EDGAR 10-K Filing

Company CIK: 1528129
Filing Year: 2023
Filename: 1528129_10-K_2023_0001528129-23-000048.json

---

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. For a full discussion of the development of our business, see "Part I, Item 1. Business" in our 2019 Annual Report on Form 10-K.
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, 2022, we had assembled 163,286 net acres in the Permian Basin, all of which were held in 371 sections. Our acreage is largely contiguous in the neighboring Texas counties of Borden, Howard, Glasscock, Reagan, and Sterling. We have identified one operating segment: exploration and production.
Business Strategy and 2022 Operational Highlights
Our strategy is to create long-term value through the efficient development and acquisition of high-margin properties, combined with prudent balance sheet management and sustainable environmental practices. We have operated in the Permian Basin since 2008, drilling almost 650 operated horizontal wells. Our extensive operating experience in the basin underpins our ability to successfully develop our properties, assess acquisition opportunities and operate safely and efficiently, ultimately maximizing our rates of return on our development program.
Beginning in late 2019, we acquired oil-weighted properties to the north and west of our existing Permian Basin acreage and quickly transitioned our development activities to these capital-efficient areas. We have significantly increased our oil production as a percentage of total production, improved our operating margin and, as a result, generated Free Cash Flow and significantly reduced debt in 2022.
Our results in 2022 were driven by our development program in Howard County. We focused on developing large packages of wells at conservative spacing to maximize both current and future productivity. Combined with continued efficiency gains in our drilling and completions operations and sustained strength in oil prices, our development program generated high returns and Free Cash Flow. Additionally, we divested non-operated properties in Howard County for $110.0 million, generating additional cash flow and enhancing control of our capital investments.
We seek to proactively manage our financial risks and maintain a strong balance sheet. During 2022, we utilized Free Cash Flow and divestiture proceeds to repurchase, and retire, a total of $284.8 million in aggregate principal amount of our senior unsecured notes, thereby reducing our consolidated total leverage ratio to 1.2 times. We increased our borrowing base to $1.3 billion and our elected commitment to $1.0 billion, increasing our liquidity and financial flexibility. Additionally, in May 2022 we instituted an equity repurchase program as a method to return cash to shareholders. During 2022 we repurchased $37.3 million of equity, reducing shares outstanding by 490,536 shares. We have historically hedged our production to protect cash flows, achieve strong rates of return on our capital investments and protect the Company in times of declining commodity prices. We entered 2022 with approximately 73% of our expected oil production hedged to protect cash flow and we will continue to seek hedging opportunities on a multi-year basis, subject to the terms of our Senior Secured Credit Facility, to further protect our capital plan, interest payments, and Free Cash Flow generation.
We integrate robust environmental, social and governance ("ESG") practices into our operations and describe these practices in the three ESG and Climate Risk Reports we have published to date, covering operations which occurred in 2019, 2020 and 2021, respectively. The disclosures in these three reports are aligned to the Sustainability Accounting Standards Board, the Task Force on Climate Related Financial Disclosures, the International Petroleum Industry Environmental Conservation Association, the American Petroleum Institute, and the American Exploration and Production Council frameworks. Our 2020
report, related to our 2019 operations, announced ambitious emissions reductions targets and outlined goals for reducing both greenhouse gas intensity and methane emissions, as well as eliminating routine flaring by 2025. Additionally, our 2022 report expanded our emissions reduction targets to include a 2025 target for the percentage of recycled water to be used in our completions operations as well as a 2030 combined Scope 1 and Scope 2 greenhouse gas intensity target. Beyond our emissions reduction targets, we also disclosed climate-related scenario analysis, Scope 3 emissions estimates, and EEO-1 workforce diversity data. Furthermore, we described our pilot program for continuous emissions monitoring and the certification of portions of our oil and natural gas production as responsibly sourced through the Project Canary TrustWellTM Certification pilot project, the first operator in the Permian Basin to achieve this certification. Relatedly, we continue to incorporate environmental measures into our executive compensation program.
Our business strategy is both clear and sustainable. We will continue to focus on safely developing our highest return oil-weighted inventory while opportunistically adding more high-margin acreage as we seek to improve our margins and profitability. We are highly selective in the projects that we consider, and we will continue to monitor the market for strategic opportunities that we believe could be accretive and enhance shareholder value. These opportunities may take the form of acquisitions, divestitures, mergers, redemptions, equity or debt repurchases, or other similar transactions, any of which could result in the utilization of our Senior Secured Credit Facility and/or further accessing the capital markets.
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 and Spraberry formations. As of December 31, 2022, we had an average working interest of 73% in Vital-operated active productive wells and 67% in all wells in which Vital has an interest, and our leases are 98% held by production.
The following table sets forth certain information regarding productive wells as of December 31, 2022. Wells are classified as oil or natural gas wells according to the predominant production stream. All but sixteen 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 producing wells Average WI %
Gross Net
Vertical Horizontal Total Total
Permian-Midland Basin:
Operated 947 742 1,689 1,235 73 %
Non-operated 163 64 227 57 25 %
Total 1,110 806 1,916 1,292 67 %
Drilling Activity
On December 31, 2022, we had two drilling rigs drilling horizontal wells and one completions crew. We anticipate running two drilling rigs and two completions crews in the first quarter of 2023. For the remainder of 2023, we anticipate running two drilling rigs and one completions crew. We will 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 will 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 wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.
Years ended December 31,
2022 2021 2020
Gross Net Gross Net Gross Net
Productive development wells 49 47.1 71 70.1 48 47.3
Sales volumes, revenues, prices and expenses history
The following table presents 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."
Years ended December 31, 2022 compared to 2021
2022 2021 2020 Change (#) Change (%)
Sales volumes:
Oil (MBbl) 13,838 11,619 9,827 2,219 19 %
NGL (MBbl) 8,028 8,678 10,615 (650) (7) %
Natural gas (MMcf) 49,259 57,175 70,049 (7,916) (14) %
Oil equivalents (MBOE)(1)(2)
30,076 29,827 32,117 249 1 %
Average daily oil equivalent sales volumes (BOE/D)(2)
82,400 81,717 87,750 683 1 %
Average daily oil sales volumes (Bbl/D)(2)
37,912 31,833 26,849 6,079 19 %
Sales revenues (in thousands):
Oil $ 1,351,207 $ 805,448 $ 367,792 $ 545,759 68 %
NGL $ 234,613 $ 191,591 $ 78,246 $ 43,022 22 %
Natural gas $ 208,554 $ 150,104 $ 50,317 $ 58,450 39 %
Average sales prices(2):
Oil ($/Bbl)(3)
$ 97.65 $ 69.32 $ 37.43 $ 28.33 41 %
NGL ($/Bbl)(3)
$ 29.22 $ 22.08 $ 7.37 $ 7.14 32 %
Natural gas ($/Mcf)(3)
$ 4.23 $ 2.63 $ 0.72 $ 1.60 61 %
Average sales price ($/BOE)(3)
$ 59.66 $ 38.46 $ 15.45 $ 21.20 55 %
Oil, with commodity derivatives ($/Bbl)(4)
$ 70.32 $ 52.09 $ 56.41 $ 18.23 35 %
NGL, with commodity derivatives ($/Bbl)(4)
$ 24.29 $ 10.55 $ 9.12 $ 13.74 130 %
Natural gas, with commodity derivatives ($/Mcf)(4)
$ 2.83 $ 1.56 $ 1.02 $ 1.27 81 %
Average sales price, with commodity derivatives ($/BOE)(4)
$ 43.48 $ 26.36 $ 22.50 $ 17.12 65 %
Selected average costs and expenses per BOE sold(1)(2):
Lease operating expenses $ 5.78 $ 3.42 $ 2.55 $ 2.36 69 %
Production and ad valorem taxes 3.69 2.30 1.03 1.39 60 %
Transportation and marketing expenses 1.79 1.61 1.55 0.18 11 %
General and administrative (excluding LTIP) 1.91 1.54 1.29 0.37 24 %
Total selected operating expenses $ 13.17 $ 8.87 $ 6.42 $ 4.30 48 %
General and administrative (LTIP):
LTIP cash $ 0.11 $ 0.35 $ 0.06 $ (0.24) (69) %
LTIP non-cash $ 0.24 $ 0.22 $ 0.22 $ 0.02 9 %
Depletion, depreciation and amortization $ 10.36 $ 7.22 $ 6.76 $ 3.14 43 %
_______________________________________________________________________________
(1)BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)The numbers presented in the years ended December 31, 2022, 2021 and 2020 columns are based on actual amounts and may not recalculate using the rounded numbers presented in the table above.
(3)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.
(4)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 and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled 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 Securities and Exchange Commission ("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, 2022 Year ended December 31, 2022
Estimated proved reserves(1)
Producing wells Average daily production
MBOE % Oil Net
acreage Gross Net (BOE/D) % Oil % NGL % Natural gas
Permian-Midland Basin 302,318 39 % 163,286 1,916 1,292 82,400 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, 2022 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, 2022 December 31, 2021
Proved developed:
Oil (MBbl) 70,333 70,727
NGL (MBbl) 75,156 78,908
Natural gas (MMcf) 464,567 494,476
Total proved developed (MBOE) 222,917 232,048
Proved undeveloped:
Oil (MBbl) 46,125 50,175
NGL (MBbl) 18,656 21,139
Natural gas (MMcf) 87,721 91,669
Total proved undeveloped (MBOE) 79,401 86,592
Estimated proved reserves:
Oil (MBbl) 116,458 120,902
NGL (MBbl) 93,812 100,047
Natural gas (MMcf) 552,288 586,145
Total estimated proved reserves (MBOE) 302,318 318,640
Percent developed 74 % 73 %
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, our independent reserve engineers, 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, our independent reserve engineers, estimated 100% of our proved reserve information as of December 31, 2022, 2021 and 2020 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 8 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 Financial 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 decreased from 86,592 MBOE as of December 31, 2021 to 79,401 MBOE as of December 31, 2022. We estimate that we incurred $337.9 million of costs to convert 23,722 MBOE of proved undeveloped reserves from 44 locations into proved developed reserves in 2022. New proved undeveloped reserves of 30,291 MBOE were added during the year from 34 Spraberry and 32 Wolfcamp locations. 13,155 MBOE of negative revisions consisted of 9,785 MBOE of negative revisions due to 16 proved undeveloped locations that were removed due to change in the development plan and 3,370 MBOE of negative revisions from a decrease in previously estimated quantities due to performance, price and other changes. A final investment decision has been made on all 153 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, 2022 reserve report are $1.3 billion. Based on this report and our PUD booking methodology, the capital estimated to be spent to develop the proved undeveloped reserves from spud date through production is $529.0 million in 2023, $321.0 million in 2024, $222.7 million in 2025, $128.6 million in 2026 and $14.6 million in 2027. 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 2023 to 2026. Reserve calculations at any end-of-year period are representative of our development plans at that time. 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 development plans.
Acreage
The following table sets forth our developed and undeveloped acreage as of December 31, 2022, 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 183,914 160,496 3,344 2,790 187,258 163,286 98 %
The following table sets forth our gross and net undeveloped acreage as of December 31, 2022 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,
2023 2024 2025 2026
Gross Net Gross Net Gross Net Gross Net
Permian-Midland Basin 474 543 1,390 1,138 600 307 - -
Of the total undeveloped acreage identified as potentially expiring over the next five years as of December 31, 2022, 1,881 net acres have associated PUD reserves included in our reserve report as of December 31, 2022, which we anticipate drilling to hold or renewing the associated leases. These PUD reserves represent 35% of our total PUD reserves as of December 31, 2022.
Of the total undeveloped acreage identified as potentially expiring over the next five years as of December 31, 2021, 2,355 net acres had associated PUD reserves on our reserve report as of December 31, 2021. Of the total undeveloped acreage identified as potentially expiring in 2022, zero net acres were not retained through either lease renewals or operations.
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, 2022:
Total 2023 2024 2025 2026 and after
Crude oil (MBbl):
Sales commitments 7,875 7,875 - - -
Transportation commitments:
Field 21,930 10,950 10,980 - -
To U.S. Gulf Coast 54,285 12,775 12,810 12,775 15,925
Natural gas (MMcf):
Sales commitments 54,378 11,402 8,435 7,378 27,163
Total commitments (MBOE)(1)
93,153 33,500 25,196 14,005 20,452
_____________________________________________________________________________
(1)BOE is calculated using a conversion rate of six Mcf per one Bbl.
We have firm field transportation agreements that enable us or the purchasers of our oil production to transport oil from our production area to major market hubs, including Midland, Texas and Crane, Texas. If not fulfilled, we are subject to transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for our business. Our firm field transportation agreements are related to transportation commitments extending into 2024 with Medallion Pipeline Company, LLC ("Medallion") under which Medallion provides firm transportation capacity from our established Reagan County and Glasscock County acreage for redelivery to various major market hubs. In addition, we have a transportation commitment with Gray Oak Pipeline, LLC extending into 2027 to transport 35,000 barrels of oil per day of our production, or the oil purchased from third parties, from Crane, Texas to the U.S. Gulf Coast. We believe these commitments enhance our ability to efficiently market our crude oil at various locations both in and out of the Permian Basin and give us access to multiple pricing points for the sale of our crude oil.
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. 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, 2022, 2021 and 2020, 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.
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. 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. Compliance with these regulations 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." Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste are not necessary at this time. 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. Meanwhile, in October 2022, the Supreme Court heard oral argument in a case addressing the scope of federal jurisdiction under the Clean Water Act. 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 eliminate a pathway for the fracturing fluid to contact any aquifers. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval. Injections rates and pressures are monitored in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Our hydraulic fracturing operations are designed to be shut down immediately if an abrupt change occurred to the injection pressure or annular pressure.
Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements. In accordance with Texas regulations, we report the constituents of the hydraulic fracturing fluids utilized in our well completions on FracFocus (www.fracfocus.org). Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it by recycling or by discharging into the approved disposal wells. We currently do not discharge water to the surface. Based upon results of testing the performance of recycled flowback/produced water in our fracking operations, we endeavor to maximize the utilization of recycled flowback/produced water via our owned and operated recycling facilities in Glasscock and Reagan County or via contractual arrangements with third parties in Howard County.
The 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. On February 12, 2014, the EPA published a revised UIC Program permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how Class II regulations may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas, where we maintain acreage, the EPA is encouraging state programs to review and consider use of this permit guidance. Furthermore, 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.
In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities. We cannot predict the impact that these actions may have on our business at this time, but further regulation of hydraulic fracturing activities could have a material impact on our business, financial condition and results of operation.
Also, on March 26, 2015, the Bureau of Land Management (the "BLM") published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. On March 28, 2017, the Trump Administration issued an executive order directing the BLM to review the rule, and, if
appropriate, to initiate a rulemaking to rescind or revise it. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule; however, a coalition of environmentalists, tribal advocates and the State of California filed lawsuits challenging the rule rescission. At this time, it is uncertain when, or if, the hydraulic fracturing rule will be implemented, and what impact it would have on our operations.
Furthermore, there are certain governmental reviews either under way or being proposed that focus on environmental aspects of hydraulic fracturing practices. On February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Also, on December 13, 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. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism.
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, pursuant to legislation adopted by the State of Texas in June 2011, beginning February 1, 2012, companies were required to disclose to the RRC and the public the chemical components used in the hydraulic fracturing process, as well as the volume of water used. Also, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The new rules took effect in January 2014. Additionally, on October 28, 2014, the RRC adopted disposal well rule amendments designed, among other things, to 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 searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify 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. 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.
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 August 2012, the EPA published New Source Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants for oil and natural gas production, processing, transmission, and storage operations. The rules include NSPS for completions of hydraulically fractured gas wells and establish specific new requirements for emissions from compressors, pneumatic controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. This rule was promulgated and implemented to reduce emissions from volatile organic compounds ("VOC"). On June 3, 2016 the EPA published additional standards for methane and VOC emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector, including Leak Detection and Repair ("LDAR") programs, emission controls for tanks, verification of closed vent systems, and compressor requirements. Regulation of oil and natural gas facilities continues to expand and become more rigorous. On November 15, 2021, the EPA published a proposed rule for oil and natural gas facilities that would expand control requirements, increase LDAR inspection frequencies, prohibit venting of natural gas in certain situations, require equipment retrofits, and regulate older facilities. Also, on December 6, 2022, the EPA published a supplemental proposal to strengthen the emission reduction requirements, which would, among other things, expand LDAR requirements and tighten flaring restrictions.
In addition, on November 18, 2016, the BLM finalized a waste prevention rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule also clarifies when operators owe the government royalties for flared gas. On March 28, 2017, the Trump Administration issued an executive order directing the BLM to review the above rule and, if appropriate, to initiate a rulemaking to rescind or revise it. On September 28, 2018, the BLM finalized revisions to the waste prevention rule to reduce "unnecessary compliance burdens." However, a federal court struck down the scaled-back rule on July 15, 2020, and shortly thereafter, on October 8, 2020, another federal court struck down the 2016 waste prevention rule. On November 30, 2022, the BLM published a proposed replacement rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on federal and Indian lands, which would require the use of upgraded equipment in some cases and would place time and volume limits on royalty-free flaring. At this time, it is uncertain when, and to what extent, the waste prevention rule will be implemented, and what impact it will have on our operations.
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" emissions
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases ("GHGs"). In August 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”) into law. The IRA contains billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced
biofuels and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell. In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA amends the Clean Air Act to impose a fee on the emission of methane that exceeds an applicable waste emissions threshold from sources required to report their GHG emissions to the EPA, including those sources in the offshore and onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA.
The EPA has also finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry and almost one-half of the states have taken measures to reduce GHG emissions primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. Also, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and gas operations. In addition, several states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.
At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake "ambitious efforts" to limit the average global temperature and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016. Although the United States withdrew from the Paris Agreement, effective November 4, 2020, President Biden issued an Executive Order on January 20, 2021 to rejoin the Paris Agreement, which took effect on February 19, 2021. On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its GHG emissions by 50-52 percent below 2005 levels in 2030. In November 2021, in connection with the 26th Conference of the Parties in Glasgow, Scotland, the United States and other world leaders made further commitments to reduce GHGs, including reducing global methane emissions by at least 30% by 2030. In relation, many state and local leaders have stated their intent to intensify efforts to support the international climate commitments.
Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil, NGL and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.
In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
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.
National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act ("NEPA"). NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency prepares an environmental assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available for public review and comment. Any exploration and production activities, as well as proposed exploration and development plans, on federal lands would require governmental permits that are subject to the requirements of NEPA. This environmental impact assessment process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.
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 may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. If newly listed species, such as the lesser prairie chicken, are located in areas where we operate or previously unprotected species, such as the dunes sagebrush lizard, are designated as endangered or threatened, or if we were to have a portion of our leases designated as critical or suitable habitat, it could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas, which could adversely impact the value of our leases.
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, 2022, 2021 or 2020.
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
The Vital Way is a path designed for our employees to experience mutual respect, openness, honesty and a spirit of trust and collaboration while employed by Vital. Vital's key human capital objectives are to attract, retain, motivate and develop the highest quality talent possible. To support these objectives, we support and encourage an inclusive work environment to help our employees attain their highest level of productivity, creativity and efficiency. The Vital Way separates itself by advancing a limitless mindset. Diverse and sound ideas, approaches and individual experiences are essential features of inclusion. By choosing to practice a mindset unencumbered by bias or fear, we believe there are no barriers to what we can become. Through the implementation of our Code of Conduct and Business Ethics, annual anti-harassment training and unconscious bias trainings, we uphold an environment of safety and inclusion. We firmly believe that everyone at Vital contributes to our success.
Workforce Composition
As of December 31, 2022, we employed 289 full-time employees, 141 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.
Diversity and Inclusion
We believe that a diverse workforce will help our organization better accomplish our mission. To increase our hiring of traditionally underrepresented personnel and women, Vital proactively sources open positions on job sites specifically focused on diversity. This allows us to gain candidates from underrepresented talent pools to help fill our positions. At the end of our fiscal year 2022, our workforce consisted of:
•28% diverse based on ethnicity
•28% diverse based on gender
•3% US military veterans
•37% women in professional roles or higher
Vital strives to provide a comfortable and progressive workplace where communication is open and problems can be discussed and resolved in a mutually respectful atmosphere. We take into account individual circumstances and the individual employee. Working together, we are stronger, and we will continue to honor diversity and inclusion as key values of the Vital Way.
Health and Safety
Vital Energy exists to help people reach their fullest potential. We believe this starts with making sure people are healthy and safe. Most importantly, we know that an engaged, healthy, safe and well-trained workforce helps us accomplish our strategic goals. By taking action every day through all-hands safety meetings, hazard hunts, stop-work authority and root-cause analysis, we are building belief in this culture every day.
Total Rewards
To attract and retain exceptional talent, we provide our employees a comprehensive total rewards program, which includes a comprehensive benefits offering and competitive compensation package. In addition to competitive salaries, we offer both short and long term incentive programs, company-matched 401K contributions, flexible working schedules and many more employee-focused programs.
Learning and Development
Attracting, retaining and developing our workforce is crucial to all aspects of Vital's overall success and it is central to our long-term strategy. We offer tuition reimbursement benefits for extended educational learning opportunities. Additionally, we have a robust training program for our Lease Operators and Field Technicians that allows for consistency in our processes and gives the leadership team clarity when considering field employees for promotional opportunities. Administration of this program is a joint effort between leadership on the Production team and the Learning and Development staff that allows us to intentionally train our employees with the goal of promoting from within for all promotions in the field. Vital prides itself on the ability to promote our great employees.
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 http://www.sec.gov. Our common stock is listed and traded on the New York Stock Exchange under the symbol "VTLE."
We also make available on our website (http://www.vitalenergy.com) all of the documents that we file with the SEC and amendments to those reports, including related exhibits and supplemental schedules, filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Our Code of Conduct and Business Ethics, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines, Policy Statement Regarding Related Party Transactions and the charters of our audit committee, compensation committee, finance committee, and nominating, corporate governance, environmental and social committee are also available on our website and in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our executive office. Information contained on our website is not incorporated by reference into this Annual Report. We intend to disclose on our website any amendments or waivers to our Code of Conduct and Business Ethics or Code of Ethics for Senior Financial Officers that are required to be disclosed pursuant to Item 5.05 of Form 8-K.

---

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
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 and may continue to increase in 2023. 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. Sustained levels of high inflation have likewise caused the Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, 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.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. 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. A write-down constitutes a non-cash charge to earnings. 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.
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 the likelihood that interest rates will continue to rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.
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.
There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, cash flows from operations and shareholder 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 shareholder value. However, due to many factors, including some beyond our control, there is no guarantee that we will be able to find the optimal plan or one that provides continuous improvement. If we are unable to design and implement an effective spacing, drilling and completions strategy, it may have a material adverse effect on our production results, financial performance, stock price and net asset value.
In addition, we use 3D seismic and other advanced technologies, which are relatively unproven and require greater pre-drilling expenditures than traditional drilling strategies, which may result in a reduction in our returns. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.
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 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, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
We may be subject to risks in connection with acquisitions and disposition of assets.
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.
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.
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, 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.
Recent transactions may expose us to contingent liabilities.
We have agreed to indemnify the sellers of assets in recent transactions 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 in the unconventional resource industry has been growth in production and reserves. With historical volatility in oil and natural gas prices and the likelihood that rising interest rates will increase the cost of borrowing, capital efficiency and free cash flow from earnings have become the key drivers for energy companies, particularly shale producers. 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 Note 19 to our consolidated financial statements 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 eight 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.
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 affected by the COVID-19 pandemic and responses.
Since 2020, the spread of the COVID-19 coronavirus caused, and is continuing to cause, disruptions in the worldwide and U.S. economy. There are many variables and uncertainties regarding the COVID-19 pandemic, including the emergence and severity of new and different strains of the virus; the effectiveness of treatments or vaccines against the virus or its new strains; the extent of travel restrictions, business closures and other measures that are or may be imposed in affected areas or countries by governmental authorities; disruptions in the supply chain; a competitive labor market due to sustained labor shortage or increased turnover caused by the COVID-19 pandemic; increased logistics costs; additional costs due to remote working arrangements, adherence to social distancing practices and other COVID-19 related challenges; and decreases in the price of oil due to remote working arrangements. Further, there remain increased risks of cyberattacks on information technology systems used in remote working environment; increased privacy-related risks due to processing health-related personal information; absence of workforce due to illness; the impact of the pandemic on any of our contractual counterparties; and other factors that are currently unknown or considered immaterial. It is difficult to assess the ultimate impact of the COVID-19 pandemic on our business, financial condition and results of operations.
Our business could be negatively impacted by disruption of electronic systems, security threats, including cyber-security 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. If any of such systems or programs were to fail or we were subject to cyberspace breaches or attacks, possible consequences include our loss of communication links, inability to find, produce, process and sell oil, NGL and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
As an oil and natural gas producer, we face various security threats, including cyber-security 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. In particular, cyber-security attacks are evolving and include, but are not limited to, malicious software, 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. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.
Our business could be negatively impacted by hydrocarbon price volatility as the result of, or with the intensification of, Russian activities in Ukraine and as the result of, or as a result of the threat of, Russia expanding its production of oil and gas to finance its activities in Ukraine and destabilize world energy markets.
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. Russia's activities in Ukraine have caused, and could intensify, volatility in global oil and gas prices and increases in oil production by Russia to finance its activities in Ukraine or to destabilize global oil and gas prices could reduce the price 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, 2022, 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.
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, 2022, we had federal net operating loss ("NOL") carryforwards totaling $1.5 billion and state of Oklahoma NOL carryforwards totaling $34.4 million. If we were to experience an "ownership change," as determined under Section 382 of the Internal Revenue Code, to which Oklahoma conforms, our ability to offset taxable income arising after the ownership change with NOLs arising prior to the ownership change would be limited, possibly substantially. An ownership change would establish an annual limitation on the amount of our 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 This annual litigation however, may be significantly increased if there is "net unrealized built-in gain" in the assets of the corporation undergoing the ownership change.
In addition, as a result of a comprehensive tax reform bill commonly referred to as the Tax Cuts and the Jobs Act (the "Tax Act"), NOLs arising before January 1, 2018, and NOLs arising on or after January 1, 2018, are subject to different rules. NOLs arising before January 1, 2018, can generally be carried forward to offset future taxable income for a period of 20 years. Any
NOL arising on or after January 1, 2018, while subject to additional limitations, can generally be carried forward indefinitely. Our ability to use our NOLs during this 20-year period will be dependent on our ability to generate taxable income, and the NOLs could expire before we generate sufficient taxable income. As of December 31, 2022, based on evidence available to us, including projected future cash flows from our oil, NGL and natural gas reserves and the timing of those cash flows, we believe a portion of our NOLs is not fully realizable. As a result, as of December 31, 2022, a valuation allowance has been recorded against our net deferred tax assets. See Note 13 to our consolidated financial statements included elsewhere in this Annual Report for additional information.
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.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil, NGL and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil, NGL and natural gas, including the possibility of (i) environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination, (ii) abnormally pressured formations, (iii) mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse, (iv) fires, explosions and ruptures of pipelines, (v) disagreements regarding the royalty due to our royalty owners, (vi) personal injuries and death, (vii) electronic system disruption and cyber-security 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 will continue to develop, targets related to ESG initiatives, including our emissions reduction targets and strategy. Public statements related to these initiatives reflect our current plans and are 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, some of which are outside of our control.
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.
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 senior unsecured note 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, 2022, we had total long-term indebtedness of $1.12 billion. We may be able to incur substantial additional indebtedness, including secured indebtedness, in the future. The restrictions on the incurrence of additional indebtedness contained in the indentures governing our senior unsecured notes and in our Senior Secured Credit Facility are subject to a number of significant qualifications and exceptions, and under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we face would increase and may make it more difficult to satisfy our existing financial obligations. In addition, the restrictions on the incurrence of additional indebtedness contained in the indentures governing the senior unsecured notes apply only to debt that constitutes indebtedness under the indentures. However, such increased debt may reduce the amount of outstanding debt allowed under the Senior Secured Credit Facility.
Increases in our cost of and ability to access capital 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. 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 and signaled that additional interest rate increases should be expected in 2023. On December 14, 2022, it raised interest rates by 0.50%, representing the seventh increase in interest rates during 2022 to date. Raising or lowering of interest rates by the U.S. Federal Reserve generally causes an increase or decrease, respectively, in SOFR and other floating interest rate benchmarks. As such, if interest rates increase, so will our interest costs. 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 increase, so will 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 Inflation Reduction Act of 2022 ("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 will be phased-in starting 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.
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. 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 (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. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business, results of operations, financial condition and cash flow.
In addition, the IRA imposes a 15% corporate alternative minimum tax ("CAMT") on the "adjusted financial statement income" of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income in their consolidated financial statements) as well as an excise tax of 1% on the fair market value of certain public company stock repurchases for tax years beginning after December 31, 2022. The U.S. Treasury Department, the Internal Revenue Service and other standard-setting bodies are expected to issue guidance on how the CAMT, stock buyback excise tax, and other provisions of the IRA will be applied or otherwise administered. 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, or designation of previously unprotected species in areas where we operate, such as the dunes sagebrush lizard 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.
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.
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 common stock or just our common stock. 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 plans to pay and are currently restricted from paying dividends on our common stock, investors must look solely 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 foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. 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 restrict the payment of dividends. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

---

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

---

ITEM 2. PROPERTIES
Item 2. Properties
The information required by Item 2. is contained in "Item 1. Business."

---

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.

---

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

---

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 17, 2023, there were 113 holders of record of our common stock.
Dividends
We have not paid any cash dividends since our inception. Covenants contained in our Senior Secured Credit Facility and the indentures governing our senior unsecured notes restrict 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:
Period Total number of
shares purchased Weighted-average price paid per share(1)
Total number of shares purchased as
part of publicly announced program(2)
Maximum value that may yet be
purchased under the program as
of the respective period-end date(2)
October 1, 2022 - October 31, 2022 100,749 $ 66.87 100,749 $ 166,676,279
November 1, 2022 - November 30, 2022 59,939 $ 66.17 59,939 $ 162,710,185
December 1, 2022 - December 31, 2022 - $ - - $ 162,710,185
Total 160,688 160,688
____________________________________________________________________________
(1)Average share price includes any commissions paid to repurchase stock.
(2)On May 31, 2022, our board of directors authorized a $200 million share repurchase program commencing on the date of such announcement and continuing through and including May 27, 2024. 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, 2022, we repurchased 160,688 shares under this program at a cost of $10.7 million.
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, 2017 to December 31, 2022

---

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

---

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, 2022 compared to 2021, 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 2021 Annual Report on Form 10-K for discussion and analysis of our financial condition and results of operations for the year ended December 31, 2021 compared to 2020. 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. We have grown primarily through our drilling program, coupled with select strategic acquisitions and joint ventures.
As of December 31, 2022, we were operating two drilling rigs and one completions crew. We expect to operate two drilling rigs during 2023, with two completions crews during the first quarter of 2023 and returning to one completions crew for the remainder of 2023. Our expected capital expenditures for full-year 2023 are expected to be in the approximate range of $625.0 million to $675.0 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 periods presented:
Years ended December 31, 2022 compared to 2021
(in thousands) 2022 2021 Change (#) Change (%)
Oil sales volumes (MBbl) 13,838 11,619 2,219 19 %
Oil equivalents sales volumes (MBOE) 30,076 29,827 249 1 %
Oil, NGL and natural gas sales(1)
$ 1,794,374 $ 1,147,143 $ 647,231 56 %
Net income $ 631,512 $ 145,008 $ 486,504 336 %
Net cash provided by operating activities $ 829,620 $ 496,671 $ 332,949 67 %
Free Cash Flow (a non-GAAP financial measure)(2)
$ 219,941 $ (2,829) $ 222,770 7,875 %
Adjusted EBITDA (a non-GAAP financial measure)(2)
$ 913,482 $ 505,917 $ 407,565 81 %
Proved developed and undeveloped reserves (MBOE)(3)
302,318 318,640 (16,322) (5) %
_____________________________________________________________________________
(1)Our oil, NGL and natural gas sales increased as a result of a 55% increase in average sales price per BOE and a 19% increase in oil sales volumes.
(2)See pages 57-58 for discussion and calculations of these non-GAAP financial measures.
(3)See Note 19 to our consolidated financial statements included elsewhere in this Annual Report for discussion of changes in our estimated proved reserve quantities of oil, NGL and natural gas.
Recent developments
Vital Energy rebranding
Effective January 9, 2023, the Company changed its corporate name from Laredo Petroleum, Inc. to Vital Energy, Inc., pursuant to a certificate of amendment to its certificate of incorporation filed with the Delaware Secretary of State on January 6, 2023. The Company also amended and restated its bylaws to reflect the name change, effective as of January 9, 2023.
Volatility in commodity prices
Commodity prices remained steady during the fourth quarter of 2022, sustaining levels reached at the end of the first quarter as increased commodity demand has continued to outpace relative supply. While recessionary concerns have placed some downward pressure on commodity prices, causing oil and gas prices to retreat from their earlier highs in 2022, worldwide commodity demand continues to exceed pre-COVID-19 pandemic levels. Although supply has increased, it has been constrained and pricing has been affected, in part, by the impact of the Russian-Ukrainian military conflict on global commodity and financial markets, and the resulting effect of sanctions by the European Union, United Kingdom and U.S. on imports of oil and natural gas from Russia, as well as a recent announcement by OPEC+ of oil production cuts of two million barrels per day beginning in November of 2022. However, because any of the above factors could suddenly change or reverse, global commodity and financial markets remain subject to heightened levels of uncertainty and volatility, and future disruptions and industry-specific impacts could result.
Rising inflation and interest rates
Reversing a trend experienced in 2020 in connection with the impact of COVID-19 and historically low crude oil prices, 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 in conjunction with the significant increase in commodity prices, labor tightening, supply chain disruptions caused by the COVID-19 pandemic and the resulting limited availability of certain materials and products manufactured using such materials and heightened levels of inflation. In addition to the effect of such inflationary pressures on our operating and capital costs, rising 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. 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.
See Note 18 to our consolidated financial statements included elsewhere in this Annual Report for discussion of recent developments that have occurred subsequent to December 31, 2022.
Pricing and reserves
Our results of operations are heavily influenced by oil, NGL and natural gas prices. Historically, commodity prices have experienced significant fluctuations; however, the volatility in the prices has substantially increased in recent years. 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, 12 and 18 to our consolidated financial statements included elsewhere in this Annual Report for additional discussion of our commodity derivatives. Not withstanding 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.
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, 2022 were $96.21 for oil, $29.84 for NGL and $4.24 for natural gas. The unamortized cost of evaluated oil and natural gas properties being depleted did not exceed the full cost ceiling for any of the quarterly periods in 2022 and 2021. As such, no full cost ceiling impairments were recorded during the years ended December 31, 2022 and 2021. Oil prices have declined from mid-2022 levels, however, even with this decline if oil prices remain at current levels, we do not anticipate recording full cost ceiling impairments for the foreseeable future. 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.
Results of operations
Revenues
Sources of our revenue
Our revenues are primarily derived from the sale of produced oil, NGL and natural gas and the sale of purchased oil, all within the continental U.S. and do not include the effects of derivatives.
The following table presents our sources of revenue as a percentage of total revenues for the periods presented and corresponding changes for such periods:
Years ended December 31, 2022 compared to 2021
2022 2021 Change (#) Change (%)
Oil sales 70 % 58 % 12 % 21 %
NGL sales 12 % 14 % (2) % (14) %
Natural gas sales 11 % 11 % - % - %
Sales of purchased oil 7 % 17 % (10) % (59) %
Other operating revenues - % - % - % - %
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, 2022 compared to 2021
2022 2021 Change (#) Change (%)
Sales volumes:
Oil (MBbl) 13,838 11,619 2,219 19 %
NGL (MBbl) 8,028 8,678 (650) (7) %
Natural gas (MMcf) 49,259 57,175 (7,916) (14) %
Oil equivalents (MBOE)(1)(2)
30,076 29,827 249 1 %
Average daily oil equivalent sales volumes (BOE/D)(2)
82,400 81,717 683 1 %
Average daily oil sales volumes (Bbl/D)(2)
37,912 31,833 6,079 19 %
Sales revenues (in thousands):
Oil $ 1,351,207 $ 805,448 $ 545,759 68 %
NGL 234,613 191,591 43,022 22 %
Natural gas 208,554 150,104 58,450 39 %
Total oil, NGL and natural gas sales revenues $ 1,794,374 $ 1,147,143 $ 647,231 56 %
Average sales prices(2):
Oil ($/Bbl)(3)
$ 97.65 $ 69.32 $ 28.33 41 %
NGL ($/Bbl)(3)
$ 29.22 $ 22.08 $ 7.14 32 %
Natural gas ($/Mcf)(3)
$ 4.23 $ 2.63 $ 1.60 61 %
Average sales price ($/BOE)(3)
$ 59.66 $ 38.46 $ 21.20 55 %
Oil, with commodity derivatives ($/Bbl)(4)
$ 70.32 $ 52.09 $ 18.23 35 %
NGL, with commodity derivatives ($/Bbl)(4)
$ 24.29 $ 10.55 $ 13.74 130 %
Natural gas, with commodity derivatives ($/Mcf)(4)
$ 2.83 $ 1.56 $ 1.27 81 %
Average sales price, with commodity derivatives ($/BOE)(4)
$ 43.48 $ 26.36 $ 17.12 65 %
_____________________________________________________________________________
(1)BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)The numbers presented in the years ended December 31, 2022 and 2021 columns are based on actual amounts and may not recalculate using the rounded numbers presented in the table above or the table below.
(3)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.
(4)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 and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods.
The following table presents net settlements 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, 2022 compared to 2021
(in thousands) 2022 2021 Change ($) Change (%)
Net settlements paid for matured commodity derivatives:
Oil $ (378,163) $ (158,612) $ (219,551) (138) %
NGL (39,587) (100,029) 60,442 60 %
Natural gas (68,965) (60,810) (8,155) (13) %
Total $ (486,715) $ (319,451) $ (167,264) (52) %
Net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil $ - $ (41,553) $ 41,553 100 %
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, 2022 and 2021:
(in thousands) Oil NGL Natural gas Total
2021 Revenues $ 805,448 $ 191,591 $ 150,104 $ 1,147,143
Effect of changes in average sales prices 391,955 57,373 79,233 528,561
Effect of changes in sales volumes 153,804 (14,351) (20,783) 118,670
2022 Revenues $ 1,351,207 $ 234,613 $ 208,554 $ 1,794,374
Change ($) $ 545,759 $ 43,022 $ 58,450 $ 647,231
Change (%) 68 % 22 % 39 % 56 %
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, 2022 compared to 2021
(in thousands) 2022 2021 Change ($) Change (%)
Sales of purchased oil $ 119,408 $ 240,303 $ (120,895) (50) %
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 utilize purchased oil to fulfill portions of our commitments. In previous periods, we also utilized purchased oil to fulfill portions of our Bridgetex pipeline commitment, which ended during the first quarter of 2022. 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. Sales of purchased oil decreased during the year ended December 31, 2022 compared to 2021 primarily due to a decrease in the volumes of purchased oil as our Bridgetex pipeline commitment ended during the first quarter of 2022, partially offset by an increase in sales prices.
We enter into purchase transactions with third parties and separate sale transactions. These transactions are presented on a gross basis as we act as the principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. The transportation costs associated with these transactions are presented as a component of costs of purchased oil. See "-Costs and expenses - Costs of purchased oil."
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, 2022 compared to 2021
(in thousands except for per BOE sold data) 2022 2021 Change ($) Change (%)
Costs and expenses:
Lease operating expenses $ 173,983 $ 101,994 $ 71,989 71 %
Production and ad valorem taxes 110,997 68,742 42,255 61 %
Transportation and marketing expenses 53,692 47,916 5,776 12 %
Costs of purchased oil 122,118 251,061 (128,943) (51) %
General and administrative (excluding LTIP) 57,501 45,906 11,595 25 %
General and administrative (LTIP):
LTIP cash 3,307 10,299 (6,992) (68) %
LTIP non-cash 7,274 6,596 678 10 %
Organizational restructuring expenses 10,420 9,800 620 6 %
Depletion, depreciation and amortization 311,640 215,355 96,285 45 %
Impairment expense 40 1,613 (1,573) (98) %
Other operating expenses, net 8,583 6,381 2,202 35 %
Total costs and expenses $ 859,555 $ 765,663 $ 93,892 12 %
Gain (loss) on disposal of assets, net (1,079) 84,551 (85,630) (101) %
Selected average costs and expenses per BOE sold(1):
Lease operating expenses $ 5.78 $ 3.42 $ 2.36 69 %
Production and ad valorem taxes 3.69 2.30 1.39 60 %
Transportation and marketing expenses 1.79 1.61 0.18 11 %
General and administrative (excluding LTIP) 1.91 1.54 0.37 24 %
Total selected operating expenses $ 13.17 $ 8.87 $ 4.30 48 %
General and administrative (LTIP):
LTIP cash $ 0.11 $ 0.35 $ (0.24) (69) %
LTIP non-cash $ 0.24 $ 0.22 $ 0.02 9 %
Depletion, depreciation and amortization $ 10.36 $ 7.22 $ 3.14 43 %
____________________________________________________________________________
(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, 2022 compared to 2021. 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 2022 due to inflationary pressures and costs associated with integrating our assets from the Sabalo/Shad Acquisition and Pioneer Acquisition, primarily driven by costs related to artificial lift and flowback management. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to LOE. Total LOE is expected to increase for 2023 as more of our production shifts to high-value Howard County wells, where, among other things, we have higher water production, resulting in increased water handling and lifting costs.
Production and ad valorem taxes
Production and ad valorem taxes increased for the year ended December 31, 2022 compared to 2021 due to increased oil, NGL and natural gas sales 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.
Transportation and marketing expenses
Transportation and marketing expenses increased for the year ended December 31, 2022 compared to 2021. These are expenses incurred for the delivery of produced oil to customers in the U.S. Gulf Coast market via the Gray Oak pipeline and, in previous years and the first quarter of 2022, the Bridgetex pipeline. We ship the majority of our produced oil to the U.S. Gulf Coast, which we believe provides a long-term pricing advantages versus the Midland market. Additionally, firm transportation payments on excess pipeline capacity associated with transportation agreements are included in 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.
Costs of purchased oil
During the year ended December 31, 2022, we were a firm shipper on the Gray Oak pipeline and we utilized purchased oil to fulfill portions of our commitments. In previous years and the first quarter of 2022, we also utilized purchased oil to fulfill portions of our Bridgetex pipeline commitment, which ended during the first quarter of 2022. In the event our long-haul transportation capacity on the Gray Oak pipeline is expected to exceed our net production, consistent with our historic practice, we expect to continue to purchase third-party oil at the trading hubs to satisfy the deficit in our associated long-haul transportation commitments. Costs of purchased oil decreased for the year ended December 31, 2022, compared to the same period in 2021 primarily due to a decrease in the volumes of purchased oil on pipelines as our Bridgetex pipeline commitment ended during the first quarter of 2022 and an increase in produced oil volumes, partially offset by an increase in sales prices.
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"), increased for the year ended December 31, 2022 compared to 2021 mainly due to (i) increases in workforce and professional expenses and (ii) inflationary pressures.
LTIP cash expense decreased for the year ended December 31, 2022 compared to 2021. These decreases are primarily due to (i) forfeitures of cash-settled performance unit awards in connection with the departure of our former Senior Vice President and Chief Operating Officer during the third quarter of 2022 and (ii) a decrease in the fair values of our cash-settled LTIP awards during the year ended December 31, 2022, mainly due to the performance of our stock during the period.
LTIP non-cash expense increased for the year ended December 31, 2022 compared to 2021, mainly due to new share-settled LTIP awards granted to our employees during the second half of 2021 and the first half of 2022, and partially offset by forfeitures of share-settled LTIP awards in connection with the departure of our former Senior Vice President and Chief Operating Officer during the third quarter of 2022. See Notes 2, 9 and 17 to our consolidated financial statements included elsewhere in this Annual Report for information regarding our equity-based compensation.
Organizational restructuring expenses
Organizational restructuring expenses increased for the year ended December 31, 2022 compared to 2021. Such expenses were incurred for (i) the departure our former Senior Vice President and Chief Operating Officer during the third quarter of 2022 and (ii) a workforce reduction during the second quarter of 2021. See Note 17 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of the organizational restructurings.
Depletion, depreciation and amortization ("DD&A")
The following table presents depletion expense per BOE sold for the periods presented and the corresponding changes for such periods:
Years ended December 31, 2022 compared to 2021
(in thousands) 2022 2021 Change ($) Change (%)
Depletion expense per BOE sold $ 9.92 $ 6.76 $ 3.16 47 %
Depletion expense per BOE increased for the year ended December 31, 2022 compared to 2021 primarily due to an increase in the book value of our oil and natural gas properties as a result of the Sabalo/Shad Acquisition and Pioneer Acquisition and the associated development costs, which includes the effects of inflationary pressures.
See Note 6 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding the full cost method of accounting.
Gain (loss) on disposal of assets, net
Gain (loss) on disposal of assets, net, decreased for the year ended December 31, 2022 compared to 2021, primarily due to the gain recorded in third-quarter 2021 in connection with the Working Interest Sale. See Note 4 to our consolidated financial statements included elsewhere in this Annual Report for additional discussion regarding the gain on the Working Interest Sale. From time to time, we dispose of inventory, midstream service assets and other fixed assets. The associated gain or loss recorded during the period fluctuates depending on the volume of the assets disposed, their associated net book value and, in the case of a disposal by sale, the sale price.
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, 2022 compared to 2021
(in thousands) 2022 2021 Change ($) Change (%)
Loss on derivatives, net $ (298,723) $ (452,175) $ 153,452 34 %
Interest expense (125,121) (113,385) (11,736) (10) %
Loss on extinguishment of debt, net (1,459) - (1,459) (100) %
Other income, net 2,155 1,250 905 72 %
Total non-operating expense, net $ (423,148) $ (564,310) $ 141,162 25 %
Loss on derivatives, net
The following table presents the components of loss on derivatives, net for the periods presented and corresponding changes for such periods:
Years ended December 31, 2022 compared to 2021
(in thousands) 2022 2021 Change ($) Change (%)
Non-cash gain (loss) on derivatives, net $ 185,573 $ (140,348) $ 325,921 232 %
Settlements paid for matured derivatives, net (486,753) (320,868) (165,885) (52) %
Settlements received for contingent consideration 2,457 - 2,457 100 %
Premiums received for commodity derivatives - 9,041 (9,041) (100) %
Loss on derivatives, net $ (298,723) $ (452,175) $ 153,452 34 %
Non-cash gain (loss) on derivatives, net is the result of (i) 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 and (ii) matured interest rate swaps and the changing relationship between the contract interest rate and the LIBOR interest rate forward curve. 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 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, (ii) interest rate derivative and (iii) contingent consideration derivatives.
We classify the derivatives gains and losses 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, 2022 compared to 2021. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Senior Secured Credit Facility and our senior unsecured notes. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. 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 (including origination, amendment and professional fees), (ii) commitment fees and (iii) annual agency fees in interest expense. During the third quarter of 2021, we completed the offering of the July 2029 Notes, with interest payable semi-annually commencing January 31, 2022 with interest from closing to that date. The increase during the year ended December 31, 2022 reflects a full year-to-date of interest expense incurred for the July 2029 Notes and higher interest expense on outstanding balances under our Senior Secured Credit Facility resulting from increases in interest rates by the U.S. Federal Reserve. See Note 7 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding our debt and interest expense.
Income tax (expense) benefit
The following table presents income tax (expense) benefit for the periods presented and corresponding changes for such periods:
Years ended December 31, 2022 compared to 2021
(in thousands) 2022 2021 Change ($) Change (%)
Current $ (6,121) $ (1,324) $ (4,797) (362) %
Deferred $ 619 $ (2,321) $ 2,940 127 %
We are subject to federal and state income taxes and the Texas franchise tax. The income tax (expense) benefit for the year ended December 31, 2022 is attributed to Texas franchise tax, due to a full valuation allowance recorded against the federal and Oklahoma deferred tax assets.
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 ("NOL carryforwards") arising prior to the ownership change would be limited. As of December 31, 2022, no such ownership change has occurred.
With the rise in oil prices and the addition of oily, high-margin inventory, we have seen positive indications that we will use our NOLs. We utilized $281.6 million of our NOLs on our 2021 tax return and expect to utilize a comparable amount on our 2022 tax return. However, as of December 31, 2022, we believe it is more likely than not that a portion of the NOL carryforwards are not fully realizable. We continue to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from our oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2022, and our ability to capitalize intangible drilling costs, rather than expensing these costs and future projections of Oklahoma sourced income. Significant items of objective negative evidence considered were the cumulative historical three-year pre-tax loss and a net deferred tax asset position at December 31, 2022.
We currently believe it is reasonably possible we could achieve a three-year cumulative level of profitability within the next 12 months, which would enhance our ability to conclude that it is more likely than not that the deferred tax assets would be
realized and support a release of the valuation allowance. However, the exact timing and amount of the release is unknown at this time. As long as we continue to conclude that the valuation allowance recorded against our net deferred tax assets is necessary, we will not have significant deferred income tax expense or benefit. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income.
Liquidity and capital resources
Historically, our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from senior unsecured note 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. During the year ended December 31, 2022, we have utilized our cash flows to fund the repurchase of portions of our senior unsecured notes and our share repurchase program. For additional discussion of the repurchase of our senior unsecured notes and our share repurchase program, see Notes 7 and 8, respectively to our consolidated financial statements included elsewhere in this Annual Report.
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 continuously look for other opportunities to maximize shareholder 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. Due to the inherent volatility in interest rates, we will, 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. 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. As of December 31, 2022, 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 18 to our consolidated financial statements included elsewhere in this Annual Report for discussion of our open commodity positions.
As of December 31, 2022, we had cash and cash equivalents of $44.4 million and available capacity under the Senior Secured Credit Facility of $930.0 million, resulting in total liquidity of $974.4 million. As of February 17, 2023, we had cash and cash equivalents of $15.6 million and available capacity under the Senior Secured Credit Facility of $865.0 million, resulting in total liquidity of $880.6 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.
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, 2022:
(in thousands) Short-term Long-term Total
Senior unsecured notes $ 96,803 $ 1,394,575 $ 1,491,378
Senior Secured Credit Facility - 70,000 70,000
Asset retirement obligations 3,715 70,366 74,081
Firm transportation commitments 17,555 57,043 74,598
Operating lease commitments
16,467 10,153 26,620
Total $ 134,540 $ 1,602,137 $ 1,736,677
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, 2022 compared to 2021
(in thousands) 2022 2021 Change ($) Change (%)
Net cash provided by operating activities $ 829,620 $ 496,671 $ 332,949 67 %
Net cash used in investing activities (475,952) (796,811) 320,859 40 %
Net cash (used in) provided by financing activities (366,031) 308,181 (674,212) (219) %
Net (decrease) increase in cash and cash equivalents $ (12,363) $ 8,041 $ (20,404) (254) %
Cash flows from operating activities
Net cash provided by operating activities increased during the year ended December 31, 2022, compared to 2021. Notable cash changes include (i) an increase in total oil, NGL and natural gas sales revenues of $647.2 million, (ii) a decrease of $174.3 million due to changes in net settlements received for matured, net of premiums paid, mainly due to increases in commodity prices and (iii) a decrease of $16.4 million due to net changes in operating assets and liabilities. Other significant changes include an increase in lease operating expense and production and ad valorem taxes. The increase in total oil, NGL and natural gas sales revenues is due to a 55% increase in average sales price per BOE as well as a 19% increase in oil volumes sold. 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 decreased during the year ended December 31, 2022, compared to 2021, mainly due to (i) a decrease in acquisitions of oil and natural gas properties and (ii) an increase in capital expenditures, which includes the effects of inflationary pressures. Such items are partially offset by a decrease in proceeds from the sale of capital assets, which includes proceeds of $106.5 million for 2022 related to the sale of the Company's working interests in certain specified
non-operated oil and gas properties. 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 expenditures
We currently expect capital expenditures for 2023 to be in the approximate range of $625.0 million to $675.0 million. We are prepared to adjust our capital expenditures further if oil, NGL and natural gas prices continue to exhibit volatility. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
The following table presents the components of our incurred capital expenditures, excluding non-budgeted acquisition costs, for the periods presented and corresponding changes for such periods:
Years ended December 31, 2022 compared to 2021
(in thousands) 2022 2021 Change ($) Change (%)
Oil and natural gas properties(1)
$ 566,831 $ 444,337 $ 122,494 28 %
Midstream service assets 1,595 2,842 (1,247) (44) %
Other fixed assets 12,150 6,807 5,343 78 %
Total incurred capital expenditures, excluding non-budgeted acquisition costs $ 580,576 $ 453,986 $ 126,590 28 %
_____________________________________________________________________________
(1)See Note 19 to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding our incurred capital expenditures in the exploration and development of oil and natural gas properties.
The amount, timing and allocation of capital expenditures 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 $308.2 million during the year ended December 31, 2021, compared to net cash used in financing activities of $366.0 million during the year ended December 31, 2022. In 2022, we began executing our strategy to return cash to shareholders through redemption of our senior unsecured notes and repurchasing our equity, which consisted of extinguishment of debt on our senior unsecured notes of $282.9 million and share repurchases of $37.3 million during the year ended December 31, 2022. Other notable 2022 activity includes (i) borrowings on our Senior Secured Credit Facility of $455.0 million, (ii) payments on our Senior Secured Credit Facility of $490.0 million and (iii) stock exchanged for tax withholding of $7.4 million. Notable 2021 activity includes borrowings on our Senior Secured Credit Facility, proceeds from the issuance of our July 2029 Notes and proceeds from our "at-the-market" equity program (the "ATM Program"), partially offset by payments on our Senior Secured Credit Facility. 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
We are the borrower under our Senior Secured Credit Facility and a party to the indentures governing our senior unsecured notes.
Senior Secured Credit Facility
As of December 31, 2022, our Fifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility") had a maximum credit amount of $2.0 billion, a borrowing base of $1.3 billion and an aggregate elected commitment of $1.0 billion, with $70.0 million outstanding, and was subject to an interest rate of 6.897%. 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, 2022 and 2021, we had no letters of credit outstanding and one letter of credit outstanding of $44.1 million, respectively 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.
January 2025 Notes, January 2028 Notes and July 2029 Notes
The following table presents principal amounts and applicable interest rates for our outstanding January 2025 Notes, January 2028 Notes and July 2029 Notes as of December 31, 2022:
(in millions, except for interest rates) Principal Interest rate
January 2025 Notes $ 455.6 9.500 %
January 2028 Notes 300.3 10.125 %
July 2029 Notes 298.2 7.750 %
Total senior unsecured notes $ 1,054.1
During the year ended December 31, 2022, we repurchased a total of $284.8 million in aggregate principal amount of our senior unsecured notes. See Note 7 to our consolidated financial statements included elsewhere in this Annual Report for further discussion of these repurchases.
Supplemental Guarantor information
As of December 31, 2022, approximately $1.1 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 the January 2025 Notes, January 2028 Notes and July 2029 Notes. On February 3, 2023, Garden City Minerals, LLC ("GCM"), our former other wholly-owned subsidiary, was merged with and into Vital Energy, Inc. and is therefore no longer a guarantor under any of our debt arrangements.
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 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.
Non-GAAP financial measures
The non-GAAP financial measures of Free Cash Flow and Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Furthermore, these non-GAAP financial measures should not be considered in isolation or as a substitute for GAAP measures of liquidity or financial performance, but rather should be considered in conjunction with GAAP measures, such as net income or loss, operating income or loss or cash flows from operating activities.
Free Cash Flow
Free Cash Flow is a non-GAAP financial measure that we define as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less incurred capital expenditures, excluding non-budgeted acquisition costs. Management believes Free Cash Flow is useful to management and investors in evaluating operating trends in our business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.
The following table presents a reconciliation of net cash provided by operating activities (GAAP) to Free Cash Flow (non-GAAP) for the periods presented:
Years ended December 31
(in thousands) 2022 2021
Net cash provided by operating activities $ 829,620 $ 496,671
Less:
Change in current assets and liabilities, net 54,260 49,321
Change in noncurrent assets and liabilities, net (25,157) (3,807)
Cash flows from operating activities before changes in operating assets and liabilities, net 800,517 451,157
Less incurred capital expenditures, excluding non-budgeted acquisition costs:
Oil and natural gas properties(1)
566,831 444,337
Midstream service assets(1)
1,595 2,842
Other fixed assets 12,150 6,807
Total incurred capital expenditures, excluding non-budgeted acquisition costs 580,576 453,986
Free Cash Flow (non-GAAP) $ 219,941 $ (2,829)
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss (GAAP) plus adjustments for share-settled equity-based compensation; depletion, depreciation and amortization; impairment expense; gains or losses on disposal of assets; mark-to-market on derivatives; premiums paid or received for commodity derivatives that matured during the period; accretion expense; interest expense; income taxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for future discretionary use because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:
•is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;
•helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and
• is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting.
There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Adjusted EBITDA reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.
The following table presents a reconciliation of net income (GAAP) to Adjusted EBITDA (non-GAAP) for the periods presented:
Years ended December 31,
(in thousands) 2022 2021
Net income $ 631,512 $ 145,008
Plus:
Share-settled equity-based compensation, net 8,403 7,675
Depletion, depreciation and amortization 311,640 215,355
Impairment expense 40 1,613
Organizational restructuring expenses 10,420 9,800
(Gain) loss on disposal of assets, net 1,079 (84,551)
Mark-to-market on derivatives:
Loss on derivatives, net 298,723 452,175
Settlements paid for matured derivatives, net (486,753) (320,868)
Settlements received for contingent consideration 2,457 -
Net premiums paid for commodity derivatives that matured during the period(1)
- (41,553)
Accretion expense 3,879 4,233
Interest expense 125,121 113,385
Loss on extinguishment of debt, net 1,459 -
Income tax expense 5,502 3,645
Adjusted EBITDA (non-GAAP) $ 913,482 $ 505,917
_____________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
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 and (ii) future cash flows from oil and natural gas properties.
There have been no material changes in our critical accounting estimates during the year ended December 31, 2022.
Oil, NGL and natural gas reserve quantities 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. 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. 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 economic conditions. As a result, material revisions to existing reserve estimates 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 that may be material. See Note 19 to our consolidated financial statements 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.
New accounting standards
There are no new accounting standards not yet adopted and meaningful to disclose as of December 31, 2022. Additionally, we did not adopt any new accounting standards during the year ended December 31, 2022.

---

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, 2022:
(in thousands) As of December 31, 2022
Commodity derivative asset position $ 16,433
Impact of a 10% increase in forward commodity prices $ (27,299)
Impact of a 10% decrease in forward commodity prices $ 25,878
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, 2022 was 6.897%. 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 publically 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 form 1.5% to 2.5% on alternate base rate borrowings and from 2.5% to 3.5% on Term SOFR borrowings, in each case, depending on our utilization ratio. At December 31, 2022, the applicable margin on our borrowings were 1.5% for alternate base rate borrowings and 2.5% 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.

---

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, 2022, 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, 2022.
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, 2022. The report, which expresses an unqualified opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2022, 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, 2022, 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, 2022, 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 2022 consolidated financial statements of the Company and our report dated February 22, 2023 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 22, 2023

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
On June 3, 2022, following the completion of a comprehensive evaluation process, our Audit Committee dismissed Grant Thornton LLP (“Grant Thornton”) and appointed Ernst & Young LLP (“EY”) as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2022. The change was effective immediately.
Grant Thornton’s audit report on the Company’s consolidated financial statements for the fiscal years ended December 31, 2021 and 2020 did not contain an adverse opinion or a disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope or accounting principle.
During the fiscal years ended December 31, 2021 and 2020 and through the subsequent interim period ending June 3, 2022, there were (i) no disagreements (as that term is defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions) between the Company and Grant Thornton on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which, if not resolved to the satisfaction of Grant Thornton would have caused Grant Thornton to make reference to the subject matter thereof in connection with its reports on the consolidated financial statements of the Company for such years, and (ii) no “reportable events” (as that term is defined in Item 304(a)(1)(v) of Regulation S-K).
During the fiscal years ended December 31, 2021 and 2020 and through the subsequent interim period ending June 3, 2022, neither the Company, nor any party on behalf of the Company, consulted with EY with respect to either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of the audit opinion that might be rendered with respect to the Company’s consolidated financial statements, and no written report or oral advice was provided to the Company by EY that was an important factor considered by the Company in reaching a decision as to any accounting, auditing or financial reporting issue, or (ii) any matter that was subject to any disagreement (as that term is defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions) or a reportable event (as that term is defined in Item 304(a)(1)(v) of Regulation S-K).

---

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, 2022 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, 2022. 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.

---

ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
Not applicable.

---

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, 2022.

---

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, 2022.

---

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, 2022.

---

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, 2022.

---

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, 2022.
Part IV

---

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
Agreement and Plan of Merger by and between Laredo Petroleum, LLC and Laredo Petroleum Holdings, Inc., dated as of December 19, 2011.
8-K 2.1 12/22/2011
2.2
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
2.3
Purchase and Sale Agreement by and between Vital Energy, Inc. and Driftwood Energy Operating, LLC, dated as of February 14, 2023.
8-K 2.1 2/15/2023
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
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
3.4
Certificate of Ownership and Merger, dated as of December 30, 2013.
8-K 3.1 1/6/2014
3.5
Fourth Amended and Restated Bylaws of Vital Energy, Inc., adopted January 9, 2023.
8-K 3.2 1/9/2023
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
Third Supplemental Indenture, dated as of January 24, 2020, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, N.A., as trustee.
8-K 4.4 1/24/2020
4.5
Fourth Supplemental Indenture, dated as of January 24, 2020, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, N.A., as trustee.
8-K 4.6 1/24/2020
4.6
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
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
Incorporated by reference (File No. 001-35380, unless otherwise indicated)
Exhibit Description Form Exhibit Filling Date
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
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
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
10.13
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
10.14#*
Vital Energy, Inc. Omnibus Equity Incentive Plan, as amended and restated as of January 9, 2023.
10.15#*
Vital Energy, Inc. Change in Control Executive Severance Plan, as last amended January 9, 2023.
10.16#*
Vital Energy, Inc. Executive Severance Plan, as amended and restated as of January 9, 2023.
10.17#
Offer Letter, dated April 17, 2019, between Laredo Petroleum, Inc. and Mr. Jason Pigott.
10-Q 10.3 5/2/2019
10.18#
Offer Letter, dated June 12, 2020, between Laredo Petroleum, Inc. and Mr. Bryan J. Lemmerman.
10-Q 10.3 8/6/2020
10.19#
Form of Stock Option Agreement.
8-K 10.3 5/25/2016
10.20#
Form of 2020 Performance Share Unit Award Agreement.
10-K 10.18 2/22/2021
10.21#
Form of 2021 Performance Share Unit Award Agreement.
10-Q 10.3 5/6/2021
10.22#
Form of 2022 Performance Share Unit Award Agreement.
10-Q 10.2 5/5/2022
10.23#
Form of 2022 Restricted Share Unit Award Agreement.
10-Q 10.3 5/5/2022
10.24#*
Form of 2023 Performance Share Unit Award Agreement.
10.25#
Form of Outperformance Share Unit Award Agreement.
10-Q 10.8 8/1/2019
10.26#
Form of Restricted Stock Unit Agreement.
8-K 10.2 5/25/2016
10.27#
Form of Phantom Unit Agreement.
10-K 10.21 2/22/2021
21.1*
List of Subsidiaries.
22.1*
List of Issuers and Guarantor Subsidiaries.
23.1*
Consent of Ernst & Young LLP.
23.2*
Consent of Grant Thornton LLP.
23.3*
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.
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.
99.1*
Summary Report of Ryder Scott Company, L.P.
Incorporated by reference (File No. 001-35380, unless otherwise indicated)
Exhibit Description Form Exhibit Filling Date
101 The following financial information from Vital's Annual Report on Form 10-K for the year ended December 31, 2022, 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 SEC on request.