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What changed in CIVITAS RESOURCES, INC.'s 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of CIVITAS RESOURCES, INC.'s 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+701 added−770 removedSource: 10-K (2024-02-27) vs 10-K (2023-02-22)

Top changes in CIVITAS RESOURCES, INC.'s 2023 10-K

701 paragraphs added · 770 removed · 187 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

10 edited+205 added−309 removed1 unchanged
Biggest changeIn January 2021, the results of a major rulemaking took effect addressing a wide range of topics including facility siting, cumulative impacts, development approvals, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, and wildlife protection, and those rules apply to permit applications pending on or submitted after that date and generally to operations occurring on or after that date.
Biggest changeFor example, the states in which we operate have implemented or are considering additional regulations governing a range of topics, including facility siting, development approvals, cumulative impacts, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, wildlife protection, and financial assurance.
In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. On November 15, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.
In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.
The adoption of future federal, state, or local laws or implementing regulations imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products.
The adoption of future federal, state, or local laws or implementing regulations imposing new environmental, operational, and/or financial assurance obligations on, or otherwise limiting, our operations could make it more difficult, more expensive, and/or impossible to complete crude oil and natural gas wells, increase our costs of compliance operations, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products.
We are subject to extensive federal, state, and local laws and regulations concerning public health and safety, and environmental protection. Government authorities frequently review, revise and supplement these requirements, and both oil and gas development generally, and hydraulic fracturing specifically, are receiving increasing regulatory attention.
We are subject to extensive federal, state, and local laws and regulations, including those concerning public and occupational health and safety and environmental protection. Governmental authorities frequently review, revise, and supplement these requirements, and both oil and gas development generally, and hydraulic fracturing specifically, are receiving increasing legislative and regulatory attention.
Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production. States have historically regulated oil and gas exploration and production activity, including hydraulic fracturing.
Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of crude oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production.
Additional limitations on GHG emissions could adversely affect our production operations and/or demand for the oil and natural gas we produce. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could also reduce demand for the oil and natural gas we produce.
Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the crude oil and natural gas we produce.
Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA is expected to issue a final rule by August 2023.
Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA announced a final rule in December 2023, which, among other things, requires the phase out of routine flaring of natural gas from new crude oil wells and routine leak monitoring at all well sites and compressor stations.
We cannot assure that any such outcome would not be material, and any such outcome could have a material and adverse impact on our cash flows and results of operations. Our use of hydraulic fracturing. We use hydraulic fracturing as a means to maximize production of oil and gas from formations having low permeability such that natural flow is restricted.
We cannot assure that any such outcome would not be material, and any such outcome could have a material adverse impact on our cash flows and results of operations.
Further, on November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources.
Further, the EPA has continued with its comprehensive strategy for further reducing methane emissions from oil and gas operations, with a final rule being issued in June 2016 as part of the Subpart OOOOa NSPS. In November 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources.
Cumulatively, these laws and regulations may impact our operations. The following is a summary of the more significant environmental and health and safety laws and regulations to which we are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations, or financial position.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise have a material adverse effect on our own results of operations, competitive position, or financial condition.
Removed
Item 1. Business When we use the terms “Civitas,” the “Company,” “we,” “us,” or “our,” we are referring to Civitas Resources, Inc. and its consolidated subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary of Oil and Natural Gas Terms above.
Added
Item 1. Business - Regulation of the Crude Oil and Natural Gas Industry ” for more information regarding the new and proposed state environmental regulations applicable to our business. In addition, there have been several citizen/activist lawsuits filed against industry and state and local regulators associated with air quality, siting, environmental justice, and climate change.
Removed
Throughout this document, we make statements that may be classified as “forward-looking.” Please refer to the Information Regarding Forward-Looking Statements section above for an explanation of these types of statements.
Added
Such anti-development efforts are likely to continue in the future, which could result in dramatically reducing the area of future oil and gas development in the states in which we conduct our operations. These efforts could have a material adverse effect on our business, financial condition, and results of operations.
Removed
Overview Civitas is an independent exploration and production company focused on the acquisition, development, and production of oil and associated liquids-rich natural gas in the Rocky Mountain region, primarily in the Denver-Julesburg Basin of Colorado (the “DJ Basin”).
Added
SB 181’s requirement, which applies to our Colorado operations, that we own or control more than 45% of the working or mineral interest in order to statutorily pool our applicable interest may make it much more difficult for us to develop such interests, which could have a material adverse effect on our business, financial condition, and results of operations.
Removed
Our operations are focused on developing the horizontal Niobrara and Codell formations that have a low-cost structure, mature infrastructure, strong production efficiencies, multiple producing horizons, multiple service providers, established reserves, and prospective drilling opportunities, which help facilitate predictable production and achieve our business strategies. As of December 31, 2022, we had approximately 525,900 net acres in the Rocky Mountain region.
Added
With respect to our operations in the DJ Basin in Colorado, in some cases, we do not own more than 45% working interest or mineral interest in a prospective area of development, which is now required to statutorily pool our applicable working or mineral interests.
Removed
Approximately 470,000 net, or 89%, of the Company’s acreage is located in some of the most productive areas of the DJ Basin. We believe our acreage has been significantly delineated by our own drilling success and by the success of offset operators, providing confidence that our results are repeatable and will continue to generate economic returns.
Added
In such cases, unless we can obtain the consent of more than 45% of all applicable working or mineral interest owners (who can be located through reasonable diligence) to pursue statutory pooling, or achieve a voluntary pooling agreement with 100% of the applicable interest owners, we may be prohibited from developing the resources in that area or having them be developed by other operators.
Removed
As of December 31, 2022, we operated a total of 3,108 gross producing wells, of which 2,551 were horizontal. Our working and net revenue interest in our operated wells averaged approximately 80% and 65%, respectively. We are committed to pursuing compelling economic returns and generating significant free cash flow.
Added
Terrorist attacks and armed conflict could have a material adverse effect on our business, financial condition, or results of operations. Terrorist attacks and armed conflict may significantly affect the energy industry, including our operations and those of our current and potential customers, as well as general economic conditions, consumer confidence and spending, and market liquidity.
Removed
To that end, we strive to deliver a peer-leading operating cost structure, maximize capital efficiencies, and minimize capital reinvestment rates, while keeping production broadly flat over time. Our technical staff of geologists, petroleum engineers, and geophysicists have decades of industry experience and are experts in horizontal drilling and fracture stimulation.
Added
Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the U.S. Our insurance may not protect against such occurrences.
Removed
We are focused on exceptional performance in managing the Environmental, Social, and Governance (“ESG”) aspects of our business, with the goal of mitigating risks while benefiting our stakeholders and partnering with the communities where we operate.
Added
Furthermore, commodity markets are currently also subject to heightened levels of uncertainty related to the Russian military invasion of Ukraine, which has given rise to regional instability and resulted in heightened economic sanctions by the U.S. and the international community that, in turn, could increase uncertainty with respect to global financial markets and production output from the Organization of Petroleum Exporting Countries and other crude oil producing nations.
Removed
The Company is also actively pursuing projects designed to reduce or eliminate carbon emissions associated with its operations and then offsets remaining emissions through the retirement of certified carbon offsets and renewable energy credits. Additionally, we established the Civitas Community Foundation in 2022, and we intend to invest in a comprehensive retrofit of natural gas pneumatic devices starting in 2023.
Added
Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations. We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues.
Removed
Our Business Strategies The Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and natural gas resources. To achieve this, Civitas is guided by four foundational pillars that we believe add long-term, sustainable value. These pillars are: • Generate free cash flow. Our investment opportunities are evaluated primarily in the context of maximizing free cash flow.
Added
We do not operate all of the properties in which we have an interest. We own significant non-operated working interests which are not currently within our operated development plan. As a result, we may have a limited ability to exercise influence over normal operating procedures, expenditures, timing, or future development of underlying properties, and their associated costs.
Removed
We have a high-quality asset base, allowing us to create synergies and maintain a low-cost structure. We pursue value-accretive investments to enhance our ability to deliver incremental free cash flow to our shareholders.
Added
For all of the properties that are operated by others, we are dependent on their decision-making with respect to day-to-day operations over which we have little control.
Removed
During 2022, Civitas generated approximately $1.2 billion of free cash flow (a non-GAAP financial measure — please refer to the Reconciliation of Free Cash Flow to Cash Provided by Operating Activities presented in Part II, Item 7, Non-GAAP Financial Measures of this report). • Maintain a premier balance sheet.
Added
The failure of an operator of wells in which we have an interest to adequately perform operations, or an operator’s breach of applicable agreements, could reduce production and revenues we receive from that well.
Removed
A strong balance sheet, focus on cost control, and minimizing long-term commitments are critical to managing risk and achieving success within fluctuating market conditions.
Added
The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including the timing and amount of capital expenditures, the available expertise and financial resources, the inclusion of other participants, and the use of technology.
Removed
As evidenced by our strong liquidity position of approximately $1.8 billion as of December 31, 2022, as discussed in Part II, Item 7, Liquidity and Capital Resources , we believe Civitas has among the strongest balance sheets in the exploration and production sector. 11 Table of Contents • Return free cash flow to shareholders.
Added
Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, revenues, production, liability, and other related matters. 47 Table of Contents The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Removed
We prioritize consistently delivering free cash flow to shareholders through our published dividend framework. During 2022, we returned more than $530 million to investors through base and variable dividends, including approximately $166 million paid in December 2022. We believe Civitas has one of the industry’s highest payout ratios with an approximate 11% yield at year-end.
Added
Therefore, our undeveloped reserves may not be ultimately developed or produced. Approximately 22% of our total proved reserves were classified as proved undeveloped as of December 31, 2023. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate or that may be available to us.
Removed
In early 2023, we used cash-on-hand to repurchase approximately 4.9 million shares from our largest shareholder, CPPIB Crestone Peak Resources Canada Inc., further underscoring our commitment to this priority. • Demonstrate ESG Leadership.
Added
Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.
Removed
We have integrated ESG initiatives throughout our organization and strive to reduce and eliminate emissions while seeking to comply with all applicable air quality and other environmental rules and regulations.
Added
In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves. Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage.
Removed
We employ industry-leading best practices, including electric drilling rigs and frac spreads, 24/7 air monitoring technology and pipeline gathering and takeaway, as well as vapor recovery, automated shut-in and remote monitoring equipment for producing wells where feasible and appropriate.
Added
Our ability to drill and develop these locations is subject to a number of uncertainties, including uncertainty in the level of reserves; the availability of capital to us and other participants; seasonal conditions; regulatory approvals; activist intervention; crude oil, natural gas, and NGL prices; availability of permits; costs; and well performance.
Removed
We believe Civitas is Colorado’s first carbon neutral operator on both a Scope 1 and Scope 2 basis, meaning that Civitas is at a neutral balance between emitting and removing carbon from the atmosphere. We regularly engage community stakeholders in our development planning and operations. We strive to maintain a safe workplace for our employees and contractors at all times.
Added
Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations.
Removed
During 2022, we maintained a meaningful safety track record as evidenced by a low total recordable incident rate of 0.19 as further discussed within Human Capital below.
Added
Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible categories any proved undeveloped reserves that are not developed within this five-year time frame.
Removed
Finally, our Board of Directors (the “Board”) also has a dedicated ESG Committee that is responsible for overseeing and supporting our commitment to environmental, health and safety, social responsibility, sustainability, and other public policy matters relevant to the Company.
Added
These limitations may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Drilling locations that we decide to drill may not yield crude oil or natural gas in commercially viable quantities. We describe some of our drilling locations and our plans to explore those drilling locations in this Annual Report on Form 10-K.
Removed
Significant Developments in 2022 We successfully navigated a challenging 2022, delivering on our key financial objectives while maintaining a strong capital structure. We successfully executed our development plan and countered industry-wide inflationary pressures while exercising capital discipline to ensure we were investing in our best projects and able to return significant free cash flow to shareholders.
Added
Our drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional evaluation.
Removed
We posted strong financial results in 2022, including net income of approximately $1.2 billion and cash flow from operating activities of approximately $2.5 billion, driven primarily by commodity prices and well performance from our high-return development projects.
Added
There is no way to predict in advance of drilling and testing whether any particular location will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable.
Removed
We invested approximately 39% of our 2022 cash flow from operating activities into drilling and completion activities, allowing us to continue to return significant cash to shareholders through our base and variable dividend. In early 2022, the Board initiated a quarterly variable cash dividend in addition to our base dividend.
Added
Prior to drilling, the use of 2-D and 3-D seismic technologies, various other technologies, and the study of producing fields in the same area will still not enable us to know conclusively whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in sufficient quantities to be economically viable.
Removed
We believe Civitas provides investors with one of the highest dividend yields in the exploration and production sector. The Company achieved its annual safety target, advanced critical environmental, health, and safety objectives, integrated data management systems to improve productivity and aligned work processes, and continued to cultivate a results-driven employee culture focused on continuous improvement.
Added
In addition, the use of 2-D and 3-D seismic data and other technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures which may result in a reduction in our returns or increase our losses.
Removed
Additionally, we safely tested enhanced completion designs on large, efficient multi-well pads throughout the Company’s acreage position. Fluid volumes and types, fluid rates, proppant volumes and types, stage spacing, perforation architecture, lateral spacing, and flowback techniques were the primary variables that were tested throughout the 2022 program.
Added
Even if sufficient amounts of crude oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well.
Removed
Along with extensive internal evaluation, the Company will also continue to monitor industry trends, public data, and information from non-operated wells to further optimize completion techniques. During 2022, the Company incurred capital costs of approximately $988.5 million that, along with the incremental production acquired through acquisitions, drove an increase in sales volumes to 170.0 MBoe per day.
Added
If we drill any dry holes in our current and future drilling locations, our profitability and the value of our properties will likely be reduced. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations, or producing fields will be applicable to our drilling locations.
Removed
The capital invested during 2022 allowed the Company to drill 176, complete 142, and turn to sales 146 gross operated wells.
Added
Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing, and operating any well is often uncertain, and new wells may not be productive.
Removed
The following table summarizes our estimated proved reserves as of December 31, 2022: Crude Oil Natural Gas Natural Gas Liquids Total Proved Estimated Proved Reserves (MBbls) (MMcf) (MBbls) (MBoe) Developed 117,768 750,793 102,004 344,904 Undeveloped 34,834 116,707 16,830 71,115 Total Proved 152,602 867,500 118,834 416,019 Total proved reserves as of December 31, 2022 increased by approximately 5% from December 31, 2021. 12 Table of Contents The following table summarizes our PV-10 reserve value, sales volumes, and proved undeveloped drilling locations as of December 31, 2022: Average Net Daily Gross Proved Estimated Proved Reserves at Sales Volumes Undeveloped December 31, 2022 (1) for the Year Ended Drilling Locations Total Proved % Proved PV-10 December 31, 2022 as of (MBoe) Developed ($ in MM) (2) (Boe/d) December 31, 2022 416,019 83 % $ 9,834.3 170,035 201 _____________________ (1) Proved reserves and PV-10 (2) were calculated using the preceding twelve-month unweighted arithmetic average of the first-day-of-the-month price (“SEC prices”), which were $93.67 per Bbl WTI and $6.36 per MMBtu HH.
Added
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
Removed
Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of $3.39 per Bbl for crude oil and a decrease of $1.32 per MMBtu for natural gas assuming an average Btu factor of 1.1 MMBtu/Mcf. (2) PV-10 is a non-GAAP financial measure.
Added
The terms of our oil and gas leases often stipulate that the lease will terminate if not held by production, rentals, or otherwise some form of an extension payment to extend the term of the lease. As of December 31, 2023, approximately 25,100 net acres of our properties were not held by production.
Removed
Please refer to the Reconciliation of Proved Reserves PV-10 to Standardized Measure presented in Part II, Item 7, Non-GAAP Financial Measures of this report. Our Operations Our operations are located in the Rocky Mountain region, primarily in the DJ Basin, and target the Niobrara and Codell formations.
Added
For these properties, if production in paying quantities is not established on units containing leases during the next year, then approximately 4,600 net acres will expire in 2024, approximately 9,600 net acres will expire in 2025, and approximately 10,900 net acres will expire in 2026 and thereafter.
Removed
As of December 31, 2022, our total acreage position consisted of approximately 826,500 gross (525,900 net) acres, and our estimated proved reserves were 416,019 MBoe and contributed 170.0 MBoe per day of sales volumes during 2022. We believe our position allows us to control the pace, costs, and completion techniques used in the development of our reserves.
Added
While some expiring leases may contain predetermined extension payments, other expiring leases will require us to negotiate new leases at the time of lease expiration. Further, existing leases which are currently held by production may unexpectedly encounter operational, political, regulatory, or litigation challenges which could result in their termination.
Removed
As of December 31, 2022, we had working interests in a total of 3,702 gross producing wells, of which 3,116 were horizontal. Our working and net revenue interest for all wells in which we had a working interest averaged approximately 69% and 56%, respectively. Our sales volumes for the fourth quarter of 2022 were 169.4 MBoe per day.
Added
It is possible that market conditions at the time of negotiation could require us to agree to new leases on less favorable terms to us than the terms of the expired leases or cause us to lose the leases entirely.
Removed
We drilled 176 gross (152.0 net) wells in 2022. As of December 31, 2022, we have identified approximately 201 gross (141.7 net) proved undeveloped drilling locations on our acreage.
Added
If our leases expire, we will lose our right to develop the related properties. 48 Table of Contents Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our business, financial condition, and results of operations.
Removed
Reserves Estimated Proved Reserves The summary data with respect to our estimated proved reserves presented below has been prepared in accordance with rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to companies involved in oil and natural gas producing activities. Our reserve estimates do not include probable or possible reserves.
Added
In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our current proved reserves will decline as reserves are produced and, therefore, our level of production and cash flows will be affected adversely unless we conduct successful exploration and development activities or acquire properties containing proved reserves.

… 444 more changes not shown on this page.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

77 edited+227 added−232 removed39 unchanged
Biggest changeAdditionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks, including those related to our hydraulic fracturing operations. • We are subject to health, safety, and environmental laws and regulations that may expose us to significant costs and liabilities. • Evolving legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays. • Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. • Transition risks related to climate change, including negative shift in investor sentiment with respect to the oil and gas industry, could have material and adverse effects on us. • We are exposed to credit risks of our hedging counterparties, third parties participating in our wells, and our customers. • We may be involved in legal cases that may result in substantial liabilities. • We are subject to federal, state, and local taxes and may become subject to new taxes, and certain federal income tax deductions and state income tax deductions and exemptions currently available with respect to oil and gas exploration and development may be eliminated or reduced as a result of future legislation. • Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. • The HighPoint, Extraction, and the Crestone Peak Mergers triggered a limitation on the utilization of our historic U.S. net operating loss carryforwards (“NOLs”), HighPoint’s NOLs, Extraction’s NOLs, and Crestone Peak’s NOLs. • The COVID-19 pandemic has had, and may continue to have, a material adverse effect on our financial condition and results of operations. • We have experienced recent volatility in the market price and trading volume of our common stock and may continue to do so in the future. • Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, even if such acquisition or merger may be in our stockholders’ best interests. • Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. 35 Table of Contents Risks Related to Our Business Declines in oil, natural gas, and NGL prices will adversely affect our business, financial condition or results of operations, and our ability to meet our capital expenditure obligations or targets and financial commitments.
Biggest changeAdditionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks, including those related to our hydraulic fracturing operations. 36 Table of Contents • We are subject to health, safety, and environmental laws and regulations that may expose us to significant costs and liabilities. • Evolving legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays. • Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. • Transition risks related to climate change, including negative shift in investor sentiment with respect to the oil and gas industry, could have material and adverse effects on us. • We are exposed to credit risks of our hedging counterparties, third parties participating in our wells, and our customers. • We may be involved in legal cases that may result in substantial liabilities. • We are subject to federal, state, and local taxes and may become subject to new taxes, and certain federal income tax deductions and state income tax deductions and exemptions currently available with respect to oil and gas exploration and development may be eliminated or reduced as a result of future legislation. • Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. • Certain past transactions triggered a limitation on the utilization of our historic U.S. net operating loss carryforwards (“NOLs”) and the NOLs acquired in such transactions. • Continuing or worsening inflationary pressures and associated changes in monetary policy may result in increases to the cost of our goods, services, and personnel, which in turn could cause our capital expenditures and operating costs to rise. • We have experienced recent volatility in the market price and trading volume of our common stock and may continue to do so in the future. • Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, even if such acquisition or merger may be in our stockholders’ best interests. • CPPIB Crestone Peak Resources Canada Inc., a Canadian corporation (the “Crestone Peak Stockholder”) is a significant holder of our common stock and may have some ability to influence our management and affairs. • Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. 37 Table of Contents Risks Related to Our Business Declines in crude oil, natural gas, and NGL prices will adversely affect our business, financial condition or results of operations, and our ability to meet our capital expenditure obligations or targets and financial commitments.
During times of suppressed oil prices, we have historically experienced significant decreases in crude oil revenues and recorded unproved property asset impairment charges.
During times of suppressed crude oil prices, we have historically experienced significant decreases in crude oil revenues and recorded unproved property asset impairment charges.
Further, many factors, including, but not limited to, the following, may result in substantial losses, including personal injury or loss of life, penalties, damage or destruction of property and equipment, and curtailments, delays, or cancellations of our scheduled drilling, completion, and infrastructure projects: • shortages of or delays in obtaining equipment and qualified personnel; • facility or equipment malfunctions; • unexpected operational events; • unanticipated environmental liabilities; • pressure or irregularities in geological formations; • adverse weather conditions, such as extreme cold temperatures, blizzards, ice storms, tornadoes, floods, and fires; • reductions in oil and natural gas prices; • delays imposed by or resulting from compliance with regulatory requirements, such as permitting delays; • proximity to and capacity of transportation facilities; • title issues or inaccuracies; • safety and/or environmental events; and • limitations in the market for oil and natural gas.
Further, many factors, including, but not limited to, the following, may result in substantial losses, including personal injury or loss of life, penalties, damage or destruction of property and equipment, and curtailments, delays, or cancellations of our scheduled drilling, completion, and infrastructure projects: • shortages of or delays in obtaining equipment and qualified personnel; • facility or equipment malfunctions; • unexpected operational events; • unanticipated environmental liabilities; • pressure or irregularities in geological formations; • adverse weather conditions, such as extreme cold temperatures, blizzards, ice storms, tornadoes, floods, and fires; • reductions in crude oil and natural gas prices; • delays imposed by or resulting from compliance with regulatory requirements, such as permitting delays; • proximity to and capacity of transportation facilities; • title issues or inaccuracies; • safety and/or environmental events; and • limitations in the market for crude oil and natural gas.
Actual future net revenues from our oil and natural gas properties will be affected by factors such as: • actual prices we receive for oil and natural gas and hedging instruments; • actual cost of development and production activities; • the amount and timing of actual production; • the amount and timing of future development costs; • wellbore productivity realizations above or below type curve forecast models; • the supply and demand of oil and natural gas; and • changes in governmental regulations or taxation.
Actual future net revenues from our crude oil and natural gas properties will be affected by factors such as: • actual prices we receive for crude oil and natural gas and hedging instruments; • actual cost of development and production activities; • the amount and timing of actual production; • the amount and timing of future development costs; • wellbore productivity realizations above or below type curve forecast models; • the supply and demand of crude oil and natural gas; and • changes in governmental regulations or taxation.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including: • our proved reserves; • the amount of oil and natural gas we are able to produce from new and existing wells; • the prices at which our oil and natural gas are sold; • the costs of developing and producing our oil and natural gas; • our ability to acquire, locate, and produce new reserves; • the ability and willingness of our banks to lend; and • our ability to access the equity and debt capital markets.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including: • our proved reserves; • the amount of crude oil and natural gas we are able to produce from new and existing wells; • the prices at which our crude oil and natural gas are sold; • the costs of developing and producing our crude oil and natural gas; • our ability to acquire, locate, and produce new reserves; • the ability and willingness of our banks to lend; and • our ability to access the equity and debt capital markets.
Among the most significant changes under the legislation was the aforementioned provision giving local governments greater control over facility siting and surface impacts associated with oil and gas development. Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements.
Among the most significant changes under the legislation was the provision giving local governments greater control over facility siting and surface impacts associated with oil and gas development. Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements.
Summary of the Risk Factors We Face : • Declines in oil, natural gas, and NGL prices will adversely affect our business, financial condition or results of operations, and our ability to meet our capital expenditure obligations or targets and financial commitments. • Our production is not fully hedged, and we may hedge a lower percentage of our production than we have in the past.
Summary of the Risk Factors We Face : • Declines in crude oil, natural gas, and NGL prices will adversely affect our business, financial condition, or results of operations, and our ability to meet our capital expenditure obligations or targets and financial commitments. • Our production is not fully hedged, and we may hedge a lower percentage of our production than we have in the past.
If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, limited takeaway capacity, or depressed natural gas and oil prices, the return on our investment in these areas may not be as attractive as anticipated.
If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, limited takeaway capacity, or depressed crude oil and natural gas prices, the return on our investment in these areas may not be as attractive as anticipated.
Based on 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, from time to time, we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings.
Based on 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, from time to time, we may be required to write-down the carrying value of our crude oil and natural gas properties. A write-down constitutes a non-cash charge to earnings.
We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production, and acquisition of oil and natural gas reserves. At this time, we intend to finance future capital expenditures primarily through cash flows provided by operating activities and borrowings under the Credit Facility.
We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production, and acquisition of crude oil and natural gas reserves. At this time, we intend to finance future capital expenditures primarily through cash flows provided by operating activities and borrowings under the Credit Facility.
If the borrowing base under the Credit Facility decreases or if our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves, or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations.
If the borrowing base under the Credit Facility decreases or if our revenues decrease as a result of lower crude oil or natural gas prices, operating difficulties, declines in reserves, or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations.
In addition, the 10% discount factor (the factor required by the SEC) used when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
In addition, the 10% discount factor (the factor required by the SEC) used when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the crude oil and natural gas industry in general.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have, and may in the future enter into additional, derivative arrangements for a portion of our oil, natural gas, and NGL production, including swaps, collars, and other instruments.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of crude oil and natural gas, we have, and may in the future enter into additional, derivative arrangements for a portion of our crude oil, natural gas, and NGL production, including swaps, collars, and other instruments.
Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development, and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production.
Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development, and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable crude oil or natural gas production.
Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. In recent years, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future.
Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. In recent years, the markets for crude oil and natural gas have been volatile. These markets will likely continue to be volatile in the future.
The process of estimating oil and natural gas reserves and the production possible from our oil and gas wells is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices.
The process of estimating crude oil and natural gas reserves and the production possible from our oil and gas wells is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices.
Imbalances between the supply and demand for oil and natural gas could result in transportation and storage constraints, reductions of our planned production, and related shut-in of our wells, which could adversely affect our business, financial condition, and results of operations.
Imbalances between the supply and demand for crude oil and natural gas could result in transportation and storage constraints, reductions of our planned production, and related shut-in of our wells, which could adversely affect our business, financial condition, and results of operations.
Given the historical price volatility in the oil and natural gas markets, prices may decline or other events may arise that would require us to record further impairments of the book values associated with oil and natural gas properties.
Given the historical price volatility in the crude oil and natural gas markets, prices may decline or other events may arise that would require us to record further impairments of the book values associated with crude oil and natural gas properties.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value.
The timing of both our production and our incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value.
In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices, and other factors, many of which are beyond our control.
In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices, and other factors, many of which are beyond our control.
Risks associated with our horizontal drilling program include, but are not limited to, the following, any of which could materially and adversely impact the success of our horizontal drilling program and, thus, our cash flows and results of operations: • successfully drilling and maintaining the wellbore to planned total depth; • landing our wellbore in the desired hydrocarbon reservoir; • effectively controlling the level of pressure flowing from particular wells; • staying in the desired hydrocarbon reservoir while drilling horizontally through the formation; • running our casing through the entire length of the wellbore; • running tools and other equipment consistently through the horizontal wellbore; • successful design and execution of the fracture stimulation process; • preventing downhole communications with other wells, or, in the alternative, disruption from non-simultaneous operations; • successfully cleaning out the wellbore after completion of the final fracture stimulation stage; and • designing and maintaining efficient forms of artificial lift throughout the life of the well.
Risks associated with our horizontal drilling program include, but are not limited to, the following, any of which could materially and adversely impact the success of our horizontal drilling program and, thus, our cash flows and results of operations: • successfully drilling and maintaining the wellbore to planned total depth; • landing our wellbore in the desired hydrocarbon reservoir; 43 Table of Contents • effectively controlling the level of pressure flowing from particular wells; • staying in the desired hydrocarbon reservoir while drilling horizontally through the formation; • running our casing through the entire length of the wellbore; • running tools and other equipment consistently through the horizontal wellbore; • successful design and execution of the fracture stimulation process; • preventing downhole communications with other wells, or, in the alternative, disruption from non-simultaneous operations; • successfully cleaning out the wellbore after completion of the final fracture stimulation stage; and • designing and maintaining efficient forms of artificial lift throughout the life of the well.
In addition, these types of derivative arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.
In addition, these types of derivative arrangements may limit the benefit we would receive from increases in the prices for crude oil and natural gas and may expose us to cash margin requirements.
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred.
We review our proved crude oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred.
At this time, it impossible to estimate the potential impact on our business of future local actions on our ability to operate and/or drill oil and gas wells in these areas.
At this time, it is impossible to estimate the potential impact on our business of future local actions on our ability to operate and/or drill oil and gas wells in these areas.
Declines in commodity prices may have the following effects on our business: • reduction of our revenues, profit margins, operating income, and cash flows; • reduction in the amount of crude oil, natural gas, and NGLs that we can produce economically, and reduction in our liquidity and inability to pay our liabilities as they come due; 36 Table of Contents • certain properties in our portfolio becoming economically unviable; • delay or postponement of some of our capital projects; • significant reductions in future capital programs, resulting in a reduced ability to develop our reserves; • limitations on our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations; • reduction to the borrowing base under our Credit Facility or limitations in our access to sources of capital, such as equity or debt; • declines in our stock price; • reduction in industry demand for crude oil; • reduction in storage availability for crude oil; • reduction in pipeline and processing industry demand and capacity for natural gas; • reduction in the ability of our vendors, suppliers, and customers to continue operations due to the prevailing adverse market conditions; and • asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment.
Declines in commodity prices may have the following effects on our business: • reduction of our revenues, profit margins, operating income, and cash flows; 38 Table of Contents • reduction in the amount of crude oil, natural gas, and NGL that we can produce economically, and reduction in our liquidity and inability to pay our liabilities as they come due; • certain properties in our portfolio becoming economically unviable; • delay or postponement of some of our capital projects; • significant reductions in future capital programs, resulting in a reduced ability to develop our reserves; • limitations on our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations; • reduction to the borrowing base under our Credit Facility or limitations in our access to sources of capital, such as equity or debt; • declines in our stock price; • reduction in industry demand for crude oil; • reduction in storage availability for crude oil; • reduction in pipeline and processing industry demand and capacity for natural gas; • reduction in the ability of our vendors, suppliers, and customers to continue operations due to the prevailing adverse market conditions; and • asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment.
We are therefore exposed to fluctuations in the price of oil, natural gas, and NGLs and will be affected by continuing and prolonged declines in such prices. • Our derivative activities could result in financial losses or could reduce our income. • The agreements covering our debt have restrictive covenants that could limit our ability to finance our operations, fund capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests. • Borrowings under the Credit Facility are limited by our borrowing base, which is subject to periodic redetermination. • Our development and production projects require substantial capital expenditures.
We are therefore exposed to fluctuations in the price of crude oil, natural gas, and NGL and will be affected by continuing and prolonged declines in such prices. • Our derivative activities could result in financial losses or could reduce our income. • The agreements covering our debt have restrictive covenants that could limit our ability to finance our operations, fund capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests. • Borrowings under the Credit Facility are limited by our borrowing base, which is subject to periodic redetermination. • Our development and production projects require substantial capital expenditures.
In accordance with SEC requirements for the years ended December 31, 2022, 2021, and 2020, we based the estimated discounted future net revenues from our proved reserves on the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months (after adjustment for location and quality differentials), without giving effect to derivative transactions.
In accordance with SEC requirements for the years ended December 31, 2023, 2022, and 2021, we based the estimated discounted future net revenues from our proved reserves on the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months (after adjustment for location and quality differentials), without giving effect to derivative transactions.
It is common within the industry to hedge a portion of oil and natural gas production to reduce a company’s exposure to adverse fluctuations in these prices.
It is common within the industry to hedge a portion of crude oil and natural gas production to reduce a company’s exposure to adverse fluctuations in these prices.
For a discussion of the uncertainty involved in these processes, see Our estimated proved reserves and our ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves below.
For a discussion of the uncertainty involved in these processes, see “Our estimated proved reserves and our ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves ” below.
The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities).
The proposed rule sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities).
If cash generated by operations or cash available under the Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our undeveloped leases and a decline in our oil and natural gas reserves, and an adverse effect on our business, financial condition, and results of operations. 39 Table of Contents Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition, or results of operations.
If cash generated by operations or cash available under the Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our undeveloped leases and a decline in our crude oil and natural gas reserves, and an adverse effect on our business, financial condition, and results of operations. 41 Table of Contents Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition, or results of operations.
A major rulemaking addressing a wide range of topics including facility siting, cumulative impacts, development approvals, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, and wildlife protection took effect in January 2021.
In January 2021, the results of a major rulemaking took effect addressing a wide range of topics including facility siting, cumulative impacts, development approvals, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, and wildlife protection.
In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. On November 15, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.
In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.
We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves or anticipated production volumes. • Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition, or results of operations. • Our estimated proved reserves and our ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate.
We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our crude oil and natural gas reserves or anticipated sales volumes. • Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition, or results of operations. • Our estimated proved reserves and our ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate.
Further efforts could result in the following: • delay or denial of drilling permits; • increased local government rulemaking and/or changes to current local government rules that result in increased costs and delay or prevention of oil and gas development; • increased demands for additional best management practices (“BMPs”) beyond what is currently required in certain operating agreements or by the COGCC; • revocation or modification of drilling permits, operating agreements, or other necessary authorizations; • disputes focused on the validity of active leases and record title ownership to prevent development; • disputes focused on proximity of operations to urban and suburban communities; • restrictions on installation or operation of production, gathering, or processing facilities; • mandatory and excessive setbacks between drilling locations and structures and building units and/or bodies of water, disproportionately impacted communities, or other protected areas; • restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposal of related waste materials, such as hydraulic fracturing fluids and produced water; • increased severance and/or other taxes; • cyber-attacks; • legal challenges or lawsuits; • negative publicity about us or the oil and gas industry in general; 44 Table of Contents • increased costs of operations and development; • reduction in demand for our products; and • other adverse effects on our ability to develop our properties and expand production.
Further efforts could result in the following: • delay or denial of drilling permits; • increased local government rulemaking and/or changes to current local government rules that result in increased costs and delay or prevention of oil and gas development; • increased demands for additional best management practices (“BMPs”) beyond what is currently required in certain operating agreements or by state regulators; • revocation or modification of drilling permits, operating agreements, or other necessary authorizations; • disputes focused on the validity of active leases and record title ownership to prevent development; • disputes focused on proximity of operations to urban and suburban communities; • restrictions on installation or operation of production, gathering, or processing facilities; • mandatory and excessive setbacks between drilling locations and structures and building units and/or bodies of water, disproportionately impacted communities, or other protected areas; • restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposal of related waste materials, such as hydraulic fracturing fluids and produced water; • increased severance and/or other taxes; • cyber-attacks; • legal challenges or lawsuits; • negative publicity about us or the oil and gas industry in general; • increased costs of operations and development; • reduction in demand for our products; and • other adverse effects on our ability to develop our properties and expand production.
Our development and production projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves or anticipated production volumes. Our development and production activities are capital intensive.
Our development and production projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our crude oil and natural gas reserves or anticipated sales volumes. Our development and production activities are capital intensive.
Although the reserves information contained herein is prepared by independent reserves engineers, estimates of oil and natural gas reserves are inherently imprecise, particularly as they relate to state-of-the-art technologies being employed, such as the combination of hydraulic fracturing and horizontal drilling. 40 Table of Contents Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will vary from our estimates.
Although the reserves information contained herein is prepared by independent reserves engineers, estimates of crude oil and natural gas reserves are inherently imprecise, particularly as they relate to state-of-the-art technologies being employed, such as the combination of hydraulic fracturing and horizontal drilling. 42 Table of Contents Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable crude oil and natural gas reserves will vary from our estimates.
These factors include, but are not limited to, the following: • worldwide, regional, and local economic conditions impacting the global supply and demand for oil and natural gas; • the actions from members of the Organization of Petroleum Exporting Countries and other oil producing nations; • the price and quantity of imports of foreign oil and natural gas; • political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and involving Russia and Ukraine and conditions in South America; • the level of domestic and global oil and natural gas exploration and production; • the level of domestic and global oil and natural gas inventories; • localized supply and demand fundamentals and transportation availability; • weather conditions and natural disasters, including the physical effects of climate change; • local, domestic, and foreign governmental regulations, including regulations addressing climate change; • speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts; • the price and availability of competitors’ supplies of oil and natural gas; • technological advances affecting energy consumption; • variability in subsurface reservoir characteristics, particularly in areas with immature development history, even within areas in close proximity within the same basin or field; • the availability of pipeline capacity and infrastructure; and • the price and availability of alternative fuels.
These factors include, but are not limited to, the following: • worldwide, regional, and local economic conditions impacting the global supply and demand for crude oil and natural gas; • the actions from members of the Organization of Petroleum Exporting Countries and other crude oil producing nations; • the price and quantity of imports of foreign crude oil and natural gas; • political conditions in or affecting other crude oil and natural gas producing countries, including the current conflicts in the Middle East (including the current events related to the Israel-Palestine conflict) and involving Russia and Ukraine and conditions in South America; • the level of domestic and global crude oil and natural gas exploration and production; • the level of domestic and global crude oil and natural gas inventories; • localized supply and demand fundamentals and transportation availability; • weather conditions and natural disasters, including the physical effects of climate change; • local, domestic, and foreign governmental regulations, including regulations addressing climate change; • speculation as to the future price of crude oil and the speculative trading of crude oil and natural gas futures contracts; • the price and availability of competitors’ supplies of crude oil and natural gas; • technological advances affecting energy consumption; • variability in subsurface reservoir characteristics, particularly in areas with immature development history, even within areas in close proximity within the same basin or field; • the availability of pipeline capacity and infrastructure; and • the price and availability of alternative fuels.
Therefore, our undeveloped reserves may not be ultimately developed or produced. • Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities. • Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. • Unless we replace our oil and natural gas reserves, our reserves and production will decline, which could adversely affect our business, financial condition, and results of operations. 34 Table of Contents • We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.
Therefore, our undeveloped reserves may not be ultimately developed or produced. • Drilling locations that we decide to drill may not yield crude oil or natural gas in commercially viable quantities. • Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. • Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our business, financial condition, and results of operations. • We may incur substantial losses and be subject to substantial liability claims as a result of our crude oil and natural gas operations.
The agreements governing our debt, including the Credit Facility and the indenture governing our senior notes, contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests.
The agreements governing our debt, including the Credit Facility and the indentures governing our senior notes, contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests.
We are therefore exposed to fluctuations in the price of oil, natural gas, and NGLs and will be affected by continuing and prolonged declines in such prices. Oil, natural gas, and NGL prices are volatile.
We are therefore exposed to fluctuations in the price of crude oil, natural gas, and NGL and will be affected by continuing and prolonged declines in such prices. Crude oil, natural gas, and NGL prices are volatile.
These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in commodity prices, our business, or the economy in general, or otherwise conduct necessary corporate activities. Borrowings under the Credit Facility are limited by our borrowing base, which is subject to periodic redetermination.
These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in commodity prices, our business, or the economy in general, or otherwise conduct necessary corporate activities. 40 Table of Contents Borrowings under the Credit Facility are limited by our borrowing base, which is subject to periodic redetermination.
Any prolonged period of low market prices for oil, natural gas, and NGLs could result in future capital expenditures being reduced and will necessarily adversely affect our business, financial condition, and liquidity and our ability to meet obligations, targets, or financial commitments.
Any prolonged period of low market prices for crude oil, natural gas, and NGL could result in future capital expenditures being reduced and will necessarily adversely affect our business, financial condition, and liquidity and our ability to meet obligations, targets, or financial commitments.
We have not in the past designated any of our derivative instruments as hedges for accounting purposes and have recorded all derivative instruments on our balance sheet at fair value. 37 Table of Contents Changes in the fair value of our derivative instruments are recognized in earnings.
We have not in the past designated any of our derivative instruments as hedges for accounting purposes and have recorded all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings.
The adoption of future federal, state, or local laws or implementing regulations imposing new environmental, operational, and/or financial assurance obligations on, or otherwise limiting, our operations could make it more difficult, more expensive, and/or impossible to complete oil and natural gas wells, increase our costs of compliance operations, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products.
The adoption of future federal, state, or local laws or implementing regulations imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete crude oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products.
The price we receive for our oil, natural gas, and natural gas liquids (“NGLs”) heavily influences our revenue, profitability, cash flows, liquidity, access to capital, present value and quality of our reserves, and the nature and scale of our operations.
The price we receive for our crude oil, natural gas, and NGL heavily influences our revenue, profitability, cash flows, liquidity, access to capital, present value and quality of our reserves, and the nature and scale of our operations.
Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K.
Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See “ Item 1.
We are subject to extensive federal, state, and local laws and regulations, including those concerning public and occupational health and safety and environmental protection. Governmental authorities frequently review, revise, and supplement these requirements, and both oil and gas development generally, and hydraulic fracturing specifically, are receiving increasing legislative and regulatory attention.
We are subject to extensive federal, state, and local laws and regulations concerning public health and safety, and environmental protection. Government authorities frequently review, revise and supplement these requirements, and both oil and gas development generally, and hydraulic fracturing specifically, are receiving increasing regulatory attention.
Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because approximately 65% of our estimated proved reserves as of December 31, 2022 were oil and NGLs, our financial results are more sensitive to movements in oil and NGL prices.
Further, crude oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because approximately 68% of our estimated proved reserves as of December 31, 2023 were crude oil and NGL, our financial results are more sensitive to movements in crude oil and NGL prices.
See Estimated Proved Reserves under Part I, Item 1 of this Annual Report on Form 10-K for information about our estimated oil and natural gas reserves and the PV-10 (a non-GAAP financial measure) as of December 31, 2022, 2021, and 2020. In order to prepare our estimates, we must project production rates and the timing of development expenditures.
Business - Estimated Proved Reserves ” of this Annual Report on Form 10-K for information about our estimated oil and natural gas reserves and the PV-10 (a non-GAAP financial measure) as of December 31, 2023, 2022, and 2021. In order to prepare our estimates, we must project production rates and the timing of development expenditures.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves.
The legislation mandated the COGCC conduct rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned, or shut-in, financial assurance, wellbore integrity, and application fees.
The legislation mandated ECMC rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned or shut-in, financial assurance, wellbore integrity, and application fees. In November 2022, the ECMC completed rulemaking on flowlines and wells that are inactive, temporarily abandoned, or shut-in and completed rulemaking on wellbore integrity in June 2020.
As of February 20, 2023, the daily NYMEX WTI oil spot price and NYMEX HH natural gas spot price was $76.34 per Bbl and $2.28 per MMBtu, respectively. The prices we receive for our production and the levels of our production, depend on numerous factors beyond our control.
As of February 23, 2024, the daily NYMEX WTI crude oil spot price and NYMEX HH natural gas spot price was $76.49 per Bbl and $1.60 per MMBtu, respectively. The prices we receive for our production and the levels of our production, depend on numerous factors beyond our control.
Horizontal development operations can be more operationally challenging and costly relative to our historic vertical drilling operations. Horizontal drilling is generally more complex and more expensive on a per well basis than vertical drilling. As a result, there is greater risk associated with a horizontal well program.
We intend to pursue the further development of our properties through horizontal drilling and completion, which can be more operationally challenging and costly relative to vertical drilling operations. Horizontal drilling is generally more complex and more expensive on a per well basis than vertical drilling. As a result, there is greater risk associated with a horizontal well program.
Upon a redetermination, we could be required to repay a portion of our bank debt to the extent our outstanding borrowings at such time exceed the redetermined borrowing base.
The next scheduled borrowing base redetermination date is set to occur in May 2024. Upon a redetermination, we could be required to repay a portion of our bank debt to the extent our outstanding borrowings at such time exceed the redetermined borrowing base.
Permitting delays that result from the new COGCC rules and regulations could substantially curtail the Company’s near-term pace of new oil and gas development.
Permitting delays that result from the new ECMC rules and regulations or other state rules and regulations could substantially curtail our near-term pace of new crude oil and natural gas development.
We have observed a decline in the pace at which permit applications are being granted, and if this trend continues, it could have a material adverse effect on our business, financial condition, production targets, and results of operations.
We have observed a decline in the pace at which permit applications are being granted in Colorado, and if this trend continues in any of the states in which we operate, it could have a material adverse effect on our business, financial condition, production targets, and results of operations. 46 Table of Contents Rules adopted by regulators in the states in which we operate may significantly increase our operating costs and have a material adverse effect on our business, financial condition, and results of operations.
We must also analyze available geological, geophysical, production, and engineering data. The extent, quality, and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds, and given the current volatility in pricing, such assumptions are difficult to make.
The process also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds, and given the current volatility in pricing, such assumptions are difficult to make.
Item 1A. Risk Factors. Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer. The risks described below are not the only ones facing us.
If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.
Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets.
No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets.
During the year ended December 31, 2022, the daily NYMEX WTI oil spot price ranged from a high of $123.64 per Bbl to a low of $71.05 per Bbl, and the NYMEX HH natural gas spot price ranged from a high of $9.85 per MMBtu to a low of $3.46 per MMBtu.
During the year ended December 31, 2023, the daily NYMEX WTI crude oil spot price ranged from a high of $93.67 per Bbl to a low of $66.61 per Bbl, and the NYMEX HH natural gas spot price ranged from a high of $3.78 per MMBtu to a low of $1.74 per MMBtu.
See the Derivative Activity section in Part I, Item I of this Annual Report on Form 10-K for a summary of our hedging activity. Our derivative activities could result in financial losses or could reduce our income.
Financial Statements and Supplementary Data - Note 9 - Derivatives ” of this Annual Report on Form 10-K for a summary of our hedging activity. 39 Table of Contents Our derivative activities could result in financial losses or could reduce our income.
Horizontal development operations can be more operationally challenging and costly relative to our historic vertical drilling operations. • We may be unable to make attractive acquisitions, and any inability to do so may disrupt our business. • We may not realize anticipated benefits from mergers and acquisitions. • Concentration of our operations in one core area may increase our risk of production loss. • We face increasing risk associated with the long-term trend toward increased activism against oil and gas exploration and development activities in Colorado and elsewhere. • The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. • We intend to pursue the further development of our properties through horizontal drilling and completion, which can be more operationally challenging and costly relative to vertical drilling operations. • Several of our recent acquisitions represent an expansion outside of the DJ Basin, and we may encounter new obstacles operating in different geographic regions. • We may be unable to make attractive acquisitions, and any inability to do so may disrupt our business. • We may not realize anticipated benefits from mergers and acquisitions. • We face increasing risk associated with the long-term trend toward increased activism against oil and gas exploration and development activities in the states in which we operate, particularly in Colorado. • The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Any future excess supply of oil and natural gas (such as that which resulted from the unprecedented decline in demand for oil and natural gas stemming from various governmental actions taken in 2020 to mitigate the impact of COVID-19) could impact our ability to sell our production because of transportation or storage constraints, causing us to shut-in or curtail production or flare our natural gas.
Any future excess supply of crude oil and natural gas could impact our ability to sell our production because of transportation or storage constraints, causing us to shut-in or curtail production or flare our natural gas.
We cannot assure that any such outcome would not be material, and any such outcome could have a material adverse impact on our cash flows and results of operations.
We cannot assure that any such outcome would not be material, and any such outcome could have a material and adverse impact on our cash flows and results of operations. Our use of hydraulic fracturing. We use hydraulic fracturing as a means to maximize production of oil and gas from formations having low permeability such that natural flow is restricted.
Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters”. The EPA is expected to issue a final rule by August 2023.
Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA announced a final rule on December 2, 2023, which, among other things, requires the phase out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations.
In the future we may make acquisitions of producing properties or businesses that complement or expand our current business. The successful acquisition of producing properties requires an assessment of several factors, including: • recoverable reserves; • future oil, natural gas, and NGL prices and their applicable differentials; • operating costs; • location inventory; and • potential environmental and other liabilities.
The successful acquisition of producing properties requires an assessment of several factors, including: • recoverable reserves; • future crude oil, natural gas, and NGL prices and their applicable differentials; • operating costs; • location inventory; and • potential environmental and other liabilities. 44 Table of Contents The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities.
Currently, we have hedged approximately 2,800 Bbls per day in 2023, and our hedging for 2024 oil production is even more limited. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices, which would have a material negative impact on our results of operations.
Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices, which would have a material negative impact on our results of operations. See “ Part II - Item 8.
Further, as a result of any of these developments, we could incur material impairments of our oil and gas properties and the value of our undeveloped acreage could decline in the future. We may be unable to make attractive acquisitions, and any inability to do so may disrupt our business.
Further, as a result of any of these developments, we could incur material impairments of our oil and gas properties and the value of our undeveloped acreage could decline in the future. Several of our recent acquisitions represent an expansion outside of the DJ Basin, and we may encounter new obstacles operating in different geographic regions.
Even when problems are identified, the seller 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 properties on an “as is, where is” basis.
Inspections may not always be performed on every well and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.
Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms or for other reasons stated herein. 42 Table of Contents Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.
We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is, where is” basis. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms or for other reasons stated herein.
In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors. 38 Table of Contents In our fall 2022 semi-annual redetermination, the borrowing base under the Credit Facility was set at $1.85 billion with an elected committed amount of $1.0 billion.
In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors. On August 2, 2023, in connection with the closing of several of our recent acquisitions, the Credit Facility was amended to increase the borrowing base to $3.0 billion, with an aggregate maximum credit commitment of $4.0 billion and aggregate elected commitments of $1.85 billion.
Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.
In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities.
Further, on November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources.
Among other things, these revisions imposed new requirements for leak detection and repair, control requirements for oil well completions, and additional control requirements for gathering, boosting, and compressor stations. In November 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources.
Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production. In some instances, certain state and local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations.
Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of crude oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production. States have historically regulated oil and gas exploration and production activity, including hydraulic fracturing.
Failure to successfully manage the combined company may have an adverse effect on our business, reputation, financial condition, and results of operations. Concentration of our operations in one core area may increase our risk of production loss. Our assets and operations are currently concentrated in one core area: the DJ Basin in Colorado.
Failure to successfully manage the combined company may have an adverse effect on our business, reputation, financial condition, and results of operations. 45 Table of Contents We face increasing risk associated with the long-term trend toward increased activism against oil and gas exploration and development activities in the states in which we operate, particularly in Colorado.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise have a material adverse effect on our own results of operations, competitive position, or financial condition.
Cumulatively, these laws and regulations may impact our operations. 26 Table of Contents The following is a summary of the more significant environmental and health and safety laws and regulations to which we are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations, or financial position.
Removed
Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.
Added
Item 1A. Risk Factors ” of this report for additional discussion. Insurance Matters As is common in the crude oil and natural gas industry, we will not insure fully against all risks associated with our business, either because such insurance is not available or customary, or because premium costs are considered cost-prohibitive.
Removed
Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. • Continuing or worsening inflationary pressures and associated changes in monetary policy may result in increases to the cost of our goods, services, and personnel, which in turn could cause our capital expenditures and operating costs to rise. • We intend to pursue the further development of our properties in the DJ Basin through horizontal drilling and completion.

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Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Removed
Item 3. Legal Proceedings. From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business.
Added
We are a party to various routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas exploration and development industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to crude oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations.
Removed
Like other gas and oil producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health, and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Boulder County.
Added
While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, results of operations or cash flows.
Removed
In prior periods, there was ongoing litigation between Boulder County and Extraction which has been previously disclosed as having the potential to prevent oil and gas operations for the development of minerals contained within Boulder County, Colorado.
Added
For additional information regarding legal proceedings and environmental matters, refer to “ Part II, Item 8. Financial Statements and Supplementary Data - Note 6 - Commitments and Contingencies .” Enforcement.
Removed
Boulder County had initiated suit in District Court for Boulder County that was primarily a contract case, where the relevant contracts were the conservation easement over the Blue Paintbrush location, Extraction’s Surface Use Agreement for the Blue Paintbrush location, and the leases that Boulder owns within the Blue Paintbrush drilling and spacing unit.
Added
Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that we believe could exceed $0.3 million. We have received Notices of Alleged Violations (“NOAV”) from the ECMC alleging violations of various Colorado statutes and ECMC regulations governing oil and gas operations.
Removed
Boulder sought invalidation of these leases in the litigation. This litigation has been resolved as to all substantive issues, and the Company is awaiting final dismissal of the matter by the trial court.
Added
We have further received notices from the Colorado Air Pollution Control Division. We continue to engage in discussions regarding resolution of the alleged violations and we anticipate the assessed penalties to be approximately $0.6 million. 60 Table of Contents Item 4. Mine Safety Disclosures. Not applicable. 61 Table of Contents PART II
Removed
In May 2022, the Company became aware that Boulder County is alleging new legal theories and requesting termination of the leases previously at issue in the Blue Paintbrush litigation. No formal action has been initiated, but the Company intends to vigorously defend against all claims alleged by Boulder County.
Removed
If an action is brought by Boulder County, an adverse outcome in any such litigation could result in the Company failing to meet its development objectives in Blue Paintbrush. Item 4. Mine Safety Disclosures. Not applicable. 59 Table of Contents PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeDuring the nine months ended September 30, 2022, the quarterly base dividend was $0.46 per share of common stock ($1.85 annually) and was increased to $0.50 per share of common stock ($2.00 annually) beginning in the fourth quarter of 2022. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, the Board.
Biggest changeThe decision to pay any future dividends is solely within the discretion of, and subject to approval by, the Board.
Additionally, covenants contained in our Credit Facility and the indentures governing our senior notes restrict the payment of cash dividends on our common stock, as discussed further in Item 8, Note 5 - Long-Term Debt of this report. Issuer Purchases of Equity Securities.
Additionally, covenants contained in our Credit Facility and the indentures governing our senior notes restrict the payment of cash dividends on our common stock, as discussed further in “ Item 8. Financial Statements and Supplementary Data - Note 5 - Long-Term Debt ” of this report. Issuer Purchases of Equity Securities.
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 NYSE under the symbol “CIVI”. Holders. As of February 20, 2023, there were approximately 110 registered holders of our common stock. Dividend Policy.
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 NYSE under the symbol “CIVI”. Holders. As of February 23, 2024, there were approximately 143 registered holders of our common stock. Dividend Policy.
The following graph compares the cumulative total stockholder return for the Company’s common stock, the Standard and Poor’s 500 Stock Index (the “S&P 500 Index”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P O&G E&P Index”) over the five year period from December 31, 2017 through December 31, 2022.
The following graph compares the cumulative total stockholder return for our common stock, the Standard and Poor’s 500 Stock Index (the “S&P 500 Index”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P O&G E&P Index”) over the five year period from December 31, 2018 through December 31, 2023.
The graph assumes that $100 was invested on December 31, 2017 in each of the common stock of the Company, the S&P 500 Index, and the S&P O&G E&P Index and assumes reinvestment of any dividends. The stock price performance on the following graph is not necessarily indicative of future stock price performance. Item 6. [Reserved]. 61 Table of Contents
The graph assumes that $100 was invested on December 31, 2018 in our common stock, the S&P 500 Index, and the S&P O&G E&P Index and assumes reinvestment of any dividends. The stock price performance on the following graph is not necessarily indicative of future stock price performance. Item 6. [Reserved]. 63 Table of Contents
In March 2022, the Board approved the initiation of a quarterly variable cash dividend in addition to the aforementioned base dividend, equal to 50% of free cash flow after the base cash dividend for the preceding twelve-month period and pro forma for all acquisition and divestiture activity, assuming pro forma compliance with certain leverage targets.
As approved by the Board, cash dividends are paid quarterly and consist of a base and variable component. Variable cash dividends are equal to 50% of Free Cash Flow, after the base cash dividend for the preceding twelve-month period and pro forma for all acquisition and divestiture activity, assuming pro forma compliance with certain leverage targets.
The following table contains information about our acquisition of equity securities during the three months ended December 31, 2022.
The following table provides information about our purchases of our common stock during the three months ended December 31, 2023.
We had no sales of unregistered securities during the year ended December 31, 2022. 60 Table of Contents Stock Performance Graph.
Other than as previously reported on our Current Reports on Form 8-K, filed with the SEC on June 20, 2023 and August 2, 2023, we had no sales of unregistered securities during the year ended December 31, 2023. 62 Table of Contents Stock Performance Graph.
Removed
In May 2021, we announced the initiation of a quarterly base cash dividend on our common stock.
Added
Total Number of Shares Purchased (2) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1) Maximum Dollar value that May Yet be Purchased Plans or Programs (in thousands) (1) October 1, 2023 - October 31, 2023 912 $ 79.11 — $ 479,810 November 1, 2023 - November 30, 2023 366 $ 69.03 — 479,810 December 1, 2023 - December 31, 2023 87 $ 69.29 — 479,810 Total 1,365 $ 75.78 — $ 479,810 _________________________ (1) In February 2023, we announced that the Board provided authorization for the stock repurchase program pursuant to which we may, from time to time and through December 31, 2024, acquire shares of our common stock in the open market, in privately negotiated transactions, or through block trades, derivative transactions, or purchases made in accordance with the Rule 10b5-1 of the Exchange Act in an amount not to exceed $1.0 billion, exclusive of any fees, commissions, or other expenses related to such repurchases.
Removed
Total Number of Shares Maximum Number of Total Number Purchased as Part of Shares that May Be of Shares Average Price Publicly Announced Purchased Under Plans Purchased (1) Paid per Share Plans or Programs or Programs October 1, 2022 - October 31, 2022 1,504 $ 67.52 — — November 1, 2022 - November 30, 2022 1,109 $ 71.26 — — December 1, 2022 - December 31, 2022 4,844 $ 67.93 — — Total 7,457 $ 68.62 — — _________________________ (1) Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligations upon the vesting of restricted stock awards.
Added
In June 2023, commensurate with the announcement of the Hibernia Acquisition and Tap Rock Acquisition, the Board reduced the amount of stock authorized for repurchase by us under the stock repurchase program from $1.0 billion to $500.0 million.
Removed
These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock. Sale of Unregistered Securities.
Added
The stock repurchase program does not require any specific number of shares to be acquired and can be modified or discontinued by the Board at any time.
Added
(2) Purchases outside of our stock repurchase program represent shares withheld from officers, former officers, executives, and employees for the payment of personal income tax withholding obligations upon the vesting of restricted stock awards. The withheld shares are not considered common stock repurchased under the stock repurchase program. Sale of Unregistered Securities.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

77 edited+70 added−32 removed12 unchanged
Biggest changeAdditionally, we turned 146 gross wells to sales during the year ending December 31, 2022. 64 Table of Contents The following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts): Year Ended December 31, 2022 2021 Change Percent Change Operating Expenses: Lease operating expense $ 169,986 $ 52,391 $ 117,595 224 % Midstream operating expense 31,944 17,426 14,518 83 % Gathering, transportation, and processing 287,474 64,507 222,967 346 % Severance and ad valorem taxes 305,701 65,113 240,588 369 % Exploration 6,981 7,937 (956) (12) % Depreciation, depletion, and amortization 816,446 226,931 589,515 260 % Abandonment and impairment of unproved properties 17,975 57,260 (39,285) (69) % Unused commitments 3,641 7,692 (4,051) (53) % Bad debt expense (recovery) (950) 607 (1,557) (257) % Merger transaction costs 24,683 43,555 (18,872) (43) % General and administrative expense 143,477 65,132 78,345 120 % Operating expenses $ 1,807,358 $ 608,551 $ 1,198,807 197 % Selected Costs ($ per Boe): Lease operating expense $ 2.74 $ 2.56 $ 0.18 7 % Midstream operating expense 0.51 0.85 (0.34) (40) % Gathering, transportation, and processing 4.63 3.16 1.47 47 % Severance and ad valorem taxes 4.93 3.18 1.75 55 % Exploration 0.11 0.39 (0.28) (72) % Depreciation, depletion, and amortization 13.16 11.10 2.06 19 % Abandonment and impairment of unproved properties 0.29 2.80 (2.51) (90) % Unused commitments 0.06 0.38 (0.32) (84) % Bad debt expense (recovery) (0.02) 0.03 (0.05) (167) % Merger transaction costs 0.40 2.13 (1.73) (81) % General and administrative expense 2.31 3.19 (0.88) (28) % Operating expenses $ 29.12 $ 29.77 $ (0.65) (2) % Operating expenses, excluding abandonment and impairment of unproved properties and unused commitments $ 28.77 $ 26.59 $ 2.18 8 % Lease operating expense.
Biggest changeThe following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts): Year Ended December 31, 2023 2022 Change Percent Change Operating Expenses: Lease operating expense $ 301,288 $ 169,986 $ 131,302 77 % Midstream operating expense 45,080 31,944 13,136 41 % Gathering, transportation, and processing 290,645 287,474 3,171 1 % Severance and ad valorem taxes 276,535 305,701 (29,166) (10) % Exploration 2,178 6,981 (4,803) (69) % Depreciation, depletion, and amortization 1,171,192 816,446 354,746 43 % Abandonment and impairment of unproved properties — 17,975 (17,975) (100) % Transaction costs 84,328 24,683 59,645 242 % General and administrative expense 161,077 143,477 17,600 12 % Other operating expense 7,437 2,691 4,746 176 % Total operating expenses $ 2,339,760 $ 1,807,358 $ 532,402 29 % Selected Operating Expenses (per Boe): Lease operating expense $ 3.89 $ 2.74 $ 1.15 42 % Midstream operating expense (1) 0.58 0.51 0.07 14 % Gathering, transportation, and processing 3.75 4.63 (0.88) (19) % Severance and ad valorem taxes 3.57 4.93 (1.36) (28) % Depreciation, depletion, and amortization 15.13 13.16 1.97 15 % Transaction costs 1.09 0.40 0.69 173 % General and administrative expense 2.08 2.31 (0.23) (10) % Total selected operating expenses (per Boe) $ 30.09 $ 28.68 $ 1.41 5 % _____________________________ (1) Our midstream assets relate entirely to our DJ Basin operations.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Such forward-looking statements should be read in conjunction with our disclosures under Part I, Item 1A, Risk Factors of this Form 10-K.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Such forward-looking statements should be read in conjunction with our disclosures under “ Part I - Item 1A. Risk Factors ” of this Form 10-K.
We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties.
We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our crude oil and natural gas properties.
We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Neither our PV-10 measure nor the Standardized Measure purports to present the fair value of our oil and natural gas reserves.
We use this measure when assessing the potential return on investment related to our crude oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Neither our PV-10 measure nor the Standardized Measure purports to present the fair value of our crude oil and natural gas reserves.
Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. Oil and Natural Gas Reserves. The successful efforts method of accounting outlined above inherently relies on the estimation of proved oil and natural gas reserves.
Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. Crude Oil and Natural Gas Reserves. The successful efforts method of accounting outlined above inherently relies on the estimation of proved crude oil and natural gas reserves.
The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide oil and natural gas supply and demand, which in turn has increased the volatility of oil and natural gas prices.
The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide crude oil and natural gas supply and demand, which in turn has increased the volatility of crude oil and natural gas prices.
The Credit Facility contains customary representations and various affirmative and negative covenants as well as certain financial covenants, including (a) a maximum ratio of the Company’s consolidated indebtedness to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“permitted net leverage ratio”) of 3.00 to 1 and (b) a current ratio, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1.
The Credit Facility contains customary representations and various affirmative and negative covenants as well as certain financial covenants, including (a) a maximum ratio of our consolidated indebtedness to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“permitted net leverage ratio”) of 3.00 to 1.00 and (b) a current ratio, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1.00.
Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors.
Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of crude oil and natural gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors.
We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures, and liquidity requirements. Funding for these requirements may be provided by any combination of the sources of liquidity outlined above. We expect our 2023 capital program to be funded by cash flows from operations.
We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures, and liquidity requirements. Funding for these requirements may be provided by any combination of the sources of liquidity outlined above. We expect our 2024 capital program to be funded by cash flows from operations.
Significant judgments and assumptions are inherent in these estimates and include, among other things, reserve quantities and classification, pace of drilling plans, future commodity prices, future development and lease operating costs, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition.
Significant judgments and assumptions are inherent in these estimates and include, among other things, reserve quantities and classification, pace of drilling plans, future commodity prices, future development and lease operating costs, reserve adjustment factors, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition.
On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by the Company or other market participants.
On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by us or other market participants.
Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 that are not included in this Form 10-K can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021.
Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 that are not included in this Form 10-K can be found in “ Part II - Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
See Results of Operations above for more information on the factors driving these changes.
See “ Results of Operations ” above for more information on the factors driving these changes.
We believe that free cash flow provides additional information that may be useful to investors in evaluating our ability to generate cash from our existing oil and natural gas assets to fund future exploration and development activities and to return cash to shareholders.
We believe that Free Cash Flow provides additional information that may be useful to investors in evaluating our ability to generate cash from our existing crude oil and natural gas assets to fund future exploration and development activities and to return cash to stockholders.
Although we cannot provide any assurance, based on our projected cash flows from operations, our cash on hand, and available borrowing capacity on our Credit Facility, we believe that we will have sufficient capital available to fund these requirements through the 12-month period following the filing of this report.
Although we cannot provide any assurance, based on our projected cash flows from operations, our cash on hand, and available borrowing capacity on our Credit Facility, we believe that we will have sufficient capital available to fund these requirements through the 12-month period following the filing of this report, and based on current expectations, the long-term.
Reconciliation of Free Cash Flow to Cash Provided by Operating Activities Free cash flow is a supplemental non-GAAP financial measure that is calculated as net cash provided by operating activities before changes in current assets and liabilities and less exploration and development of oil and natural gas properties, changes in working capital related to capital expenditures, and purchases of carbon offsets.
Reconciliation of Free Cash Flow to Cash Provided by Operating Activities Free Cash Flow is a supplemental non-GAAP financial measure that is calculated as net cash provided by operating activities before changes in operating assets and liabilities and less exploration and development of crude oil and natural gas properties, changes in working capital related to capital expenditures, and purchases of carbon credits.
The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering and economic data to estimate underground accumulations of oil and natural gas that cannot be precisely measured. Consequently, the Company engages a third-party petroleum consultant to prepare our estimates of oil and natural gas reserves.
The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering and economic data to estimate underground accumulations of crude oil and natural gas that cannot be precisely measured. Consequently, we engage a third-party petroleum consultant to prepare our estimates of crude oil and natural gas reserves.
As such, our cash flows are subject to significant volatility due to changes in commodity prices, as well as variations in our production volumes.
As such, our cash flows are subject to significant volatility due to changes in commodity prices, as well as variations in our sales volumes.
The preparation of these statements requires us to make certain assumptions, judgments, and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. We evaluate our estimates and assumptions on an ongoing basis.
The preparation of these statements requires us to 76 Table of Contents make certain assumptions, judgments, and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our consolidated financial statements. We evaluate our estimates and assumptions on an ongoing basis.
Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Effects of Inflation and Pricing Inflation in the United States averaged 8.0% in 2022, 4.7% in 2021, and 1.2% in 2020.
Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. 78 Table of Contents Effects of Inflation and Pricing Inflation in the United States averaged 4.1% in 2023, 8.0% in 2022, and 4.7% in 2021.
Our effective tax rate differs from the statutory United States federal income tax rate of 21% due to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, tax limitations on compensation of covered individuals, changes in valuation allowances, and other permanent differences.
Our effective tax rate differs from the statutory United States federal income tax rate of 21% due to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, tax limitations on compensation of covered individuals, changes in valuation allowances, and other permanent differences. Please refer to “ Item 8.
While WTI oil prices have strengthened, in light of uncertainty associated with oil and natural gas demand, future monetary policy relating to inflationary pressures, and governmental policies aimed at transitioning toward lower carbon energy, we cannot predict any future volatility in or levels of commodity prices or demand for oil and natural gas.
In light of uncertainty associated with crude oil and natural gas demand, future monetary policy relating to inflationary pressures, and governmental policies aimed at transitioning toward lower carbon energy, we cannot predict any future volatility in or levels of commodity prices or demand for crude oil and natural gas.
Our material long-term cash requirements from various contractual and other obligations include: debt obligations and related interest payments, firm transportation and minimum volume agreements, taxes, asset retirement obligations, and operating leases. Please refer to Item 8 for additional information.
Our material long-term cash requirements from various contractual and other obligations include: debt obligations and related interest payments, firm transportation and minimum volume agreements, taxes, asset retirement obligations, and leases. Please refer to “ Item 8. Financial Statements and Supplementary Data ” for additional information.
The Company tends to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.
We tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing crude oil and natural gas prices increase drilling activity in our areas of operations.
Cash flows used in financing activities Net cash used in financing activities of $657.4 million during 2022 was primarily the result of dividends paid of $536.9 million, the redemption of our 7.5% Senior Notes for $100.0 million, and payments of employee tax withholdings in exchange for the return of common stock of $19.6 million.
Net cash used in financing activities of $657.4 million for the year ended December 31, 2022 was primarily the result of dividends paid of $536.9 million, the redemption of our 7.5% Senior Notes for $100.0 million, and the payment of employee tax withholdings in exchange for the return of common stock of $19.6 million.
We may use our available liquidity for operating activities, working capital requirements, capital expenditures, acquisitions, the return of capital to shareholders, and for general corporate purposes. Our primary source of cash flows from operating activities is the sale of oil, natural gas, and NGLs.
We may use our available liquidity for operating activities, working capital requirements, capital expenditures, acquisitions, debt reduction, return of capital to stockholders, and for general corporate purposes. Our primary source of cash flows from operating activities is the sale of crude oil, natural gas, and NGL.
We believe the following discussions of critical accounting estimates address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
We believe the following discussions of critical accounting estimates address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. Our significant accounting policies are described in “ Item 8.
Our income tax expense for the years ended December 31, 2022 and 2021 was $405.7 million and $72.9 million, resulting in an effective tax rate of 24.5% and 28.9% on pre-tax income, respectively.
Our income tax expense for the years ended December 31, 2023 and 2022 was $215.2 million and $405.7 million, resulting in an effective tax rate of 21.5% and 24.5% on pre-tax income, respectively.
Please refer to Item 8, Note 12 - Income Taxes for additional discussion. Liquidity and Capital Resources The Company’s primary sources of liquidity include cash flows from operating activities, available borrowing capacity under the Credit Facility, potential proceeds from equity and/or debt capital markets transactions, potential proceeds from sales of assets, and other sources.
Financial Statements and Supplementary Data - Note 12 - Income Taxes ” for additional discussion. Liquidity and Capital Resources Our primary sources of liquidity include cash flows from operating activities, available borrowing capacity under the Credit Facility, potential proceeds from equity and/or debt capital markets transactions, potential proceeds from sales of assets, and other sources.
Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established. Unproved properties are routinely evaluated for continued capitalization or impairment.
Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties. Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established. Unproved properties are routinely evaluated for continued capitalization or impairment.
Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate.
Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with probable and possible reserves.
Our general and administrative expense increased $78.4 million, or 120%, to $143.5 million for the year ended December 31, 2022 from $65.1 million for the year ended December 31, 2021, and decreased 28% on an equivalent basis per Boe.
General and administrative expense. Our general and administrative expense increased 12% to $161.1 million for the year ended December 31, 2023 from $143.5 million for the year ended December 31, 2022, and decreased 10% on an equivalent basis per Boe.
In the event that reserve quantities or future commodity prices are lower than those used as inputs to determine estimates of acquisition-date fair values, the likelihood increases that certain costs may be determined to not be recoverable. In addition, we record deferred taxes for any differences between the assigned fair values and tax basis of assets and liabilities.
In the event that reserve quantities or future commodity prices are lower than those used as inputs to determine estimates of acquisition-date fair values, the likelihood increases that certain costs may be determined to not be recoverable and increases the likelihood of future impairment charges.
If carrying values exceed undiscounted future net cash flows, impairment is measured and recorded at fair value. Because there usually is a lack of quoted market prices for proved properties, the Company estimates the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount.
Because there usually is a lack of quoted market prices for proved properties, we estimate the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount.
(2) Natural gas sales excludes $3.2 million and $3.6 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2022 and 2021, respectively. (3) Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(2) Natural gas sales in the DJ Basin exclude $4.1 million, $3.2 million, and $3.6 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2023, 2022, and 2021, respectively.
Our midstream operating expense increased $14.5 million, or 83%, to $31.9 million for the year ended December 31, 2022 from $17.4 million for the year ended December 31, 2021, and decreased 40% on an equivalent basis per Boe.
Our midstream operating expense increased 41% to $45.1 million for the year ended December 31, 2023 from $31.9 million for the year ended December 31, 2022, and increased 14% on an equivalent basis per Boe.
The components of interest expense for the periods presented are as follows (in thousands): Year Ended December 31, 2022 2021 Senior Notes $ 22,521 $ 9,903 Credit Facility 115 2,019 Commitment and letter of credit fees under the Credit Facility 5,099 2,185 Amortization of deferred financing costs 4,464 1,890 Capitalized interest — (6,297) Total interest expense, net $ 32,199 $ 9,700 Income tax expense .
The components of interest expense for the periods presented are as follows (in thousands): Year Ended December 31, 2023 2022 Senior Notes $ 154,607 $ 22,521 Credit Facility 12,100 115 Commitment and letter of credit fees under the Credit Facility 6,231 5,099 Amortization of deferred financing costs 9,293 4,464 Finance lease 509 — Total interest expense $ 182,740 $ 32,199 Income tax expense .
The below graph depicts month average NYMEX WTI oil and NYMEX natural gas HH spot price over the years ended December 31, 2022 and December 31, 2021.
The below graph depicts month average NYMEX WTI crude oil and NYMEX natural gas HH spot price over the years ended December 31, 2023 and December 31, 2022. _____________________________ (1) The average NYMEX WTI crude oil spot price for the years ended December 31, 2023 and 2022 was $77.58 and $94.90, respectively.
For example, a higher fair value ascribed to a proved properties results in higher DD&A expense, which results in lower net income. As discussed above, estimated fair values assigned to proved and unproved properties are dependent on estimates of reserve quantities, future commodity prices, as well as development and operating costs.
As discussed above, estimated fair values assigned to proved and unproved properties are dependent on estimates of reserve quantities, future commodity prices, as well as development and operating costs.
Our lease operating expense increased $117.6 million, or 224%, to $170.0 million for the year ended December 31, 2022 from $52.4 million for the year ended December 31, 2021, and increased 7% on an equivalent basis per Boe.
Our lease operating expense increased 77% to $301.3 million for the year ended December 31, 2023 from $170.0 million for the year ended December 31, 2022, and increased 42% on an equivalent basis per Boe.
Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions.
Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill.
Abandonment and impairment of unproved properties. During the years ended December 31, 2022 and 2021, we incurred $18.0 million and $57.3 million, respectively, in abandonment and impairment of unproved properties due to the Company’s assessment of its locations and replacement of non-core legacy locations with newly acquired locations. Unused commitments.
During the year ended December 31, 2022, we incurred $18.0 million in abandonment and impairment of unproved properties due to our assessment over locations and the replacement of non-core legacy locations with newly acquired locations. No abandonment and impairment of unproved properties was incurred during the year ended December 31, 2023. Transaction costs.
Our significant accounting policies are described in Item 8, Note 1 - Summary of Significant Accounting Policies . Property and Equipment Proved Properties. The Company accounts for its oil and gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful.
Financial Statements and Supplementary Data - Note 1 - Summary of Significant Accounting Policies .” Crude Oil and Natural Gas Properties Proved Properties. We account for our oil and gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful.
Our severance and ad valorem taxes increased $240.6 million, or 369%, to $305.7 million for the year ended December 31, 2022 from $65.1 million for the year ended December 31, 2021, and increased 55% on an equivalent basis per Boe.
Our severance and ad valorem taxes decreased 10% to $276.5 million for the year ended December 31, 2023 from $305.7 million for the year ended December 31, 2022, and decreased 28% on an equivalent basis per Boe.
Free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. 69 Table of Contents The following table presents a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of free cash flow (in thousands): Year Ended December 31, 2022 2021 Net cash provided by operating activities $ 2,477,041 $ 274,599 Add back: changes in current assets and liabilities (276,141) 61,573 Cash flow from operations before changes in operating assets and liabilities 2,200,900 336,172 Less: exploration and development of oil and natural gas properties (967,096) (151,500) Less: changes in working capital related to capital expenditures (7,679) (128,977) Less: purchases of carbon offsets (7,298) — Free cash flow $ 1,218,827 $ 55,695 Reconciliation of Proved Reserves PV-10 to Standardized Measure PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure.
The following table presents a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of Free Cash Flow (in thousands): Year Ended December 31, 2023 2022 Net cash provided by operating activities $ 2,238,760 $ 2,477,041 Add back: Changes in operating assets and liabilities, net (71,932) (276,141) Cash flow from operations before changes in operating assets and liabilities 2,166,828 2,200,900 Less: Exploration and development of crude oil and natural gas properties (1,352,388) (967,096) Less: Changes in working capital related to capital expenditures (12,349) (7,679) Less: Purchases of carbon credits and renewable energy credits (6,151) (7,298) Free Cash Flow $ 795,940 $ 1,218,827 75 Table of Contents Reconciliation of Proved Reserves PV-10 to Standardized Measure PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure.
Our depreciation, depletion, and amortization expense increased $589.5 million, or 260%, to $816.4 million for the year ended December 31, 2022 from $226.9 million for the year ended December 31, 2021, and increased 19% on an equivalent basis per Boe.
Our depreciation, depletion, and amortization expense (“DD&A”) increased 43% to $1.2 billion for the year ended December 31, 2023 from $816.4 million for the year ended December 31, 2022, and increased 15% on an equivalent basis per Boe.
Severance and ad valorem taxes primarily correlate to revenues, which increased by 309% for the year ended December 31, 2022 when compared to the same period in 2021.
Product revenues decreased by 8% for the year ended December 31, 2023 when compared to the same period in 2022, resulting in lower severance and ad valorem taxes for the current year.
The Company was in compliance with all covenants under the Credit Facility as of December 31, 2022, and through the filing of this report.
We were in compliance with all covenants under the Credit Facility as of December 31, 2023, and through the filing of this report. Please refer to “ Item 8.
The most significant of these assumptions relate to the estimated fair values assigned to proved and unproved properties. Since sufficient market data was not available regarding the fair values of our acquired proved and unproved oil and gas properties, we engaged a third-party valuation expert to assist in preparing fair value estimates.
Because sufficient market data may not be available regarding the fair values of our acquired proved and unproved oil and gas properties, we engage a third-party valuation expert to assist in preparing the fair value estimates. We utilize a discounted cash flow approach, based on market participant assumptions.
Borrowing capacity under the Credit Facility is primarily based on the value assigned to the proved reserves attributable to our oil and natural gas interests.
As of December 31, 2023, our liquidity was $2.2 billion, consisting of cash on hand of $1.1 billion and $1.1 billion of available borrowing capacity on our Credit Facility. Borrowing capacity under the Credit Facility is primarily based on the value assigned to the proved reserves attributable to our crude oil and natural gas interests.
Partially offsetting these outflows were proceeds from the $400.0 million issuance of 5.0% Senior Notes. 68 Table of Contents Non-GAAP Financial Measures Reconciliation of EBITDAX to Net Income Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges.
Non-GAAP Financial Measures Reconciliation of EBITDAX to Net Income Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges.
Please refer to Item 8, Note 5 - Long-Term Debt for additional information. 67 Table of Contents Our material short-term cash requirements include: operating activities, working capital requirements, capital expenditures, commodity derivative liabilities, dividends, and payments of contractual obligations.
Financial Statements and Supplementary Data - Note 5 - Long-Term Debt ” for additional information. 72 Table of Contents Our material short-term cash requirements include: consideration for the Vencer Acquisition, operating activities, working capital requirements, capital expenditures, dividends, and payments of contractual obligations.
Executive Summary We are an independent exploration and production company focused on the acquisition, development, and production of oil and associated liquids-rich natural gas in the Rocky Mountain region, primarily in the DJ Basin of Colorado.
Executive Summary We are an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas primarily in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. Our primary objective is to maximize stockholder returns by responsibly developing our crude oil and natural gas resources.
(4) Derivatives economically hedge the price we receive for oil, natural gas, and NGL. For the year ended December 31, 2022, the derivative cash settlement loss for oil, natural gas, and NGLs was $346.4 million, $189.4 million, $41.0 million, respectively.
For the year ended December 31, 2023, the derivative cash settlement loss for crude oil and natural gas was $59.5 million and $8.7 million, respectively. For the year ended December 31, 2022, the derivative cash settlement loss for crude oil, natural gas, and NGL was $346.4 million, $189.4 million, and $41.0 million, respectively. Please refer to “ Item 8.
The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDAX (in thousands): Year Ended December 31, 2022 2021 Net income $ 1,248,080 $ 178,921 Exploration 6,981 7,937 Depreciation, depletion, and amortization 816,446 226,931 Abandonment and impairment of unproved properties 17,975 57,260 Stock-based compensation (1) 31,367 15,558 Non-recurring general and administrative expense (1) 18,037 2,609 Merger transaction costs 24,683 43,555 Unused commitments 3,641 7,692 Gain on property transactions, net (15,880) (1,932) Interest expense 32,199 9,700 Derivative loss 335,160 60,510 Derivative cash settlement loss (576,802) (275,914) Income tax expense 405,698 72,858 Adjusted EBITDAX $ 2,347,585 $ 405,685 _________________________ (1) Included as a portion of general and administrative expense in the accompanying consolidated statements of operations and comprehensive income (“statements of operations”).
Because adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. 74 Table of Contents The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of adjusted EBITDAX (in thousands): Year Ended December 31, 2023 2022 Net income $ 784,288 $ 1,248,080 Exploration 2,178 6,981 Depreciation, depletion, and amortization 1,171,192 816,446 Abandonment and impairment of unproved properties — 17,975 Unused commitments and other (1) 5,013 3,641 Transaction costs 84,328 24,683 Stock-based compensation (2) 34,931 31,367 Non-recurring general and administrative expense (2) — 18,037 Derivative (gain) loss (9,307) 335,160 Derivative cash settlement loss (68,246) (576,802) Interest expense 182,740 32,199 Interest income (3) (33,347) — (Gain) loss on property transactions, net 254 (15,880) Income tax expense 215,166 405,698 Adjusted EBITDAX $ 2,369,190 $ 2,347,585 _________________________ (1) Included as a portion of other operating expense in the accompanying statements of operations.
Please refer to Item 8, Note 5 - Long-Term Debt for more information about financial covenants under our Credit Facility. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and natural gas exploration and production industry.
In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry.
Although inflation increased significantly in 2022, inflation did not have a material impact on our results of operations for the period ended December 31, 2022, or for the periods ended December 31, 2021 and 2020.
During 2023 and 2022, we experienced cost inflation on labor, power and other key costs in our operations and development program, however, it did not have a material impact on our results of operations for the periods ended December 31, 2023, 2022, or 2021.
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated: Year Ended December 31, 2022 2021 Change Percent Change Revenues (in thousands): Crude oil sales (1) $ 2,535,496 $ 613,804 $ 1,921,692 313 % Natural gas sales (2) 691,903 141,090 550,813 390 % NGL sales 560,185 171,095 389,090 227 % Product revenue $ 3,787,584 $ 925,989 $ 2,861,595 309 % Sales Volumes: Crude oil (MBbls) 27,650.1 9,384.6 18,265.5 195 % Natural gas (MMcf) 112,478.3 36,763.4 75,714.9 206 % NGL (MBbls) 15,666.4 4,933.6 10,732.8 218 % Crude oil equivalent (MBoe) (3) 62,062.9 20,445.4 41,617.5 204 % Average Sales Prices (before derivatives) (4) : Crude oil (per Bbl) $ 91.70 $ 65.41 $ 26.29 40 % Natural gas (per Mcf) $ 6.15 $ 3.84 $ 2.31 60 % NGL (per Bbl) $ 35.76 $ 34.68 $ 1.08 3 % Crude oil equivalent (per Boe) (3) $ 61.03 $ 45.29 $ 15.74 35 % Average Sales Prices (after derivatives) (4) : Crude oil (per Bbl) $ 79.17 $ 42.49 $ 36.68 86 % Natural gas (per Mcf) $ 4.47 $ 2.43 $ 2.04 84 % NGL (per Bbl) $ 33.14 $ 32.84 $ 0.30 1 % Crude oil equivalent (per Boe) (3) $ 51.73 $ 31.80 $ 19.93 63 % _____________________________ (1) Crude oil sales excludes $0.6 million and $1.0 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2022 and 2021, respectively.
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated: Year Ended December 31, 2023 2022 Change Percent Change Revenues (in thousands): Crude oil sales (1) $ 2,775,364 $ 2,535,496 $ 239,868 9 % Natural gas sales (2) 305,629 691,903 (386,274) (56) % NGL sales 392,828 560,185 (167,357) (30) % Product revenue $ 3,473,821 $ 3,787,584 $ (313,763) (8) % Sales Volumes: Crude oil (MBbls) 36,726 27,651 9,075 33 % Natural gas (MMcf) 133,821 112,478 21,343 19 % NGL (MBbls) 18,400 15,666 2,734 17 % Total sales volumes (MBoe) 77,430 62,063 15,367 25 % Average Sales Prices (before derivatives): Crude oil (per Bbl) $ 75.57 $ 91.70 $ (16.13) (18) % Natural gas (per Mcf) 2.28 6.15 (3.87) (63) % NGL (per Bbl) 21.35 35.76 (14.41) (40) % Total (per Boe) 44.86 61.03 (16.17) (26) % Average Sales Prices (after derivatives) (3) : Crude oil (per Bbl) $ 73.95 $ 79.17 $ (5.22) (7) % Natural gas (per Mcf) 2.22 4.47 (2.25) (50) % NGL (per Bbl) 21.35 33.14 (11.79) (36) % Total (per Boe) (3) 43.98 51.73 (7.75) (15) % _____________________________ (1) Crude oil sales excludes $1.3 million and $0.6 million of crude oil transportation revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2023 and 2022, respectively.
Despite the prevalence of climate change-related regulations, policies and initiatives (across the market at the corporate level and/or investor community level), we did not incur any material increase in compliance costs related to climate change in the year ended December 31, 2022, and we do not presently anticipate the incurrence of any material increases in future periods. 63 Table of Contents Results of Operations The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto contained in Item 8 of this Annual Report on Form 10-K.
We do not presently anticipate the occurrence of any material effects on our business, financial condition, or results of operations in future periods as a result of capital designated on these initiatives. 67 Table of Contents Results of Operations The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto contained in Item 8 of this Annual Report on Form 10-K.
Please refer to Item 8, Note 9 - Derivatives for additional discussion. 66 Table of Contents Interest expense. Our interest expense for the years ended December 31, 2022 and 2021 was $32.2 million and $9.7 million, respectively. Average debt outstanding for the years ended December 31, 2022 and 2021 was $435.5 million and $217.9 million, respectively.
Our interest expense for the years ended December 31, 2023 and 2022 was $182.7 million and $32.2 million, respectively. Average debt outstanding for the years ended December 31, 2023 and 2022 was $2.1 billion and $435.5 million, respectively.
Significant inputs and engineering assumptions used in developing the estimates of proved oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking.
Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking. 77 Table of Contents 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.
Gathering, transportation, and processing expense increased $223.0 million, or 346%, to $287.5 million for the year ended December 31, 2022 from $64.5 million for the year ended December 31, 2021, and increased 47% on an equivalent basis per Boe. Sales volumes have a direct correlation to gathering, transportation, and processing expense and increased 204% during the comparable periods.
Gathering, transportation, and processing expense increased $3.2 million, or 1%, to $290.6 million for the year ended December 31, 2023 from $287.5 million for the year ended December 31, 2022, and decreased 19% on an equivalent basis per Boe.
The following table provides a reconciliation of the GAAP financial measure of Standardized Measure to the non-GAAP financial measure of PV-10 as of the periods presented (in millions): December 31, 2022 2021 2020 PV-10 $ 9,834.3 $ 5,327.2 $ 437.1 Present value of future income taxes discounted at 10% (1,906.8) (915.1) — Standardized Measure $ 7,927.5 $ 4,412.1 $ 437.1 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 following table provides a reconciliation of the GAAP financial measure of Standardized Measure to the non-GAAP financial measure of PV-10 as of the periods presented (in millions): As of December 31, 2023 2022 2021 Standardized Measure $ 8,269.3 $ 7,927.5 $ 4,412.1 Present value of future income taxes discounted at 10% 1,110.7 1,906.8 915.1 PV-10 $ 9,380.0 $ 9,834.3 $ 5,327.2 Reconciliation of average sales price, after derivatives Average sales price, after derivatives is a non-GAAP financial measure that incorporates the net effect of derivative cash receipts from or payments on commodity derivatives that are presented in our statement of cash flows, netted into the average sales price, before derivatives, the most directly comparable GAAP financial measure.
The net book value of the Company’s midstream assets was $326.8 million as of December 31, 2022. 62 Table of Contents Current Events and Outlook Commodity prices continue to be impacted by various macro-economic factors influencing the balance of supply and demand.
Commodity prices continue to be impacted by various macro-economic factors influencing the balance of supply and demand.
General and administrative expense per Boe decreased due to oil equivalent sales volumes being 204% higher during the year ended December 31, 2022 as compared to the same period in 2021. Derivative gain (loss).
The increase in general and administrative expense is primarily due to an increase in headcount and an increase in professional services, partially offset by a decrease in charitable contributions. General and administrative expense per Boe decreased due to total sales volumes increasing 25% during the year ended December 31, 2023 as compared to the same period in 2022.
Our derivative loss for the years ended December 31, 2022 and December 31, 2021 of $335.2 million and $60.5 million, respectively, was due to settlement losses caused by market prices being higher than our current contracted hedge prices, partially offset by fair market value adjustments caused by market prices being lower relative to our future contracted hedge prices.
Derivative gain (loss), net. Our derivative gain for the year ended December 31, 2023 of $9.3 million was due to fair market value adjustments resulting from lower market prices relative to our open positions, partially offset by cash settlement 71 Table of Contents losses.
The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands): Year Ended December 31, 2022 2021 Net cash provided by operating activities $ 2,477,041 $ 274,599 Net cash provided by (used in) investing activities (1,306,095) 73,547 Net cash used in financing activities (657,368) (118,435) Cash, cash equivalents, and restricted cash 768,134 254,556 Acquisition of oil and natural gas properties (377,923) (1,250) Exploration and development of oil and natural gas properties (967,096) (151,500) Cash flows provided by operating activities Net cash provided by operating activities increased by $2.2 billion to $2.5 billion in 2022 as compared to $274.6 million in 2021, which was attributable to our normal operating cycle.
The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands): Year Ended December 31, 2023 2022 Net cash provided by operating activities $ 2,238,760 $ 2,477,041 Net cash used in investing activities (5,243,155) (1,306,095) Net cash provided by (used in) financing activities 3,363,076 (657,368) Cash, cash equivalents, and restricted cash 1,126,815 768,134 Acquisitions of businesses, net of cash acquired (3,655,612) (236,160) Acquisitions of crude oil and natural gas properties (154,855) (97,453) Exploration and development of crude oil and natural gas properties (1,352,388) (967,096) Operating Activities Our net cash flows from operating activities are primarily impacted by commodity prices, sales volumes, net settlements from our commodity derivative positions, operating costs, and general and administrative expenses.
When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves. 71 Table of Contents Estimated fair values ascribed to assets acquired can have a significant impact on future results of operations presented in the Company’s financial statements.
Estimated fair values ascribed to assets acquired can have a significant impact on future results of operations presented in our consolidated financial statements. For example, a higher fair value ascribed to proved properties results in higher DD&A expense, which results in lower net income.
Cash flows provided by (used in) investing activities Net cash used in investing activities of $1.3 billion during 2022 was primarily the result of the exploration and development of oil and natural gas properties of $967.1 million, acquisitions of oil and natural gas properties of $377.9 million that included the Bison Acquisition and the purchase additional working interests in certain Company-operated wells, partially offset by $44.3 million of cash acquired in the Bison Acquisition.
Total investing activities were partially offset by $90.5 million of proceeds from the sale of crude oil and natural gas properties. 73 Table of Contents Net cash used in investing activities of $1.3 billion for the year ended December 31, 2022 was primarily the result of the exploration and development of crude oil and natural gas properties of $967.1 million, acquisitions of businesses, net of cash acquired of $236.2 million, and acquisitions of crude oil and natural gas properties of $97.5 million.
If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of proved property. Business Combinations As part of our business strategy, we regularly pursue the acquisition of oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses.
Financial Statements and Supplementary Data - Note 16 - Disclosures About Oil and Gas Producing Activities ” included elsewhere in this report. Business Combinations As part of our business strategy, we regularly pursue the acquisition of crude oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses.
On April 20, 2022, the Company entered into an amendment to the Credit Agreement that increased the Company’s borrowing base from $1.0 billion to $1.7 billion and the aggregate elected commitment amount from $800.0 million to $1.0 billion.
On August 2, 2023, we closed the Hibernia Acquisition and Tap Rock Acquisition and simultaneously entered into an amendment to the Credit Facility that increased our aggregate elected commitments from $1.0 billion to $1.85 billion, increased the borrowing base from $1.85 billion to $3.0 billion, and increased the aggregate maximum credit commitment from $2.0 billion to $4.0 billion.
During the years ended December 31, 2022 and 2021, we incurred $24.7 million and $43.6 million, respectively, in legal, advisor, and other costs associated with the HighPoint, Extraction, and Crestone Peak mergers as well as the Bison Acquisition.
During the year ended December 31, 2023, we incurred $84.3 million in short-term financing fees as well as legal, advisor, and other costs associated with the Hibernia Acquisition, Tap Rock Acquisition, and Vencer Acquisition.
The expected future cash flows used for impairment reviews include future production volumes associated with proved developed producing reserves and risk-adjusted proved undeveloped reserves, and when needed, probable and possible reserves. Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties.
Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with proved developed producing reserves and risk-adjusted proved undeveloped reserves.
This section of this Form 10-K generally discusses 2022 and 2021 results and year-to-year comparisons between 2022 and 2021.
Additionally, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables. This section of this Form 10-K generally discusses 2023 and 2022 results and year-to-year comparisons between 2023 and 2022.
The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment.
The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. We assess proved properties for impairment whenever events or circumstances indicate that their carrying value may not be recoverable. If carrying values exceed undiscounted future net cash flows, impairment is measured and recorded at fair value.
For the year ended December 31, 2021, the derivative cash settlement loss for oil, natural gas, and NGLs was $215.1 million, $51.8 million, and $9.1 million, respectively. Please refer to Item 8, Note 9 - Derivatives for additional disclosures.
Our derivative loss for the year ended December 31, 2022 of $335.2 million was due to cash settlement losses, partially offset by fair market value adjustment gains attributable to lower market prices relative to our open positions. Please refer to “ Item 8. Financial Statements and Supplementary Data - Note 9 - Derivatives ” for additional discussion. Interest expense.
Net cash provided by investing activities of $73.5 million during 2021 was primarily the result of cash acquired in the HighPoint, Extraction, and Crestone Peak Mergers of $223.7 million, partially offset by the exploration and development of oil and natural gas properties of $151.5 million.
Net cash used in investing activities of $5.2 billion for the year ended December 31, 2023 was primarily the result of (i) acquisitions of businesses, net of cash acquired of $3.7 billion; (ii) exploration and development of crude oil and natural gas properties of $1.4 billion; (iii) a deposit for acquisitions of $161.3 million; and (iv) acquisitions of crude oil and natural gas properties of $154.9 million.
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We believe our acreage in the DJ Basin has been significantly delineated by our own drilling success and by the success of offset operators, providing confidence that our results are repeatable and will continue to generate economic returns. The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production.
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To achieve this, we are guided by four foundational pillars that we believe add long-term, sustainable value.
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The Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and natural gas resources. To achieve this, Civitas is guided by four foundational pillars that we believe add long-term, sustainable value. These pillars are: generate free cash flow, maintain a premier balance sheet, return free cash flow to shareholders, and demonstrate ESG leadership.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeAny increases in these interest rates can have an adverse impact on our results of operations and cash flows. As of December 31, 2022 and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants.
Biggest changeAs of December 31, 2023 and through the filing date of this report, we were in compliance with all financial and non-financial covenants under the Credit Facility. 79 Table of Contents Counterparty and Customer Credit Risk In connection with our derivative activities, we have exposure to financial institutions in the form of derivative transactions.
Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.
Any reduction in our crude oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in crude oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.
It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically.
It is impossible to predict future crude oil and natural gas prices with any degree of certainty. Sustained weakness in crude oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of crude oil and natural gas reserves that we can produce economically.
Factors influencing oil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions.
Factors influencing crude oil and natural gas prices include the level of global demand for crude oil and natural gas, the global supply of crude oil and natural gas, the establishment of and compliance with production quotas by crude oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions.
This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned. 72 Table of Contents While we may reduce the potential negative impact of lower commodity prices, we may also be prevented from realizing the benefits of favorable price changes in the physical market.
This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned. While we may reduce the potential negative impact of lower commodity prices, we may also be prevented from realizing the benefits of favorable price changes in the physical market.
If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow. 73 Table of Contents
If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow. 80 Table of Contents
If oil and natural gas SEC prices declined by 10%, our proved reserve volumes would decrease by 1% and our PV-10 value as of December 31, 2022 would decrease by approximately 13% or $1.3 billion.
If crude oil and natural gas SEC prices declined by 10%, our proved reserve volumes would decrease by 3% and our PV-10 value as of December 31, 2023 would decrease by approximately 18% or $1.6 billion.
If oil and natural gas SEC prices increased by 10%, our proved reserve volumes would increase by 1% and our PV-10 value as of December 31, 2022 would increase by approximately 13% or $1.3 billion. PV-10 is a non-GAAP financial measure. Please refer to Non-GAAP Financial Measures under Part I, Item 7 for management’s discussion of this non-GAAP financial measure.
If crude oil and natural gas SEC prices increased by 10%, our proved reserve volumes would increase by 2% and our PV-10 value as of December 31, 2023 would increase by approximately 18% or $1.7 billion. PV-10 is a non-GAAP financial measure. Please refer to “ Item 7.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk. Oil and Natural Gas Price Risk Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk. Crude Oil and Natural Gas Price Risk Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of crude oil and natural gas.
For the derivatives outstanding at December 31, 2022, a hypothetical upward or downward shift of 10% in the forward curve for the related indices would increase our derivative loss by $20.7 million or decrease it by $20.4 million, respectively. Please refer to the Derivative Activities section of Part I, Item 1 for summary derivative activity tables.
For the derivatives outstanding at December 31, 2023, a hypothetical upward or downward shift of 10% in the forward curve for the related indices would decrease our derivative gain by $81.1 million or increase it by $82.3 million, respectively. Please refer to “ Item 8.
Commodity Price Derivative Contracts Our primary commodity risk management objective is to protect the Company’s balance sheet. We periodically enter into derivative contracts for oil, natural gas, and natural gas liquids using NYMEX futures or over-the-counter derivative financial instruments. The types of derivative instruments that we use include swaps, collars, and puts.
We periodically enter into derivative contracts for crude oil, natural gas, and NGL using NYMEX futures or over-the-counter derivative financial instruments. The types of derivative instruments that we use include swaps, collars, basis protection swaps, and puts.
However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss. We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers.
We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with certain significant customers. 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.
Interest Rates At both December 31, 2022 and on the filing date of this report, we had a zero balance on our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an Alternate Base Rate or Secured Overnight Financing Rate, at our option.
Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an Alternate Base Rate or Secured Overnight Financing Rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flows.
Counterparty and Customer Credit Risk In connection with our derivative activity, we have exposure to financial institutions in the form of derivative transactions. As of December 31, 2022, our derivative contracts have been executed with 7 counterparties, all of which are members of the Credit Facility lender group and have investment grade credit ratings.
As of December 31, 2023, and the filing date of this report, our derivative contracts have been executed with 15 counterparties, all of which are members of the Credit Facility lender group and have investment grade credit ratings. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.
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. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.
We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral. Our allowances for credit losses were insignificant as of December 31, 2023.
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These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations - Non-GAAP Financial Measures ” for management’s discussion of this non-GAAP financial measure. Commodity Price Derivative Contracts Our primary commodity risk management objective is to protect our balance sheet.
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Financial Statements and Supplementary Data - Note 9 - Derivatives ” for summary derivative activity tables. Interest Rates As of December 31, 2023, we had a $750.0 million balance on our Credit Facility. As of the filing date of this report, we had a $400.0 million balance on our Credit Facility.

Other CIVI 10-K year-over-year comparisons