through a methane emissions charge, which began its phase-in in 2024. The IRA 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, which could have an adverse effect on our business, financial condition and results of operations. The EPA finalized regulations implementing the IRA’s methane emissions charge in November 2024. We cannot predict what actions Congress may take with respect to the IRA’s methane emissions charge and the timing with respect to the same. The Trump
administration may also seek to revise or repeal the methane emissions charge implementing rule though we cannot predict whether such action will occur or its timing. As a result, the ultimate impact of the IRA’s methane emissions charge and its implementing rule on our business is uncertain.
Additional 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, 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. See "Item 1. Business-Regulation of the oil and natural gas industry-“Greenhouse gas" emissions" for a further discussion of the laws and regulations related to greenhouse gases.
Moreover, climate change may also result in various physical risks such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our financial condition and operations, as well as those of our suppliers or customers. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our services, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact the infrastructure on which we rely to provide our services. One or more of these developments could have a material adverse effect on our business, financial condition and operations. Extreme weather conditions can interfere with our production and increase our costs, and damage resulting from extreme weather may not be fully insured.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.
We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development, marketing, transportation and production activities. These laws and regulations may require us to obtain and maintain a variety of permits, approvals, certificates or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, production and transporting product pipelines or other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; 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 remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed, and, in some instances, the issuance of orders or injunctions limiting or requiring discontinuation of certain operations.
Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, accidental spills or releases from our operations could expose us to significant liabilities under environmental laws. Moreover, 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, NGL and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental actions are taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
See "Item 1. Business-Regulation of the oil and natural gas industry" for a further description of the laws and regulations
that affect us.
Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.
The Dodd-Frank Act, the Adopted Derivatives Rules, and the U.S. Resolution Stay Rules could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. We have stopped entering into new hedging transactions with Foreign Counterparties and do not currently intend to resume hedging with Foreign Counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act, the Adopted Derivatives Rules, the U.S. Resolution Stay Rules, and Foreign Regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations. See "Item 1. Business-Regulation of derivatives" for a further description of the laws and regulations that affect us.
Tax laws and regulations may change over time, and any such changes could adversely affect our business, results of operations, financial condition and cash flow.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including to certain key U.S. federal and state income tax provisions currently available to oil and natural gas exploration and development companies. Such legislative changes have included, but have not been limited to, (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on oil and natural gas extraction. Any changes in tax laws, and significant variance in our interpretation of current tax laws or a successful challenge of one or more of our tax positions by any taxing authority could result in additional taxes on our activities, which could adversely affect our business, results of operations, financial condition and cash flow.
In addition, the IRA, among other things, introduced a 15% corporate alternative minimum tax ("CAMT"). Under the CAMT, a 15% minimum tax is imposed on certain adjusted financial statement income of "applicable corporations." The CAMT generally treats a corporation as an applicable corporation in any taxable year in which the " average annual adjusted financial statement income" of the corporation and certain of its subsidiaries and affiliates for a three-taxable-year period ending prior to such taxable year exceeds $1 billion. The U.S. Department of the Treasury and the Internal Revenue Service have issued guidance on the application of the CAMT, which may be relied upon until final regulations are released. If our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash flows in that year, but provide an offsetting credit against our regular U.S. federal income tax liability in future years. Based on our interpretation of the IRA, CAMT and related guidance, we do not expect the CAMT to impact our tax obligation for the 2024 taxable year. We continue to evaluate the IRA and its effect on our financial results and operating cash flow.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil, NGL and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The presence of newly listed species, such as the lesser prairie chicken and dunes sagebrush lizard, or designation of previously unprotected species in areas where we operate, such as the monarch butterfly could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that
could have an adverse impact on our ability to develop and produce our reserves. See "Item 1. Business-Regulation of the oil and natural gas industry-Endangered Species Act" for further discussion about the impact of regulations protecting certain species of wildlife.
Risks related to our common stock
Our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware state law contain provisions that may have the effect of delaying or preventing a change in control and may adversely affect the market price of our capital stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without any further vote or action by the stockholders. The rights of the holders of our common stock will be subject to the rights of the holders of any preferred stock that may be issued in the future. The issuance of preferred stock could delay, deter or prevent a change in control and could adversely affect the voting power or economic value of our shares.
In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders.
Delaware law prohibits us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who owns 15% of our stock cannot acquire us for a period of three years from the date such stockholder became an interested stockholder, unless various conditions are met, such as the approval of the transaction by our board of directors. Provisions such as these are also not favored by various institutional investor services, which may periodically "grade" us on various factors, including stockholder rights and corporate governance policies. Certain institutional investors may have internal policies that prohibit investments in companies receiving a certain grade level from such services, and if we fail to meet such criteria, it could limit the number or type of certain investors which might otherwise be attracted to an investment in the Company, potentially negatively impacting the public float and/or market price of our common stock.
The availability of shares for sale in the future could reduce the market price of our common stock.
Subject to the rules of the NYSE, our board of directors has the authority, without action or vote of our stockholders, to issue our authorized but unissued shares of common stock. In the future, we may issue securities to raise cash for acquisitions, to pay down debt, to fund capital expenditures or general corporate expenses, in connection with the exercise of stock options or to satisfy our obligations under our incentive plans. We may also acquire interests in other companies by using a combination of cash and our equity securities or just our equity securities. We have in the past issued both shares of common stock and shares of preferred stock in order to fund acquisitions and have granted the recipients of such shares registration rights that may be used in order to sell such shares in registered and unregistered transactions, and we may do so in the future. We may also issue securities convertible into, exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our Company, reduce our earnings per share and have an adverse impact on the price of our common stock.
Because we have no current plans to pay, and certain of our agreements may, under specified conditions, limit our ability to pay, dividends on our common stock, investors must look primarily to stock appreciation for a return on their investment in us.
We do not anticipate paying any cash dividends on our common stock in the near term. We currently intend to retain all future earnings to fund the development and growth of our business. To the extent our earnings exceed our budgeted development plans, if any, we currently expect that we would use such excess earnings to repay indebtedness. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Covenants contained in our Senior Secured Credit Facility and the indentures governing our senior unsecured notes may under specified conditions limit the payment of dividends by, for example, requiring compliance with certain financial ratios following the payment of any dividend. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the primary means to realize a return on their investment on our common stock. Investors seeking cash dividends should not purchase our common stock.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
Not applicable.

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ITEM 2. PROPERTIES
Item 2. Properties
Our executive offices are located at 521 E. Second Street, Suite 1000, Tulsa, Oklahoma, 74120. Additional information required by Item 2. is contained in "Item 1. Business" and is incorporated herein.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we may not have insurance coverage. While many of these matters involve inherent uncertainty as of the date hereof, we do not currently believe that any such legal proceedings will have a material adverse effect on our business, financial position, results of operations or liquidity. See Note 15 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of legal proceedings.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
The operation of our Howard County, Texas sand mine is subject to regulation by the Federal Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health Act of 1977 (the "Mine Act"). MSHA may inspect our Howard County mine and may issue citations and orders when it believes a violation has occurred under the Mine Act. While we contract the mining operations of the Howard County mine to an independent contractor, we may be considered an "operator" for purposes of the Mine Act and may be issued notices or citations if MSHA believes that we are responsible for violations.
The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Annual Report.
Part II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market for registrant's common equity
Our common stock is listed on the New York Stock Exchange ("NYSE") under the symbol "VTLE."
As of February 19, 2025, there were 107 holders of record of our common stock.
Dividends
We have not paid any cash dividends on our common stock since our inception, but we paid cash dividends on shares of our 2.0% Mandatorily Convertible Series A Preferred Stock ("Preferred Stock"), which were converted to common stock during the year ended December 31, 2024. Covenants contained in our Senior Secured Credit Facility and the indentures governing our senior unsecured notes may, under specified conditions, limit the payment of cash dividends on our common stock. See "Item 1A. Risk Factors-Risks related to our financing and indebtedness-Our debt agreements contain restrictions that limit our flexibility in operating our business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Debt."
Issuer purchases of equity securities
The following table summarizes purchases of common stock by Vital Energy for the periods presented:
Period Total number of shares purchased(1)
Weighted-average price paid per share Total number of shares purchased as part of publicly announced program Maximum value that may yet be purchased under the program as of the respective period-end date(2)
October 1, 2024 - October 31, 2024 339 $ 30.26 - $ 200,000,000
November 1, 2024 - November 30, 2024 946 $ 27.14 - $ 200,000,000
December 1, 2024 - December 31, 2024 - $ - - $ 200,000,000
Total 1,285 -
____________________________________________________________________________
(1)Represents shares that were withheld by us to satisfy tax withholding obligations that arose upon the lapse of restrictions on certain equity-based compensation awards, namely restricted stock awards.
(2)On May 31, 2022, our board of directors authorized a $200.0 million share repurchase program commencing on the date of such announcement and continuing through and including May 27, 2024. On May 23, 2024, our board of directors approved an amendment to the share repurchase program to (i) increase the shares of Common Stock which the Company may purchase by $37.3 million, resulting in aggregate authorization of $237.3 million, and (ii) extend the expiration date to May 22, 2026. Share repurchases under the program may be made through a variety of methods, which may include open market purchases, including under plans complying with Rule 10b5-1 of the Exchange Act, and privately negotiated transactions. During the three months ended December 31, 2024, no shares were repurchased.
Unregistered sales of equity securities and use of proceeds
None.
Stock performance graph
The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that we specifically request that such information be treated as "soliciting material" or specifically incorporate such information by reference into such a filing.
The performance graph below compares the cumulative five-year total returns to our common stockholders relative to the cumulative total returns on the Standard and Poor's 500 Index (the "S&P 500") and the Standard and Poor's Oil & Gas Exploration & Production Select Industry Index (the "S&P O&G E&P"). The comparison was prepared based upon the following assumption:
1. $100 was invested in our common stock, the S&P 500 and the S&P O&G E&P from December 31, 2019 to December 31, 2024.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved]
Not applicable.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations is for the year ended December 31, 2024 compared to 2023, and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Annual Report. Additionally, see "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our 2023 Annual Report on Form 10-K filed on March 11, 2024 for discussion and analysis of our financial condition and results of operations for the year ended December 31, 2023 compared to 2022. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please see "Cautionary Statement Regarding Forward-Looking Statements" and "Part I, Item 1A. Risk Factors." Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of our derivative transactions.
Executive overview
We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties in the Permian Basin of West Texas. In the past two years, we have grown primarily through multiple strategic acquisitions.
Throughout the majority of the fourth quarter of 2024, we were operating five drilling rigs and one completions crew. Throughout 2025, we expect to operate four to six drilling rigs and one to three completions crews. Our capital investments for full-year 2025 are expected to be in the approximate range of $825.0 million to $925.0 million. However, we will continue to monitor commodity prices and service costs and adjust activity levels in order to proactively manage our cash flows and preserve liquidity. Below is a summary of our financial and operating performance for the year ended December 31, 2024:
•Net loss of $173.5 million, which included a non-cash impairment loss on oil and gas properties of $481.3 million
•Oil, NGL and natural gas sales of $1.9 billion
•Oil sales volumes of 22,585 MBbl and oil production of 61,708 Bbl/D
•Oil equivalent sales volumes of 48,987 MBOE and total production of 133,845 BOE/D
•Capital investments of $895.9 million, excluding non-budgeted acquisition costs
•Proved developed and undeveloped reserves of 455,275 MBOE as of December 31, 2024. See Unaudited Supplementary Information, included elsewhere in this Annual Report, for discussion on changes in our estimated proved reserve quantities of oil, NGL and natural gas.
Recent developments
2024 Acquisitions
On September 20, 2024, we, together with Northern Oil and Gas, Inc. ("NOG"), purchased certain oil and natural gas properties located in the Delaware Basin with an effective date of April 1, 2024 from Point Energy Partners Petroleum, LLC, Point Energy Partners Operating, LLC, Point Energy Partners Water, LLC and Point Energy Partners Royalty, LLC (collectively, “Point”) for an aggregate purchase price of $1.0 billion in cash, including customary closing adjustments (the "Point Acquisition"). We purchased 80% of the acquired assets, consisting of approximately 16,300 net acres in Ward and Winkler Counties, and will operate the assets, and NOG purchased the remaining 20% of the assets. Our portion of the aggregate preliminary purchase price was $827.0 million, which consisted of (i) $805.1 million in cash and (ii) $21.9 million of estimated transaction-related expenses. The purchase price is subject to additional post-closing adjustments, and was funded entirely with borrowings under our Senior Secured Credit Facility. Upon closing of the Point Acquisition, we entered into the Thirteenth Amendment to our Senior Secured Credit Facility, which, among other things, increased our aggregate elected commitment to $1.5 billion.
On February 2, 2024, we purchased additional working interests in producing properties associated with the Henry Acquisition (as defined herein), with an effective date of August 1, 2023 through PEP Henry Production Partners LP, PEP HPP Jubilee SPV
LP, PEP PEOF Dropkick SPV, LLC, PEP HPP Dropkick SPV LP and HPP Acorn SPV LP. The aggregate purchase price of $77.6 million consisted of (i) 878,690 shares of the Company's common stock, (ii) 980,272 shares of the Company's Preferred Stock, (iii) $1.8 million cash consideration received for closing adjustments and (iv) $0.7 million in transaction-related expenses.
See Note 4 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our 2024 acquisitions.
Financing transactions
In March and April of 2024, we issued a total of $1.0 billion in aggregate principal amount of 7.875% senior unsecured notes due 2032, from which we received net proceeds of approximately $983.5 million. The net proceeds were used to (i) fully extinguish the outstanding 10.125% senior unsecured notes due 2028, (ii) reduce the outstanding principal amount of the 9.750% senior unsecured notes due 2030 and (iii) repay a portion of the outstanding borrowings on the Senior Secured Credit Facility. See Note 7 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our debt and financing transactions.
Commodity prices, reserves and full cost ceiling test
Commodity prices
Our results of operations are heavily influenced by oil, NGL and natural gas prices. Commodity prices have historically been volatile. While general economic concerns continue to place some downward pressure on commodity prices, worldwide commodity demand continues to rise. Although supply has increased, it has been constrained and pricing has been affected, in part, by the impact of the world political and economic environment. Any of the above factors could change or reverse, and global commodity and financial markets remain subject to heightened levels of uncertainty and volatility.
With natural gas production in the Permian Basin at all-time highs, transportation capacity to market hubs for our natural gas production provided by existing natural gas pipelines has been generally constrained. During this time of natural gas pipeline capacity constraint, our sales price for natural gas has been lower than historical trends and may, at times, including in 2024, be negative.
We maintain an active commodity derivatives strategy to minimize commodity price volatility and support cash flows for operations. We have entered into a number of commodity derivative contracts that have enabled us to offset a portion of the changes in our cash flow caused by fluctuations in price and basis differentials for our sales of oil, NGL and natural gas, as discussed in "Item 7A. Quantitative and Qualitative Disclosures About Market Risk." See Notes 11 and 12 to our consolidated financial statements included elsewhere in this Annual Report for additional discussion of our commodity derivatives. Notwithstanding our derivatives strategy, another collapse in commodity prices may affect the economic viability of, and our ability to fund, our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves. See "Critical accounting estimates" for further discussion of our oil, NGL and natural gas reserve quantities and standardized measure of discounted future net cash flows.
Reserves and full cost ceiling test
We use the full cost method of accounting for our oil and natural gas properties, with the full cost ceiling based principally on the estimated future net cash flows from our proved oil, NGL and natural gas reserves, which exclude the effect of our commodity derivative transactions, discounted at 10% under required SEC guidelines for pricing methodology. We review the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC on a quarterly basis. In the event the unamortized cost, or net book value, of our evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, the excess is expensed in the period such excess occurs. Once incurred, a write-down of evaluated oil and natural gas properties is not reversible and constitutes a non-cash charge to earnings.
Our reserves are reported in three streams: oil, NGL and natural gas. The Realized Prices, which are utilized to value our proved reserves and calculated using the average first-day-of-the-month prices for each month within the 12-month period prior to the end of the reporting period, adjusted for factors affecting price received at the delivery point, as of December 31, 2024 were $76.76 for oil, $13.66 for NGL and $0.85 for natural gas. The unamortized cost of evaluated oil and natural gas
properties being depleted exceeded the full cost ceiling for the fourth quarter of 2024. Accordingly, we recorded a $481.3 million full cost impairment for the year ended December 31, 2024. The unamortized cost of evaluated oil and natural gas properties being depleted did not exceed the full cost ceiling during 2023 and, as such, no full cost ceiling impairment was recorded during the year ended December 31, 2023.
If prices remain at or below the current levels, subject to numerous factors and inherent limitations, some of which are discussed below, and all other factors remain constant, we could incur additional material non-cash full cost ceiling impairments in future quarters, which would have an adverse impact on our financial results. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, changes in oilfield service costs, potential recognition of additional proved undeveloped reserves, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. Also, purchases of proved properties may be recorded at a cost that exceeds the related increase in the full cost ceiling calculation as acquisitions are generally recorded at fair value based on expected future prices and other factors that may differ from historical prices used in the full cost ceiling test, among other factors.
In our upcoming first-quarter calculation to value our proved reserves, the January 2024 first-day-of-the-month oil price of $71.65 per Bbl will be replaced by the January 2025 first-day-of-the-month oil price of $71.72 per Bbl and February 2024 first-day-of-the-month oil price of $73.82 per Bbl will be replaced by the February 2025 first-day-of-the-month oil price of $72.53 per Bbl. If the February 2025 commodity prices are used for March 2025 as well, the projected trailing 12-month average prices for our first-quarter calculation would be $76.00 per Bbl for oil, $13.62 per Bbl for NGL and $0.99 per Mcf for natural gas under SEC guidelines for pricing methodology. Utilizing these prices, with all other factors remaining constant with our fourth-quarter 2024 calculation, we would have an implied impairment of our oil and natural gas properties of approximately $150 million in the first quarter of 2025. See Notes 2 and 6 to our consolidated financial statements included elsewhere in this Annual Report for discussion of the full cost method of accounting and our Realized Prices, respectively.
Results of operations
Revenues
Sources of our revenue
Our revenues are primarily derived from the sale of produced oil, NGL and natural gas, all within the continental U.S. and do not include the effects of derivatives.
The following table presents our composition of produced oil, NGL and natural gas revenue by product for the periods presented:
Years ended December 31,
2024 2023
Oil sales 89 % 87 %
NGL sales 10 % 9 %
Natural gas sales 1 % 4 %
Total 100 % 100 %
Oil, NGL and natural gas sales volumes, revenues and prices
The following table presents information regarding our oil, NGL and natural gas sales volumes, sales revenues and average sales prices for the periods presented and corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
2024 2023 Change (#) Change (%)
Sales volumes:
Oil (MBbl) 22,585 16,894 5,691 34 %
NGL (MBbl) 13,270 9,128 4,142 45 %
Natural gas (MMcf) 78,794 55,404 23,390 42 %
Oil equivalents (MBOE)(1)
48,987 35,256 13,731 39 %
Average daily oil equivalent sales volumes (BOE/D)(1)
133,845 96,591 37,254 39 %
Average daily oil sales volumes (Bbl/D)(1)
61,708 46,284 15,424 33 %
Sales revenues (in thousands):
Oil $ 1,728,971 $ 1,328,518 $ 400,453 30 %
NGL 190,775 136,901 53,874 39 %
Natural gas 15,544 63,214 (47,670) (75) %
Total oil, NGL and natural gas sales revenues $ 1,935,290 $ 1,528,633 $ 406,657 27 %
Average sales prices(1):
Oil ($/Bbl)(2)
$ 76.55 $ 78.64 $ (2.09) (3) %
NGL ($/Bbl)(2)
$ 14.38 $ 15.00 $ (0.62) (4) %
Natural gas ($/Mcf)(2)
$ 0.20 $ 1.14 $ (0.94) (82) %
Average sales price ($/BOE)(2)
$ 39.51 $ 43.36 $ (3.85) (9) %
Oil, with commodity derivatives ($/Bbl)(3)
$ 76.56 $ 76.99 $ (0.43) (1) %
NGL, with commodity derivatives ($/Bbl)(3)
$ 14.29 $ 15.00 $ (0.71) (5) %
Natural gas, with commodity derivatives ($/Mcf)(3)
$ 0.95 $ 1.34 $ (0.39) (29) %
Average sales price, with commodity derivatives ($/BOE)(3)
$ 40.70 $ 42.87 $ (2.17) (5) %
_____________________________________________________________________________
(1)The numbers presented in the years ended December 31, 2024 and 2023 columns are based on actual amounts and may not recalculate using the rounded numbers presented in the table above or the table below.
(2)Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point.
(3)Price reflects the after-effects of our commodity derivative transactions on our average sales prices. Our calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods.
The following table presents net settlements received or paid for matured commodity derivatives and net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the periods utilized in our calculation of the average sales prices, with commodity derivatives, for the periods presented and corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
(in thousands) 2024 2023 Change ($) Change (%)
Net settlements received (paid) for matured commodity derivatives:
Oil $ 164 $ (27,860) $ 28,024 101 %
NGL (1,162) - (1,162) N/A
Natural gas 59,320 10,792 48,528 450 %
Total $ 58,322 $ (17,068) $ 75,390 442 %
Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the years ended December 31, 2024 and 2023:
(in thousands) Oil NGL Natural gas Total
2023 Revenues $ 1,328,518 $ 136,901 $ 63,214 $ 1,528,633
Effect of changes in average sales prices (47,104) (8,251) (74,357) (129,712)
Effect of changes in sales volumes 447,557 62,125 26,687 536,369
2024 Revenues $ 1,728,971 $ 190,775 $ 15,544 $ 1,935,290
Change ($) $ 400,453 $ 53,874 $ (47,670) $ 406,657
Change (%) 30 % 39 % (75) % 27 %
The following table presents sales of purchased oil and other operating revenues for the periods presented and corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
(in thousands) 2024 2023 Change ($) Change (%)
Sales of purchased oil $ 12,745 $ 14,313 $ (1,568) (11) %
Sales of purchased oil are a function of the volumes and prices of purchased oil sold to customers and are offset by the volumes and costs of purchased oil. We are a firm shipper on the Gray Oak pipeline and we may elect to utilize purchased oil to fulfill portions of our commitments. During the second half of 2024, we utilized purchased oil to fulfill portions of our commitments in excess of our lease production. The continuance of this practice in the future is based upon, among other factors, our pipeline capacity as a firm shipper and the quantity of our lease production which may contribute to our pipeline commitments. We expect to fulfill our Gray Oak pipeline commitments primarily with our lease production in the foreseeable future.
Costs and expenses
Costs and expenses and average costs and expenses per BOE sold
The following table presents select information regarding costs and expenses and selected average costs and expenses per BOE sold for the periods presented and corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
(in thousands except for per BOE sold data) 2024 2023 Change ($) Change (%)
Costs and expenses:
Lease operating expenses $ 448,078 $ 261,129 $ 186,949 72 %
Production and ad valorem taxes 117,947 93,224 24,723 27 %
Oil transportation and marketing expenses 44,843 41,284 3,559 9 %
Gas gathering, processing and transportation expenses 17,825 2,013 15,812 785 %
Costs of purchased oil 13,243 15,065 (1,822) (12) %
General and administrative (excluding LTIP and transaction expenses) 85,656 79,712 5,944 7 %
General and administrative (LTIP):
LTIP cash 2,206 3,972 (1,766) (44) %
LTIP non-cash 13,168 9,794 3,374 34 %
General and administrative (transaction expenses) 548 11,341 (10,793) (95) %
Organizational restructuring expenses 795 1,654 (859) (52) %
Depletion, depreciation and amortization 741,966 463,244 278,722 60 %
Impairment expense 481,305 - 481,305 N/A
Other operating expenses, net 8,799 6,223 2,576 41 %
Total costs and expenses $ 1,976,379 $ 988,655 $ 987,724 100 %
Selected average costs and expenses per BOE sold(1):
Lease operating expenses $ 9.15 $ 7.41 $ 1.74 23 %
Production and ad valorem taxes 2.41 2.64 (0.23) (9) %
Oil transportation and marketing expenses 0.92 1.17 (0.25) (21) %
Gas gathering, processing and transportation expenses 0.36 0.06 0.30 500 %
General and administrative (excluding LTIP and transaction costs) 1.75 2.26 (0.51) (23) %
Total selected operating expenses $ 14.59 $ 13.54 $ 1.05 8 %
General and administrative (LTIP):
LTIP cash $ 0.05 $ 0.11 $ (0.06) (55) %
LTIP non-cash $ 0.27 $ 0.28 $ (0.01) (4) %
General and administrative (transaction expenses) $ 0.01 $ 0.32 $ (0.31) (97) %
Depletion, depreciation and amortization $ 15.15 $ 13.14 $ 2.01 15 %
____________________________________________________________________________
(1)Selected average costs and expenses per BOE sold are based on actual amounts and may not recalculate using the rounded numbers presented in the table above.
Lease operating expenses ("LOE")
LOE, which includes workover expenses, increased for the year ended December 31, 2024 compared to 2023. LOE are daily expenses incurred to bring oil, NGL and natural gas out of the ground and to market, together with the daily expenses incurred to maintain our producing properties. Such costs also include maintenance, repairs and non-routine workover expenses related to our oil and natural gas properties. LOE increased during 2024 primarily due to our acquisitions of oil and natural gas properties in 2023 and 2024. We continue to focus on economic efficiencies associated with the usage and
procurement of products and services related to LOE. Workover expense for the year ended December 31, 2024 was $71.8 million, which was a 95% increase compared to the same period in 2023.
Production and ad valorem taxes
Production and ad valorem taxes increased for the year ended December 31, 2024 compared to 2023 due to increased oil and NGL revenues. Production taxes are based on and fluctuate in proportion to our oil, NGL and natural gas sales revenues, and are established by federal, state or local taxing authorities. We take advantage of all credits and exemptions in our various taxing jurisdictions. Ad valorem taxes are based on and fluctuate in proportion to the taxable value assessed by the various counties where our oil and natural gas properties are located.
Oil transportation and marketing expenses
Oil transportation and marketing expenses are expenses incurred for the delivery of produced oil to customers in the U.S. Gulf Coast market via the Gray Oak pipeline. We ship the majority of our produced oil to the U.S. Gulf Coast, which we believe provides long-term pricing advantages versus the Midland market. Additionally, firm transportation payments on excess pipeline capacity associated with transportation agreements are also included in oil transportation and marketing expenses. See Note 15 to our consolidated financial statements included elsewhere in this Annual Report for additional discussion of our transportation commitments. Oil transportation and marketing expenses increased for the year ended December 31, 2024 compared to 2023 primarily due to increases in transportation expenses of $7.6 million, as our oil production has increased, partially offset by a decrease in firm transportation payments on excess capacity of $3.8 million.
Gas gathering, processing and transportation expenses
Beginning in the third quarter of 2023, and continuing into 2024, we became party to certain natural gas processing agreements where the Company concluded it is the principal in the transaction and the customer is the ultimate third party, with control of the NGL or residue gas transferring at the tailgate of the midstream entity's processing plant. Revenue for such agreements is recognized on a gross basis, with gathering, processing and transportation fees presented as an expense on the consolidated statements of operations.
Costs of purchased oil
Costs of purchased oil are a function of the volumes and prices of purchased oil. We are a firm shipper on the Gray Oak pipeline, and in the event our long-haul transportation capacity on the Gray Oak pipeline exceeds our net production, we purchase third-party oil at the trading hubs to satisfy the deficit in our associated long-haul transportation commitments. During the first half of 2024, we had no costs of purchased oil due to fulfilling our Gray Oak pipeline commitments with our lease production. During the second half of 2024, we utilized purchased oil to fulfill portions of our commitments. We expect to fulfill our Gray Oak pipeline commitments primarily with our lease production in the foreseeable future.
General and administrative ("G&A")
G&A are expenses incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, non-production based franchise taxes, audit and other fees for professional services, legal compliance and equity-based compensation.
G&A, excluding employee compensation expense from our long-term incentive plan ("LTIP") and transaction expenses, increased for the year ended December 31, 2024 compared to 2023 primarily due to workforce and professional expenses in connection with the growth of the Company, partially offset by higher performance-related bonuses accrued for our workforce in 2023 as compared to 2024.
LTIP cash expense decreased for the year ended December 31, 2024 compared to 2023. This decrease is primarily due to (i) fluctuations in the fair value of our cash-settled performance share unit awards as a result of the performance of our stock and (ii) cash-settled performance share unit awards and employee cash retainer awards expensed through 2023, which fully vested during first-quarter 2024.
LTIP non-cash expense increased for the year ended December 31, 2024 compared to 2023, due to 2024 expense including restricted stock awards for a larger population of our workforce as compared to 2023. See Notes 2 and 9 to our consolidated financial statements included elsewhere in this Annual Report for information regarding our equity-based compensation.
Transaction expenses primarily represent incurred costs associated with the Henry Acquisition. See Note 4 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of the Henry Acquisition.
Organizational restructuring expenses
Organizational restructuring expenses are separation charges comprised of compensation, tax, professional, outplacement and insurance-related expenses, which are recorded as "Organizational restructuring expenses" on the consolidated statements of operations.
Depletion, depreciation and amortization ("DD&A")
The most significant component of DD&A for Vital Energy is depletion. The following table presents depletion expense per BOE sold for the periods presented and the corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
(in thousands) 2024 2023 Change ($) Change (%)
Depletion expense per BOE sold $ 14.70 $ 12.67 $ 2.03 16 %
Depletion expense per BOE increased for the year ended December 31, 2024 compared to 2023 primarily due to a decrease in reserves related to a drop in price and the impact of the Point Acquisition and the related future development costs for proved undeveloped wells. See Note 6 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding the full cost method of accounting.
Impairment expense
The full cost ceiling is based principally on the estimated future net revenues from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, discounted at 10%. The Realized Prices are utilized to calculate the estimated future net revenues in the full cost ceiling calculation. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. The unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling during the quarterly period ended December 31, 2024. Accordingly, the Company recorded a $481.3 million full cost ceiling impairment, which is included in "Impairment expense" on the consolidated statements of operations for the year ended December 31, 2024. See Note 6 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding our full cost ceiling calculation.
Non-operating income (expense)
The following table presents the components of non-operating income (expense), net for the periods presented and corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
(in thousands) 2024 2023 Change ($) Change (%)
Gain on derivatives, net $ 38,140 $ 96,230 $ (58,090) (60) %
Interest expense (177,794) (149,819) (27,975) (19) %
Loss on extinguishment of debt, net (66,115) (4,039) (62,076) (1,537) %
Other income, net 7,060 9,748 (2,688) (28) %
Total non-operating expense, net $ (198,709) $ (47,880) $ (150,829) (315) %
Gain on derivatives, net
The following table presents the components of gain on derivatives, net for the periods presented and corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
(in thousands) 2024 2023 Change ($) Change (%)
Non-cash gain (loss) on derivatives, net $ (20,182) $ 111,485 $ (131,667) (118) %
Settlements received (paid) for matured derivatives, net 58,322 (17,068) 75,390 442 %
Other, net - 1,813 (1,813) (100) %
Gain on derivatives, net $ 38,140 $ 96,230 $ (58,090) (60) %
Non-cash gain (loss) on derivatives, net is the result of new and matured contracts, including contingent consideration derivatives for the period subsequent to the initial valuation date and through the end of the contingency period, and the changing relationship between our outstanding contract prices and the future market prices in the forward curves, which we use to calculate the fair value of our derivatives. In general, if outstanding commodity contracts are held constant, we experience gains during periods of decreasing market prices and losses during periods of increasing market prices.
Settlements received (paid) for matured derivatives, net are for our (i) commodity derivatives, which are based on the settlement prices compared to the prices specified in the derivative contracts and (ii) contingent consideration derivatives.
We classify the derivative gains as operating activities and cash received for contingent consideration derivatives as investing activities in our consolidated statements of cash flows. See Notes 2, 4, 11, 12 and 18 to our consolidated financial statements included elsewhere in this Annual Report and see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" below for additional information regarding our derivatives.
Interest expense
Interest expense increased for the year ended December 31, 2024 compared to 2023. We reflect interest paid to the lenders and bondholders in interest expense, net of amounts capitalized. In addition, we include the amortization of: (i) debt issuance costs, which includes origination, amendment and professional fees, (ii) commitment fees and (iii) annual agency fees in interest expense. The increase during the year ended December 31, 2024 is due to new senior unsecured notes issued during the third quarter of 2023 and the first half of 2024, and increased borrowings under our Senior Secured Credit Facility related to funding of the Point Acquisition. See Note 7 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding our debt and interest expense.
Loss on extinguishment of debt, net
During the year ended December 31, 2024, we recognized a loss on extinguishment of debt of $66.1 million. During the first quarter of 2024, we settled cash tender offers on the January 2028 Notes and 2030 Notes and redeemed the remaining principal amount outstanding on the January 2028 Notes. The related loss on extinguishment of debt during the year ended December 31, 2024 consisted of early tender and redemption premiums and write-offs of debt issuance costs, premiums and discounts. See Note 7 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding our long-term debt.
Income tax benefit (expense)
The following table presents income tax benefit (expense) for the periods presented and corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
(in thousands) 2024 2023 Change ($) Change (%)
Current $ (2,456) $ (5,723) $ 3,267 57 %
Deferred 50,196 189,060 (138,864) (73) %
Income tax benefit (expense) $ 47,740 $ 183,337 $ (135,597) (74) %
We are subject to federal and state income taxes and the Texas franchise tax. For the year ended December 31, 2024, we recognized a combined United States federal and state income tax benefit of $47.7 million. The current income tax expense in both periods presented is attributable to Texas Franchise tax. See Note 13 to our consolidated financial statements included elsewhere in this Annual Report for additional discussion of our income taxes.
Management considered evidence, both positive and negative, and determined it is more-likely-thannot that a portion of our federal deferred tax assets are realizable which resulted in the release of the federal valuation allowance and preservation of the Oklahoma valuation allowance in 2023. Management reviews new evidence, both positive and negative, for each reporting period that could impact our judgement on the realizability of our deferred tax assets. As of December 31, 2024, management concluded that our federal deferred tax assets are more-likely-than-not to be realized and continue to maintain a full valuation allowance with respect to Oklahoma.
As of December 31, 2024, we had approximately $239.7 million in net deferred tax assets, which includes a $206.8 million deferred tax asset related to net operating loss ("NOL") carryforwards that can be used to offset taxable income in future periods and reduce our income taxes payable in those future periods. Some of these NOL carryforwards will expire if they are not used within certain periods. At this time, we consider it more-likely-than-not that we will have sufficient taxable income in the future that will allow the utilization of these NOL carryforwards and realize these deferred tax assets. However, it is possible that some or all of these NOL carryforwards could ultimately expire unused and prevent us from realizing the full value of the deferred tax assets. Our assessment relies on the ability to forecast sufficient taxable income from our operations; however, any future impairments as a result of the full cost ceiling limitation may limit that reliance. As a result, a full or partial valuation allowance to reduce our deferred tax assets may be required, which would materially increase our expenses in the period the allowance is recognized.
As of December 31, 2024, we have federal NOL carryforwards of $897.0 million of which $530.2 million will begin to expire in 2035, and the remaining NOL carryforwards of $366.8 million will not expire but may be limited in future periods. If we were to experience an “ownership change” as determined under Section 382 of the Internal Revenue Code, our ability to offset taxable income arising after the ownership change with net operating losses arising prior to the ownership change may be significantly limited. Based on information available as of December 31, 2024, no such ownership change has occurred.
Liquidity and capital resources
Historically, our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from debt offerings, borrowings under our Senior Secured Credit Facility and proceeds from asset dispositions. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties and infrastructure development.
We continually seek to maintain a financial profile that provides operational flexibility and monitor the markets to consider which financing alternatives, including debt and equity capital resources, joint ventures and asset sales, are available to meet our future planned capital expenditures, a significant portion of which we are able to adjust and manage. We also continually evaluate opportunities with respect to our capital structure, including issuances of new securities, as well as transactions involving our outstanding senior notes, which could take the form of open market or private repurchases, exchange or tender offers, or other similar transactions, and our common stock, which could take the form of open market or private repurchases. We may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. Such financing alternatives, or combination of alternatives, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. We continually look for other opportunities to maximize stockholder value. For further discussion of our financing activities related to debt instruments, see Notes 7 and 18 to our consolidated financial statements included elsewhere in this Annual Report.
Due to the inherent volatility in the prices of oil, NGL and natural gas and the sometimes wide pricing differentials between where we produce and sell such commodities, we engage in commodity derivative transactions to hedge price risk associated with a portion of our anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. Due to the inherent volatility in interest rates, we may, from time to time, enter into interest rate derivative swaps to hedge interest rate risk associated with our debt under the Senior Secured Credit Facility. As of December 31, 2024, the Company has not entered
into any interest rate derivative swaps, and therefore our outstanding debt balance under our Senior Secured Credit Facility is subject to interest rate fluctuations. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" below. See Notes 11 and 18to our consolidated financial statements included elsewhere in this Annual Report for discussion of our open commodity positions.
As of December 31, 2024, we had cash and cash equivalents of $40.2 million and available capacity under the Senior Secured Credit Facility of $620.0 million, resulting in total liquidity of $660.2 million. As of February 19, 2025, we had outstanding borrowings under our Senior Secured Credit Facility of $855.0 million, resulting in available capacity of $645.0 million. We believe that our operating cash flows and the aforementioned liquidity sources provide us with sufficient liquidity and financial resources to manage our cash needs and contractual obligations, to implement our currently planned capital expenditure budget and, at our discretion, fund any share repurchases, pay down, repurchase or refinance debt or adjust our planned capital expenditure budget. See Note 18 to our consolidated financial statements included elsewhere in this Annual Report for additional discussion of additional borrowings and repayments on the Senior Secured Credit Facility subsequent to December 31, 2024.
Cash requirements for known contractual and other obligations
The following table presents significant cash requirements for known contractual and other obligations as of December 31, 2024:
(in thousands) Short-term Long-term Total
Senior unsecured notes(1)
$ 131,342 $ 2,352,302 $ 2,483,644
Senior Secured Credit Facility(2)
- 880,000 880,000
Electricity purchase commitments 20,288 166,674 186,962
Operating lease commitments(3)
78,176 32,998 111,174
Asset retirement obligations 6,551 82,941 89,492
Sand purchase commitments 24,296 16,470 40,766
Firm transportation commitments 18,133 22,605 40,738
Total $ 278,786 $ 3,553,990 $ 3,832,776
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(1)Amounts presented include both principal and interest obligations.
(2)Amounts presented do not include interest expense as it is a floating rate and we cannot determine with accuracy the future interest rates we will be charged. As of December 31, 2024, the outstanding balance under our Senior Secured Credit Facility was subject to a weighted-average interest rate of 7.240%.
(3)Amounts presented include both minimum lease payments and imputed interest.
We expect to satisfy our short-term contractual and other obligations with cash flows from operations. See Notes 2, 5, 7, 15 and 18 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our known contractual and other obligations.
Cash flows
The following table presents our cash flows for the periods presented and corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
(in thousands) 2024 2023 Change ($) Change (%)
Net cash provided by operating activities $ 1,000,330 $ 812,956 $ 187,374 23 %
Net cash used in investing activities (1,737,591) (1,476,130) (261,461) (18) %
Net cash provided by financing activities 763,379 632,800 130,579 (21) %
Net increase (decrease) in cash and cash equivalents $ 26,118 $ (30,374) $ 56,492 186 %
Cash flows from operating activities
Net cash provided by operating activities increased during the year ended December 31, 2024, compared to 2023. Notable cash changes include (i) an increase in total oil, NGL and natural gas sales revenues of $406.7 million, (ii) an increase of $76.0 million due to changes in net settlements received for matured derivatives, mainly due to decreases in commodity prices and (iii) a decrease of $56.4 million due to net changes in operating assets and liabilities. Other significant changes include increases in lease operating expense and production and ad valorem taxes. See "-Results of operations" for additional discussion of our oil, NGL and natural gas sales revenues, derivatives and expenses.
Our operating cash flows are sensitive to a number of variables, the most significant of which are the volatility of oil, NGL and natural gas prices, mitigated to the extent of our commodity derivatives' exposure, and sales volume levels. Regional and worldwide economic activity, weather, infrastructure, transportation capacity to reach markets, costs of operations, legislation and regulations, including potential government production curtailments, and other variable factors significantly impact the prices of these commodities. For additional information on risks related to our business, see "Part I. Item 1A. Risk Factors" and "Part I. Item 7a. Quantitative and Qualitative Disclosures About Market Risk" included elsewhere in this Annual Report.
Cash flows from investing activities
Net cash used in investing activities increased during the year ended December 31, 2024, compared to 2023, primarily due to an increase in capital expenditures as a result of increased drilling and completions activity in 2024. See Note 4 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our acquisitions and divestiture of oil and natural gas properties.
Expected capital investments
We currently expect capital investments for 2025 to be in the approximate range of $825.0 million to $925.0 million. We will continue to monitor commodity prices and service costs and adjust activity levels in order to proactively manage our cash flows and preserve liquidity. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
The following table presents the components of our capital investments, excluding non-budgeted acquisition costs, for the periods presented and corresponding changes for such periods:
Years ended December 31, 2024 compared to 2023
(in thousands) 2024 2023 Change ($) Change (%)
Oil and natural gas properties(1)
$ 873,637 $ 663,025 $ 210,612 32 %
Midstream and other fixed assets 22,276 15,601 6,675 43 %
Total capital investments, excluding non-budgeted acquisition costs $ 895,913 $ 678,626 $ 217,287 32 %
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(1)See Unaudited Supplementary Information included elsewhere in this Annual Report for additional information regarding our capital investments in the exploration and development of oil and natural gas properties.
The amount, timing and allocation of capital investments are largely discretionary and within management's control. If oil, NGL and natural gas prices are below our acceptable levels, or costs are above our acceptable levels, we may choose to defer a portion of our capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continually monitor and may adjust our projected capital expenditures in response to world developments, as well as success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs and supplies, changes in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.
Cash flows from financing activities
Net cash provided by financing activities was $763.4 million during the year ended December 31, 2024, compared to $632.8 million during the year ended December 31, 2023. Notable 2024 activity includes (i) borrowings on our Senior Secured Credit Facility of $1.8 billion, (ii) proceeds from the issuance of our senior unsecured notes of $1.0 billion, (iii) payments on our Senior Secured Credit Facility of $1.0 billion, (iv) extinguishment of certain senior unsecured notes of $952.2 million and (v) payments for debt issuance costs of $22.1 million. For further discussion of our financing activities related to debt instruments, see Notes 7 and 18 to our consolidated financial statements included elsewhere in this Annual Report. For further discussion of our financing activities related to stockholders' equity, see Note 8 to our consolidated financial statements included elsewhere in this Annual Report.
Sources of liquidity
During the years ended December 31, 2024 and 2023, our sources of liquidity have been cash flows from operations, borrowings under our Senior Secured Credit Facility and proceeds from debt and equity offerings.
Senior Secured Credit Facility
As of December 31, 2024, our Senior Secured Credit Facility, which matures on September 13, 2027, had a maximum credit amount of $3.0 billion, a borrowing base and an aggregate elected commitment of of $1.5 billion, with $880.0 million outstanding, and was subject to an interest rate of 7.240%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which we were in compliance with for all periods presented. The Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. As of December 31, 2024 and 2023, we had no letters of credit outstanding under the Senior Secured Credit Facility.
See Notes 7 and 18 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our Senior Secured Credit Facility.
Supplemental Guarantor information
As of December 31, 2024, approximately $1.6 billion of our senior unsecured notes remained outstanding. Our wholly-owned subsidiary Vital Midstream Services, LLC ("VMS") (the "Guarantor"), jointly and severally, and fully and unconditionally, guarantees all of our outstanding senior unsecured notes.
The guarantees are senior unsecured obligations of the Guarantor and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor. The guarantees of the senior unsecured notes by the Guarantor are subject to certain Releases. The obligations of the Guarantor under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. Further, the rights of holders of the senior unsecured notes against the Guarantor may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Vital Energy is not restricted from making investments in the Guarantor and the Guarantor is not restricted from making intercompany distributions to Vital.
The assets, liabilities and results of operations of the combined issuer and the Guarantor are not materially different than the corresponding amounts presented in our consolidated financial statements included elsewhere in this Annual Report. Accordingly, we have omitted the summarized financial information of the issuer and the Guarantor that would otherwise be required.
Critical accounting estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different
conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements.
In management's opinion, the most critical accounting estimates impacted by our judgments and estimates are (i) volumes of our reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties and (iii) fair values of assets acquired and liabilities assumed in a business combination.
There have been no material changes in our critical accounting estimates during the year ended December 31, 2024.
Oil, NGL and natural gas reserve quantities and values and standardized measure of discounted future net cash flows
On an annual basis, our independent reserve engineers prepare the estimates of oil, NGL and natural gas reserves and associated future net cash flows. The SEC has defined proved reserves as the estimated quantities of oil, NGL and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions at SEC pricing. The process of estimating oil, NGL and natural gas reserves is complex, requiring significant judgment in the evaluation of available geological, geophysical, engineering and economic data. In general, our estimates of future reserve volumes and associated future net cash flows are primarily based on historical production on a well-to-well or property-to-property basis under existing economic and operating conditions. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing prices and economic conditions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. As a result, material revisions to existing reserve estimates and associated future net cash flows occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective assumptions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets under the full cost ceiling test that may be material. See Unaudited Supplementary Information included elsewhere in this Annual Report for additional discussion of our net proved oil, NGL and natural gas reserves and standardized measure of discounted future net cash flows, respectively.
Business combinations
As part of our business strategy, we actively pursue the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of evaluated and unevaluated oil and natural gas properties, which are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net cash flows of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. Changes in key assumptions may cause the accounting for business combinations to be revised, including the recognition of additional goodwill or discount on acquisition. See Note 4 to our consolidated financial statements included elsewhere in this Annual Report for additional discussion of our 2023 business combination.
New accounting standards
We considered the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the Accounting Standards Codification.
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires more detailed tax disclosures, including disaggregated information about an entity's effective tax rate reconciliation as well as expanded information on income taxes paid by jurisdiction. The amendments in this accounting standard are effective, on a prospective basis, for fiscal years beginning after December 15, 2024. Early adoption is permitted. Adoption of this ASU will result in additional disclosure, but will not impact the Company’s consolidated financial position, results of operations or cash flows.
In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which requires additional disclosure about specific types of expenses included in the expense captions presented on the income statement. The amendments in this accounting standard are effective, on a prospective basis, for fiscal years beginning after December 15, 2026, and interim periods beginning after December 15, 2027. Early adoption is permitted. Adoption of this ASU will result in additional disclosure, but will not impact the Company's consolidated financial position, results of operations or cash flows.
During the year ended December 31, 2024, the Company adopted ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which sets forth improvements to the current segment disclosure requirements in accordance with Topic 280 "Segment Reporting," including clarifying that entities with a single reportable segment are subject to both new and existing segment reporting requirements. ASU 2023-07 is effective for interim periods beginning after December 15, 2024, and is applied retrospectively to all periods presented in this Annual Report. Adoption of this ASU results in additional disclosure, but did not impact the Company's consolidated financial position, results of operations or cash flows. See Note 17 for additional information.
Inflation and interest rates
Drilling and completions costs and costs of oilfield services, equipment and materials began to rise in 2021 and continued to persist at elevated levels in 2022 and 2023. In addition to the effect of such inflationary pressures on our operating and capital costs, elevated interest rates as a result of the Federal Reserve’s tightening monetary policy have increased our borrowing costs on debt under our Senior Secured Credit Facility and may limit our ability to access debt capital markets. While the Federal Reserve has signaled cuts in interest rates for 2025, additional increases in interest rates have the potential to increase our costs of borrowing even more. We remain committed to our ongoing efforts to increase the efficiency of our operations and improve costs, which may, in part, offset cost increases from inflation and reduce our borrowing needs.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk," in our case, refers to the risk of loss arising from adverse changes in oil, NGL and natural gas prices and in interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk-sensitive derivative instruments were entered into for hedging purposes, rather than for speculative trading.
Commodity price exposure
Due to the inherent volatility in oil, NGL and natural gas prices and the sometimes wide pricing differentials between where we produce and where we sell such commodities, we engage in commodity derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of our anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations.
The fair values of our open commodity positions are largely determined by the relevant forward commodity price curves of the indexes associated with our open derivative positions. The following table provides a sensitivity analysis of the projected incremental effect on income or loss before income taxes of a hypothetical 10% change in the relevant forward commodity price curves of the indexes associated with our open commodity positions as of December 31, 2024:
(in thousands) As of December 31, 2024
Commodity derivative asset position $ 113,909
Impact of a 10% increase in forward commodity prices $ (162,671)
Impact of a 10% decrease in forward commodity prices $ 162,671
See Notes 2, 11, 12 and 18 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our commodity derivatives.
Interest rate risk
Our Senior Secured Credit Facility bears interest at a floating rate and our senior unsecured notes bear interest at fixed rates. The interest rate on our Senior Secured Credit Facility as of December 31, 2024 was 7.240%. See Note 7 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our debt. The interest rate on borrowings may be based on an alternate base rate or term secured overnight financing rate ("Term SOFR"), at our option. Interest on alternate base rate loans is equal to the sum of (a) the highest of (i) the "prime rate" (as publicly announced by Wells Fargo Bank, N.A.) in effect on such day, (ii) the federal funds effective rate in effect on such day plus 0.5% and (iii) the Adjusted Term SOFR (as defined in our Senior Secured Credit Facility) for a one-month tenor in effect on such a day plus 1% and (b) the applicable margin. Interest on Term SOFR loans is equal to the sum of (a)(i) the Term SOFR (as defined in our Senior Secured Credit Facility) rate for such period plus (ii) the Term SOFR Adjustment (as defined in our Senior Secured Credit Facility) of 0.1% (in the case of clause (a), subject to a floor of 0%) plus (b) the applicable margin. The applicable margin varies from 1.25% to 2.25% on alternate base rate borrowings and from 2.25% to 3.25% on Term SOFR borrowings, in each case, depending on our utilization ratio. As of December 31, 2024, the applicable margin on our borrowings were 1.75% for alternate base rate borrowings and 2.75% for Term SOFR borrowings.
See Notes 7, 12 and 18 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of our debt.
Counterparty and customer credit risk
See Notes 14 and 15 to our consolidated financial statements included elsewhere in this Annual Report for discussion of credit risk and commitments and contingencies. See Notes 11, 12 and 18 to our consolidated financial statements included elsewhere in this Annual Report for discussion of our commodity derivatives.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
Our consolidated financial statements and supplementary financial data are included in this Annual Report beginning on page.
Management's report on internal control over financial reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting is a process designed under the supervision of the Company's Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles.
As of December 31, 2024, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria for effective internal control over financial reporting established in the 2013 "Internal Control - Integrated Framework," issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2024.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report, has issued their report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2024. The report, which expresses an unqualified opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2024, is included in this Item under the heading "Report of Independent Registered Public Accounting Firm."
Report of independent registered public accounting firm
To the Stockholders and the Board of Directors of Vital Energy, Inc.
Opinion on internal control over financial reporting
We have audited Vital Energy, Inc.'s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Vital Energy, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2024 consolidated financial statements of the Company and our report dated February 24, 2025 expressed an unqualified opinion thereon.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 24, 2025

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures.
Evaluation of disclosure controls and procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2024 at the reasonable assurance level.
Design and evaluation of internal control over financial reporting
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management has included a report of their assessment of the design and operating effectiveness of our internal controls over financial reporting as part of this Annual Report for the year ended December 31, 2024. Ernst & Young LLP, the Company's independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting. Management's report and the independent registered public accounting firm's attestation report are included in "Item 8. Financial Statements and Supplementary Data" in this Annual Report under the caption entitled "Management's Report on Internal Control Over Financial Reporting" and "Report of Independent Registered Public Accounting Firm," respectively, and are incorporated herein by reference.
Changes in internal control over financial reporting
There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
Rule 10b5-1 Trading Arrangement Changes
Certain of our officers and directors have trading arrangements for the sale or purchase of Vital Energy, Inc. common stock intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) of the Exchange Act. The following table summarizes changes to such arrangements during the three months ended December 31, 2024:
Name and title of
director or officer Type of change Date of adoption Date of termination Duration of trading arrangement Potential aggregate number of securities to be purchased (sold) pursuant to the trading arrangement
Mark Denny
Executive Vice President-General Counsel & Secretary
Adoption December 5, 2024 N/A March 31, 2025 (11,336)
Bryan Lemmerman
Executive Vice President and Chief Financial Officer
Adoption December 11, 2024 N/A March 14, 2025 (10,000)
Katie Hill
Senior Vice President and Chief Operating Officer
Adoption December 11, 2024 N/A March 31, 2025 (9,273)
Other than as described above, none of the Company's directors or officers adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the quarterly period ended December 31, 2024.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
Information regarding our Code of Conduct and Business Ethics, Code of Ethics For Senior Financial Officers and Corporate Governance Guidelines for our principal executive officer, principal financial officer and principal accounting officer are described in "Item 1. Business" in this Annual Report. Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 10 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.
William E. Albrecht
Independent Director since 2020 Committees: Compensation and Finance Age: 73
Other Current Public Company Directorships: Halliburton Company (Compensation Committee and Health, Safety and Environment Committee chair)
Education: Directorship Certified, National Association of Corporate Directors
Board Leadership Fellow, National Association of Corporate Directors
MS, University of Southern California
BS, United States Military Academy at West Point
Career Highlights: President, Moncrief Energy, LLC (current)
California Resources Corporation Non-Executive Chair of the Board
Vice President, Occidental Petroleum Corporation; President, Oxy Oil & Gas, Americas; President, Oxy Oil & Gas, USA
EOG Resources, Inc. Executive Officer
Tenneco Oil Company Petroleum Engineer
Mr. Albrecht has more than 40 years of experience in the domestic oil and gas industry. His engineering background provides him with the ability to fully comprehend, analyze and offer insights on the wide variety of technically challenging projects facing us as we develop our shale-play assets. In addition, his service in a variety of executive positions for oil and gas companies and as a director for large public companies brings extensive managerial and operational experience of upstream assets to our Board.
Mark Denny
Executive Vice President - General Counsel and Secretary since November 2023 Age: 44
Senior Vice President -General Counsel and Secretary from April 2019 to November 2023
Education: J.D., Georgetown University Law Center
B.S., Economics and Political Science, Vanderbilt University
Mr. Denny joined Vital Energy in February 2013. Prior to his most recent promotion to Executive Vice President, he served as Senior Vice President and General Counsel. Prior to joining Vital, Mr. Denny worked in-house at SEH Offshore, Inc. and Seahawk Drilling, Inc. Prior to that, Mr. Denny worked at the international law firms of Vinson & Elkins and Fried Frank.
John Driver
Independent Director since 2022 Committees: Audit and Finance Age: 60
Other Current Public Company Directorships: Broadway Financial Corp & City First Bank, N.A. (Audit, Governance, Risk & Compliance Committees)
Education: MBA, Tuck School of Business at Dartmouth College
BS, Industrial Engineering, Stanford University
Directorship Certified, National Association of Corporate Directors
Cybersecurity Oversight Certified, National Association of Corporate Directors
Career Highlights: Lynx Technology Chief Executive Officer (current)
PacketVideo Chief Operating Officer and Chief Marketing Officer
JoynIn Co-Founder and Chief Executive Officer
Serena Software Senior Director of Global Field Marketing
Sun Microsystems Group Manager of Field and Partner Marketing
Mr. Driver is a technology entrepreneur and innovator with leadership experience in large, public and privately- held multinational companies and early-stage startups. He has a foundation in software marketing and sales and direct experience in new product launches for first-to-market categories. Navigating complexity, delivering innovation, and creating new opportunities within the IoT (Internet of Things) market are hallmarks of his career. As CEO, he currently leads Lynx Technology, a digital media technology company he founded through a management buyout of the multinational Connected Home operations of PacketVideo, a subsidiary of NTT DOCOMO. Previously, Mr. Driver served as Chief Operating Officer and Chief Marketing Officer of PacketVideo, co-founder and Chief Executive Officer of JoynIn and in senior leadership roles for Serena Software and Sun Microsystems.
Frances Powell Hawes
Independent Director since 2018 Committees: Audit (Chair) and Nominating, Corporate Governance, Environmental, and Social ("NGE&S") Age: 70
Other Current Public Company Directorships: Archrock Inc. (Audit Committee chair and Governance and Sustainability Committee)
PGT Innovations, Inc. (Audit Committee)
Education: Texas-Certified Public Accountant
Strategic Financial Leadership Program in Executive Education, Dartmouth College
Director Professionalism Course, National Association of Corporate Directors
BBA, Accounting, University of Houston
CERT Certificate of Cybersecurity Oversight, Carnegie Mellon University, Software Engineering Institute
Career Highlights: New Process Steel, L.P. Chief Financial Officer
American Electric Technologies, Inc. Senior Vice President and Chief Financial Officer
NCI Building Systems, Inc. Chief Financial Officer, Executive Vice President and Treasurer
Grant Prideco, Inc. Chief Financial Officer and Treasurer
Weatherford International Ltd. Various positions of increasing responsibility, including Chief Accounting Officer, Vice President, Accounting and Controller
Ms. Powell Hawes has over 22 years of experience as a financial advisor and chief financial officer for both public and privately held companies. She is a highly experienced director with extensive knowledge of not only publicly traded energy companies, but also privately held companies in complementary markets. Her knowledge and management experience on the Audit Committee enhances the Board of Directors' decision-making process on all issues affecting the Company, and her strong
accounting and leadership background contributes significantly to the Board's understanding of the Company's strategic opportunities.
Katie Hill
Senior Vice President and Chief Operating Officer since November 2023 Age: 37
Education: M.S., Mechanical Engineering, University of Michigan College of Engineering
B.S., Mechanical Engineering, University of Michigan College of Engineering
Ms. Hill joined Vital Energy in September 2022 as VP-Operations and was promoted to Chief Operating Officer and the senior leadership team in November 2023. Prior to joining Vital Energy she served as Senior Vice President - Operations at Javelin Energy Partners, LLC for two years. Previously, she served for eight years at Chesapeake Energy in positions of increasing responsibility in operations. Ms. Hill began her career as an engineer with BP in 2008.
Jarvis V. Hollingsworth
Independent Director since 2020 Committees: Audit and NGE&S (Chair) Age: 62
Education: JD, University of Houston
BS, United States Military Academy at West Point
Career Highlights: Irradiant Partners, L.P. Vice Chairman (current)
Kayne Anderson Capital Advisors, L.P. Secretary/General Counsel Executive Committee and Board of Directors
Bracewell, LLP Partner Management and Finance Committees
Mr. Hollingsworth's service as General Counsel and Director of a leading alternatives investment advisor with approximately $10.1 billion in assets and service as Board Chairman for a Texas state agency that manages a $200 billion-plus pension fund highlight the legal and financial background that he brings to our Board. Mr. Hollingsworth is a former Partner at the law firm Bracewell LLP in Houston, Texas where he had a fiduciary practice counseling boards of directors and trustees on corporate governance and strategic matters. His legal, management and governance experience contribute significantly to our Board and our move to include ESG initiatives as part of the NGE&S Committee.
Dr. Craig M. Jarchow
Independent Director since 2019 Committees: Compensation (Chair) and Finance Age: 64
Other Current Private Company Directorships: TG Natural Resources, LLC
Education: Ph.D., Geophysics, Stanford University
MBA, MIT Sloan School of Management
MS, Geophysics, Stanford University
BA, Geology, University of California, Santa Barbara
Career Highlights: TG Natural Resources, LLC President, Chief Executive Officer and Director
Castleton Commodities International President, Upstream
Pine Brook Road Partners, LLC Managing Director and Partner
First Reserve Corporation Director and Partner
Amoco Corporation & Apache Corporation Operational roles of increasing responsibility
Dr. Jarchow has more than 30 years of industry experience serving in upstream operational roles for oil and gas companies, advising financial services firms on energy focused investments and building and leading an operating company. His geology and geophysics background combined with his managerial experience building and leading a company aides us in the development of our assets and the acquisition of new properties to expand our high margin inventory.
Dr. Shihab Kuran
Independent Director since 2022 Committees: Compensation and NGE&S Age: 55
Education: Ph.D., M.Sc., Electrical Engineering, City University of New York
B.Sc. Electrical Engineering, University of Jordan
The General Manager Program (TGMP), Harvard Business School
Directorship Certified, National Association of Corporate Directors
Digital Directors
Network 502 Systemic Cyber Risk Governance For U.S. Company Corporate Directors
Career Highlights: Power Edison Chief Executive Officer and Founder (current)
EV Edison Founder, Director and Executive Chairman
NRG Energy President of Strategic Development
Sun Edison President, Advanced Solutions
Petra Solar Founder, Director, President and Chief Executive Officer
Dr. Kuran is NACD Directorship Certified™. He is an investor, serial entrepreneur and an executive with over three decades of experience in the technology and energy sectors. He is a proven leader in the energy transition space with a global track record in the development and scaling of advanced energy technologies, including solar, smart grid, energy storage and Electric Vehicle ("EV") charging. He developed and deployed marque energy transition projects with international oil and oas companies. He is currently Chief Executive Officer and founder of Power Edison, a company focused on providing innovative mobile energy storage solutions for the grid. Dr. Kuran is the founder and Executive Chairman of EV Edison, a company focused on the development of large scale EV charging hubs. Dr. Kuran served as President of Strategic Development at NRG Energy and President of Advanced Solutions at SunEdison. Previously he founded Petra Solar, a pioneer of smart solar, combining solar energy and smart grid technologies, and developer of the world's largest solar electric project in 2009, and served as Director, President and Chief Executive Officer. Prior to Petra Solar he served in various executive leadership capacities in the technology sector.
Lisa M. Lambert
Independent Director since 2020 Committees: NGE&S and Compensation Age: 57
Other Current Public Company Directorships: Lucid Motors
UL
Education: MBA, Harvard Business School
BS, Management Information Systems, Pennsylvania State University
Career Highlights: Chief Investment Officer of Private Markets for the George Kaiser Family Foundation (current)
Managing Partner for the $100 million innovation foundry building energy startups (current)
National Grid Partners Founder and President
National Grid Chief Technology and Innovation Officer
The Westly Group Managing Partner
Intel Corporation Managing Director, Software and Services Fund and Diversity Fund
Ms. Lambert has extensive experience in the technology industries, leading innovation efforts and global investment initiatives. As Chief Investment Officer of Private Markets for the George Kaiser Family Foundation, she is responsible for investing in software including energy and mobility technology and managing the existing private markets portfolio. Her work with National Grid focuses on advancing energy systems, including at the intersection of energy and emerging technology to create a smarter, renewable future. She brings a perspective to our Board that contributes to our strategy of fostering a digital first mindset to make our business thrive in a digital era and to our continued commitment to ESG.
Lori A. Lancaster
Independent Director since 2020 Committees: Audit and Finance (Chair) Age: 55
Other Current Public Company Directorships: Precision Drilling Corp.
Intrepid Potash, Inc.
Education: MBA, University of Chicago
BBA, Texas Christian University
Career Highlights: UBS Securities Managing Director in the Global Energy Group
Goldman, Sachs & Co. Managing Director in the Global Natural Resources Group
Nomura Securities Managing Director in the Global Natural Resources Group
Ms. Lancaster has extensive experience in the oil and gas sector and in particular finance. During her 18-year tenure in investment banking, she led or was a key member of the execution team on more than $60 billion of announced energy merger and acquisition deals and led the structuring and execution of numerous capital markets transactions. Her wealth of knowledge in financing and structuring deals is key as we execute on our strategies to expand our high-margin drilling inventory through acquisitions and reduce our leverage. Additionally, she brings public company audit committee and nominating and corporate governance experience to our team.
Bryan Lemmerman
Executive Vice President and Chief Financial Officer since November 2023 Age: 50
Senior Vice President and Chief Financial Officer from June 2020 to November 2023
Education: M.B.A., University of Texas
M.S., Accounting, Texas A&M University
B.B.A., Accounting, Texas A&M University
Mr. Lemmerman joined Vital Energy in June 2020 as Senior Vice President and Chief Financial Officer. In November 2023 Mr. Lemmerman was promoted to Executive Vice President and Chief Financial Officer. Mr. Lemmerman has more than 16 years of experience in the energy exploration and production industry, including an extensive background in strategic planning and business development. He previously spent 10 years with Chesapeake Energy Corporation, serving in financial roles with increasing responsibility, most recently as Vice President-Business Development and Treasurer. Prior to joining Chesapeake, Mr. Lemmerman was a portfolio manager at Highview Capital Management and Ritchie Capital Management, overseeing investments in public and private energy.
Jason Pigott
President and Chief Executive Officer, October 2019 to present Director and President Age: 51
Education: MBA, University of North Carolina
BS, Petroleum Engineering, Texas A&M University
Mr. Pigott has more than 23 years of experience in the energy exploration and production industry. Before joining Vital, he served as Executive Vice President-Operations and Technical Services for Chesapeake Energy Corporation where he led all drilling and completions operations, digital operations, supply chain and land efforts. Prior to joining Chesapeake in 2013, he was with Anadarko Petroleum for 14 years, serving in positions of increasing responsibility, focused primarily on onshore unconventional play development in the Eagle Ford Shale, Haynesville Shale, Delaware Basin and various tightsand plays in East Texas. Mr. Pigott's extensive background in leading multidisciplinary operational and technical organizations, as well as experience contributing to executive level strategic decisions, contributes significant value to our Board of Directors. For these reasons, among others, we believe Mr. Pigott is qualified to serve as director.
Edmund P. Segner, III
Independent Director since 2011 Committees: Audit and Finance Age: 71
Other Current Public Company Directorships: Archrock, Inc.(Audit Committee and Governance and Sustainability Committee)
Education: Certified Public Accountant
MA, Economics, University of Houston
BS, Civil Engineering, Rice University
Career Highlights: Rice University Professor in the Practice of Engineering Management, Department of Civil and Environmental Engineering
EOG Resources, Inc. President, Chief of Staff and Director, Principal Financial Officer
Mr. Segner's service as President, Principal Financial Officer and director of publicly traded oil and gas exploration and development companies demonstrates a strong operational, financial, accounting and strategic background and enables him to provide our Board with valuable business, leadership and management experience and insights into many aspects of the operations of exploration and production. Mr. Segner also brings financial and accounting expertise to the Board, including through his experience in financing transactions for oil and gas companies, his background as a certified public accountant, his service as a Principal Financial Officer, his supervision of other principal financial officers and principal accounting officers and his service on the audit committees of other companies.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 11 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 12 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 13 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 14 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.
Part IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial statements
Our consolidated financial statements are included under "Part II, Item 8 Financial Statements and Supplementary Data" in this Annual Report. For a listing of these statements and accompanying footnotes, see "Index to Consolidated Financial Statements" on page of this Annual Report.
(a)(2) Financial statement schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
Incorporated by reference (File No. 001-35380, unless otherwise indicated)
Exhibit Description Form Exhibit Filling Date
2.1
Purchase and Sale Agreement by and between Laredo Petroleum, Inc. and Northern Oil and Gas, Inc., dated as of August 16, 2022.
8-K 2.1 8/17/2022
2.2
Purchase and Sale Agreement, dated May 11, 2023, by and among Vital Energy, Inc. and Northern Oil and Gas, Inc., as Purchasers, and Forge Energy II, Delaware LLC, as Seller.^
8-K 2.1 5/17/2023
2.3
Purchase and Sale Agreement, dated September 13, 2023, by and among Vital Energy, Inc. and Henry Resources LLC, Henry Energy LP and Moriah Henry Partners LLC.^
8-K 2.1 9/13/2023
2.4
Purchase and Sale Agreement, dated September 13, 2023, by and among Vital Energy, Inc. and Maple Energy Holdings LLC.^
8-K 2.2 9/13/2023
2.5
Purchase and Sale Agreement, dated September 13, 2023, by and among Vital Energy, Inc. and Tall City Property Holdings III LLC and Tall City Operations III LLC.^
8-K 2.3 9/13/2023
2.6
Purchase and Sale Agreement, dated July 27, 2024, by and among Vital Energy, Inc. and Northern Oil and Gas, Inc., as Purchaser, and Point Energy Partners Petroleum, LLC, Point Energy Partners Operating, LLC, Point Energy Partners Water, LLC and Point Energy Partners Royalty, LLC, as Seller.
8-K 2.1 7/29/2024
2.7
Purchase and Sale Agreement, dated February 2, 2024, by and among Vital Energy, Inc., as Purchaser, and PEP Henry Production Partners LP, PEP HPP Jubilee SPV LP, PEP PEOF Dropkick SPV, LLC, PEP HPP Dropkick SPV LP and HPP Acorn SPV LP, as Seller.
8-K/A 2.1 2/5/2024
3.1
Amended and Restated Certificate of Incorporation of Vital Energy, Inc., dated as of December 19, 2011.
8-K 3.1 12/22/2011
3.2
Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Vital Energy, Inc., dated as of June 1, 2020.
8-K 3.1 6/1/2020
3.3
Second Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Vital Energy, Inc., dated May 26, 2022
8-K 3.1 5/26/2022
3.4
Third Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Vital Energy, Inc., dated January 9, 2023.
8-K 3.1 1/9/2023
3.5
Fourth Certificate of Amendment to Vital Energy, Inc. Amended and Restated Certificate of Incorporated, dated November 21, 2023.
8-K 3.1 11/21/2023
3.6
Certificate of Ownership and Merger, dated as of December 30, 2013.
8-K 3.1 1/6/2014
3.7
Fourth Amended and Restated Bylaws of Vital Energy, Inc., adopted January 9, 2023.
8-K 3.2 1/9/2023
3.8
Certificate of Designations of 2.0% Cumulative Mandatorily Convertible Series A Preferred Stock of Vital Energy, Inc., as filed with the Secretary of State of the State of Delaware on September 13, 2023.
8-K 3.1 9/19/2023
Incorporated by reference (File No. 001-35380, unless otherwise indicated)
Exhibit Description Form Exhibit Filling Date
3.9
Certificate of Amendment to Certificate of Designations of 2.0% Cumulative Mandatorily Convertible Series A Preferred Stock of Vital Energy, Inc.
8-K 3.1 11/6/2023
4.1
Form of Common Stock Certificate.
8-A12B/A 4.1 1/7/2014
4.2*
Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934.
4.3
Indenture, dated as of March 18, 2015, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, N.A., as trustee.
8-K 4.1 3/24/2015
4.4
Indenture, dated as of July 16, 2021, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, National Association, as trustee.
8-K 4.1 7/16/2021
4.5
Fifth Supplemental Indenture, dated as of September 25, 2023, among Vital Energy, Inc., Vital Midstream Services, LLC and U.S. Bank Trust Company, National Association, as trustee.
8-K 4.2 9/25/2023
4.6
Form of Driftwood Registration Rights Agreement (attached as Exhibit C).
8-K 2.1 2/14/2023
4.7
Form of Henry Registration Rights Agreement (attached as Exhibit C).
8-K 2.1 9/13/2023
4.8
Form of Maple Registration Rights Agreement (attached as Exhibit C).
8-K 2.2 9/13/2023
4.9
Form of Tall City Registration Rights Agreement (attached as Exhibit C).
8-K 2.3 9/13/2023
4.10
Form of Grey Rock Registration Rights Agreement (attached as Exhibit G).
8-K/A 2.1 12/22/2023
4.11
Form of Henry Investor Agreement (attached as Exhibit F).
8-K 2.1 9/13/2023
4.12
Form of Grey Rock Investor Agreement (attached as Exhibit E).
8-K/A 2.1 12/22/2023
10.1
Fifth Amended and Restated Credit Agreement, dated as of May 2, 2017, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, and the other financial institutions signatory thereto.
10-Q 10.1 5/4/2017
10.2
First Amendment to Fifth Amended and Restated Credit Agreement, dated as of October 24, 2017, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
8-K 10.1 10/30/2017
10.3
Second Amendment to Fifth Amended and Restated Credit Agreement, dated as of February 14, 2018, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
10-K 10.3 2/15/2018
10.4
Third Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 19, 2018, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
8-K 10.1 4/23/2018
10.5
Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 30, 2020, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
8-K 10.1 5/6/2020
10.6
Fifth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of October 22, 2020, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
8-K 10.1 10/22/2020
10.7
Sixth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of May 7, 2021, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
8-K 10.1 5/11/2021
10.8
Seventh Amendment to the Fifth Amended and Restated Credit Agreement, dated as of July 16, 2021, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
8-K 10.2 7/16/2021
10.9
Eighth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of April 13, 2022, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
8-K 10.1 4/19/2022
Incorporated by reference (File No. 001-35380, unless otherwise indicated)
Exhibit Description Form Exhibit Filling Date
10.10
Ninth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of August 30, 2022, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
8-K 10.1 8/30/2022
10.11
Tenth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of November 1, 2022, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto.
8-K 10.1 11/3/2022
10.12
Limited Consent and Eleventh Amendment to the Fifth Amended and Restated Credit Agreement, dated as of September 13, 2023, among Vital Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Vital Midstream Services, LLC, as guarantor, and the banks signatory thereto^
8-K 10.1 9/13/2023
10.13
Twelfth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of May 8, 2024, among Vital Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Vital Midstream Services, LLC, as guarantor, and the banks signatory thereto.^
10-Q 10.6 5/9/2024
10.14
Thirteenth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of September 20, 2024, among Vital Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory hereto, and the banks signatory thereto.
10-Q 10.1 11/06/2024
10.15
Purchase Agreement, dated July 13, 2021, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Securities, LLC, as representative of the several initial purchasers named therein.
8-K 10.1 7/16/2021
10.16
Amended and Restated Form of Indemnification Agreement between Laredo Petroleum Holdings, Inc. and each of the officers and directors thereof.
10-Q 10.5 5/2/2019
10.17
Vital Energy, Inc. Omnibus Equity Incentive Plan, as amended and restated as of January 9, 2023.
10-K 10.14 2/22/2023
10.18
Vital Energy, Inc. Omnibus Equity Incentive Plan (amended and restated as of May 23, 2024).
8-K 10.1 5/28/2024
10.19
Vital Energy, Inc. Omnibus Equity Incentive Plan (amended and restated as of December 10, 2024).
8-K 10.1 12/13/2024
10.20
Vital Energy, Inc. Change in Control Executive Severance Plan (amended and restated as of December 10, 2024).
8-K 10.2 12/13/2024
10.21#
Vital Energy, Inc. Executive Severance Plan, as amended and restated as of January 9, 2023.
10-K 10.16 2/22/2023
10.22#
Offer Letter, dated April 17, 2019, between Laredo Petroleum, Inc. and Mr. Jason Pigott.
10-Q 10.3 5/2/2019
10.23#
Offer Letter, dated June 12, 2020, between Laredo Petroleum, Inc. and Mr. Bryan J. Lemmerman.
10-Q 10.3 8/6/2020
10.24#
Offer Letter, dated March 11, 2024, between Vital Energy, Inc. and Mr. Larry Faulkner.
10-Q 10.4 5/9/2024
10.25#
Form of Stock Option Agreement.
8-K 10.3 5/25/2016
10.26#
Form of 2021 Performance Share Unit Award Agreement.
10-Q 10.3 5/6/2021
10.27#
Form of Performance Share Unit Award Agreement.
10-K 10.23 3/11/2024
10.28#
Form of 2022 Restricted Stock Award Agreement.
10-Q 10.3 5/5/2022
10.29#
Form of Restricted Stock Award Agreement.
8-K 10.2 5/25/2016
10.30#
Nonqualified Director Deferred Compensation Plan.
10-K 10.28 3/11/2024
19.1*
Policy Prohibiting Insider Trading and Unauthorized Disclosure of Information to Others.
21.1*
List of Subsidiaries.
22.1*
List of Issuers and Guarantor Subsidiaries.
23.1*
Consent of Ernst & Young LLP.
23.2*
Consent of Ryder Scott Company, L.P.
31.1*
Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
Incorporated by reference (File No. 001-35380, unless otherwise indicated)
Exhibit Description Form Exhibit Filling Date
31.2*
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95.1*
Mine Safety Disclosures.
97.1
Executive Compensation Clawback Policy on Recoupment and Forfeiture of Incentive Compensation, dated November 1, 2023.
10-K 97.1 3/11/2024
99.1*
Summary Report of Ryder Scott Company, L.P.
99.2*
Unaudited pro forma condensed combined financial information of Vital Energy, Inc. for the year ended December 31, 2024.
101 The following financial information from Vital's Annual Report on Form 10-K for the year ended December 31, 2024, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders' Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements.
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
__________________________________________________________________________
* Filed herewith.
** Furnished herewith.
# Management contract or compensatory plan or arrangement.
^ Certain schedules and exhibits to this agreement have been omitted in accordance with Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the Securities and Exchange Commission on request.