Washington, D.C. 20549
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
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Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
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The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2023 was approximately $2.1 billion.
While the Merger Agreement is in effect, we are subject to certain interim covenants. The Merger Agreement generally requires us to operate our business in the ordinary course, subject to certain exceptions, including as required by applicable law, pending consummation of the Merger, and subjects us to customary interim operating covenants that restrict us, without APA’s approval (such approval not to be unreasonably conditioned, withheld or delayed), from taking certain specified actions until the Merger is completed or the Merger Agreement is terminated in accordance with its terms. These restrictions could prevent us from pursuing certain business opportunities that may arise prior to the consummation of the Merger and may affect our ability to execute our business strategies and attain financial and other goals and may impact our financial condition, results of operations and cash flows.
The announcement and pendency of the Merger may result in disruptions to our business, and the Merger could divert management's attention, disrupt our relationships with third parties and employees, and result in negative publicity or legal proceedings, any of which could negatively impact our operating results and ongoing business. In connection with the pending Merger, our current and prospective employees may experience uncertainty about their future roles with us following the Merger, which may materially adversely affect our ability to attract and retain key personnel and other employees while the Merger is pending. Key employees may depart prior to the consummation of the Merger because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with us following the Merger.
The proposed Merger may cause disruptions to our business or business relationships with our existing and potential suppliers and other business partners, and this could have an adverse impact on our results of operations. Parties with which we have business relationships may experience uncertainty as to the future of such relationships and may delay or defer certain business decisions, seek alternative relationships with third parties, or seek to negotiate changes to or alter their present business relationships with us. Parties with whom we otherwise may have sought to establish business relationships may seek alternative relationships with third parties.
The pursuit of the proposed Merger has placed an increased burden on management and internal resources, which may have a negative impact on our ongoing business. It also diverts management’s time and attention from the day-to-day operation of our business, which could adversely affect our financial results. In addition, we have incurred and will continue to incur other significant costs, expenses and fees for professional services and other transaction costs in connection with the proposed Merger, and many of these fees and costs are payable regardless of whether or not the pending Merger is consummated.
Any of the foregoing, individually or in combination, could materially and adversely affect our business, our financial condition and our results of operations and prospects.
The Merger may not be completed within the expected timeframe, or at all, for a variety of reasons, including the possibility that the Merger Agreement is terminated, and the failure to complete the Merger could adversely affect our business, results of operations, financial condition and the market price of our common stock. There can be no assurance that the Merger will be completed in the expected timeframe or at all. The Merger Agreement contains a number of customary closing conditions that must be satisfied or waived prior to the completion of the Merger, including, among others, (i) the receipt of the required approvals from Callon shareholders and APA shareholders and (ii) the absence of any governmental order or law prohibiting consummation of the Merger.
Many of the conditions to completion of the merger are not within either Callon’s or APA’s control. If any of these closing conditions are not satisfied or waived prior to October 3, 2024 (or such date as extended pursuant to the terms set forth in the Merger Agreement), it is possible that the Merger Agreement may be terminated. The Merger Agreement also provides both Callon and APA with certain termination rights. Furthermore, the requirements for obtaining the required clearances and approvals could delay the completion of the Merger for a significant period of time or prevent the Merger from occurring. There can be no assurance that all required regulatory approvals will be obtained or obtained prior to the termination date.
If the Merger is not consummated within the expected time frame or at all, we may be subject to a number of material risks. The price of our common stock may decline to the extent that current market prices reflect a market assumption that the Merger will be completed. In addition, some costs, expenses and fees related to the Merger must be paid whether or not the Merger is completed, and we have incurred, and will continue to incur, significant costs, expenses and fees for professional services and other transaction costs in connection with the proposed Merger, as well as the direction of management resources towards the Merger, for which we will have received little or no benefit if the closing of the Merger does not occur. We may also experience negative reactions from our shareholders and other investors, employees and other parties with which we maintain business relationships. In addition, if the Merger Agreement is terminated, in specified circumstances, we may be required to pay a termination fee. If the Merger is not
consummated, there can be no assurance that any other transaction acceptable to us will be offered or that our business, prospects or results of operations will not be adversely affected.
Litigation relating to the Merger could result in an injunction preventing the completion of the Merger and/or substantial costs to us. Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Such lawsuits could also seek, among other things, injunctive relief or other equitable relief, including a request to enjoin us and APA from consummating the Merger.
The Merger Agreement limits Callon’s ability to pursue alternatives to the Merger, may discourage certain other companies from making a favorable alternative transaction proposal, and, in specified circumstances, could require Callon to pay APA a termination fee. The Merger Agreement contains certain provisions that restrict each of APA’s and Callon’s ability to initiate, solicit, knowingly encourage, or knowingly facilitate any inquiry or the making of any proposal or offer that constitutes, or would reasonably be expected to result in, a competing proposal with respect to APA or Callon, as applicable, and APA and Callon have each agreed to certain terms and conditions relating to their ability to engage in, continue, or otherwise participate in any discussions with respect to, provide any third party confidential information with respect to, or enter into any acquisition agreement with respect to certain unsolicited proposals that constitute or are reasonably likely to lead to a competing proposal. The Merger Agreement further provides that under specified circumstances, including after receipt of certain alternative acquisition proposals, each of APA and Callon may be required to pay the other a cash termination fee equal to $170 million (if APA is the payor) or $85 million (if Callon is the payor). These and other provisions in the Merger Agreement could discourage a potential third party acquirer or other strategic transaction partner that might have an interest in acquiring all or a significant portion of Callon from considering or pursuing an alternative transaction with Callon or proposing such a transaction, even if it were prepared to pay consideration with a higher per share value than the total value proposed to be paid or received in the Merger. These provisions might also result in a potential third-party acquirer or other strategic transaction partner proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the termination fee or expense reimbursement that may become payable in certain circumstances.
Even if the Merger is completed, the combined company may fail to realize the anticipated benefits of the Merger and the integration of the businesses and operations of APA and Callon may not be as successful as anticipated. The success of the Merger will depend, in part, on the combined company’s ability to realize the anticipated benefits and cost savings from combining our and APA’s businesses, and there can be no assurance that the combined company will be able to successfully integrate us or otherwise realize the expected benefits of the Merger. Difficulties in integrating us into the combined company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include harmonizing the companies’ operating practices, employee development and compensation programs, internal controls, and other policies, procedures, and processes; maintaining existing agreements with customers, providers, and vendors or business partners and avoiding delays in entering into new agreements with prospective customers, providers, and vendors or business partners; addressing possible differences in business backgrounds, corporate cultures, and management philosophies; consolidating the companies’ operating, administrative, and information technology infrastructure and financial systems; and coordinating distribution and marketing efforts.
Completion of the Merger may trigger change in control or other provisions in certain agreements to which Callon is a party. If APA and Callon are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements, or seeking monetary damages. Even if APA and Callon are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to Callon.
Our shareholders will have a reduced ownership and voting interest after the Merger and will exercise less influence over the policies of the combined company than they now have on the policies of Callon. Immediately after the Merger is completed, it is expected that our current shareholders will own approximately 19% of APA’s outstanding common stock and current APA shareholders will own approximately 81% of APA’s outstanding common stock. As a result, our current shareholders will have less influence on the management and policies of the combined company than they now have on the management and policies of Callon.
Because the market price of APA common stock will fluctuate, Callon shareholders cannot be sure of the value of the shares of APA common stock they will receive in the Merger. In addition, because the Exchange Ratio is fixed, the number of shares of APA common stock to be received by Callon shareholders in the Merger will not change between now and the time the Merger is completed to reflect changes in the trading prices of APA common Stock or Callon common stock. As a result of the Merger, each eligible share of Callon common stock will be converted automatically into the right to receive, without interest, 1.0425 shares of APA common stock, with cash paid in lieu of the issuance of any fractional shares of APA common stock. The Exchange Ratio is fixed, which means that it will not change between now and the closing date, regardless of whether the market price of either APA common stock or Callon common stock changes. Therefore, the value of the Merger consideration will depend on the market price of APA common stock at the Effective Time. The market price of APA common stock has fluctuated since the date of the announcement of the parties’ entry into the Merger Agreement and will continue to fluctuate.
The market price of shares of APA common stock may decline in the future as a result of the sale of shares of APA common stock held by former Callon shareholders or APA’s other shareholders. Following their receipt of shares of APA common stock as consideration in the Merger, our shareholders may seek to sell the shares of APA common stock delivered to them, and the Merger Agreement contains no restriction on the ability of our shareholders to sell such shares of APA common stock following completion of the Merger. Other shareholders of APA may also seek to sell shares of APA common stock held by them following, or in anticipation of, completion of the Merger. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of APA common stock to be issued in the Merger, may affect the market for, and the market price of, APA common stock in an adverse manner.
Risks Related to the Oil & Natural Gas Industry
Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which have in recent years been, and we expect will continue to be, extremely volatile. During the three years ended December 31, 2023, NYMEX WTI prices ranged from a high of $123.64 per barrel on March 8, 2022 to a low of $47.47 per barrel on January 4, 2021, and NYMEX Henry Hub prices ranged from a high of $23.86 per MMBtu on February 17, 2021 to a low of $1.74 per MMBtu on June 2, 2023. Prices were particularly volatile in 2020 and 2021, with five-year highs occurring in 2021 and five-year lows occurring in 2020, as a result of multiple significant factors impacting supply and demand in the global oil and natural gas markets, including those relating to the COVID-19 global pandemic. The prices of oil and natural gas depend on factors we cannot control, such as macro-economic conditions, levels of production, domestic and worldwide inventories, demand for oil and natural gas, the capacity of U.S. and international refiners to use U.S. supplies of oil, natural gas and NGLs, relative price and availability of alternative forms of energy, actions by non-governmental organizations, OPEC and other countries, legislative and regulatory actions, trade embargoes or sanctions, technology developments impacting energy consumption and energy supply, and weather. These factors make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and non-cancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.
In general, prices of oil, natural gas, and NGLs affect the following aspects of our business: our revenues, cash flows, earnings and returns; our ability to attract capital to finance our operations and the cost of the capital; the amount we are allowed to borrow under our Credit Facility; the profit or loss we incur in exploring for and developing our reserves; and the value of our oil and natural gas properties.
A substantial or extended decline in commodity prices may also reduce the amount of oil and natural gas that we can produce economically and cause a significant portion of our development projects to become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to replace our production and our future rate of growth, or require us to borrow funds to cover any such shortfall, which we may be unable to obtain at such time on satisfactory terms. Additionally, a sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, would require us to reevaluate and postpone or eliminate additional drilling.
Additionally, if we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.
If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the net book value of our oil and natural gas properties. Under the successful efforts method, we review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their net book value may have occurred. In addition, we evaluate significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. 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, we may be required to write down the net book value of our oil and gas properties, which may result in a decrease in the amount available under the Credit Facility. See “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information.
Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry, which could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for oil and natural gas. Increasing attention from governmental and regulatory bodies, investors, consumers, industry and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial behavior, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary climate-related disclosures, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in the enactment of climate change-related regulations, policies and initiatives (at the government, regulator, corporate and/or investor community levels), including alternative energy requirements, new fuel consumption standards, energy conservation and emissions reductions measures and responsible energy development; technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology); increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services. For further discussions regarding risk related to technological developments, see “—We may not be able to keep pace with technological developments in our industry.” These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products. Such developments may also adversely impact, among other things, our revenues, stock price and access to capital markets, and the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Climate change-related developments may also impact the market prices of or our access to raw materials such as energy and water and therefore result in increased costs to our business.
More broadly, the enactment of climate change-related regulations, policies and initiatives across the market at the government, corporate, and/or investor community levels may in the future result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation). For further discussion regarding the risks posed to us by climate change-related regulations, policies and initiatives, negative public perception of the oil and gas industry, and increasing scrutiny of ESG matters, see the discussions below in “—Negative public perception of the oil and gas industry could have a material and adverse effect on us,” “—Increased scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation,” and “—Climate change legislation or regulations restricting emissions of GHG or requiring the reporting of GHG emissions or climate-related information could adversely impact our operating costs and demand for the oil and natural gas we produce.”
Negative public perception of the oil and gas industry could have a material and adverse effect on us. Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change may lead to increased reputational and litigation risk and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. Activism could materially and adversely impact our ability to operate our business and raise capital. The foregoing factors may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. In addition, various officials and candidates at the federal, state and local levels, have made climate-related pledges or proposed banning hydraulic fracturing altogether.
In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas, or claims alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or customers. Although our business is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way.
Negative perceptions regarding our industry and reputational risks may also in the future adversely affect our ability to successfully carry out our business strategy by adversely affecting our access to capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Parties concerned about the potential effects of climate change have directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, and some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Further,
certain investment banks and asset managers based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Institutional lenders who provide financing to companies in the energy sector have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. Such developments, including ESG activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in an increase in our expenses and a reduction of revenues and available capital funding for potential development projects, impacting our future financial results.
Increased scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation. In recent years, companies across all industries are facing increasing scrutiny from a variety of stakeholders, including investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies, related to their ESG and sustainability practices. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters (or meet sustainability goals and targets that we have set), as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected.
In addition, the Company’s continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any specific ESG objectives, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. While we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Further, failure or a perception (whether or not valid) of failure to implement our ESG strategy or achieve sustainability goals and targets we have set, including emissions reduction goals, could damage our reputation, causing our investors or consumers to lose confidence in our Company, and negatively impact our business. Our continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any ESG goals, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. For example, growing interest on the part of investors and regulators in ESG factors and increased demand for, and scrutiny of, ESG-related disclosure by stakeholders has also increased the risk that companies could be perceived as, or accused of, making inaccurate or misleading statements regarding their ESG-related claims, goal, targets, efforts or initiatives, often referred to as "greenwashing." Such perception or accusation could damage our reputation and result in litigation or regulatory actions. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.
Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our shareholders, employees, suppliers, customers, local communities and others. We may face pressure from stakeholders, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability while at the same time remaining a successfully operating public company. If we do not successfully manage expectations across these varied stakeholder interests, it could erode stakeholder trust and thereby affect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand and growth opportunities, delays in projects, increased legal action and regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and difficulty securing investors and access to capital.
The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability. From time to time, during periods of increasing oil and natural gas prices and in periods in which the levels of exploration and production increase, our industry experiences a shortage of drilling and workover rigs, other equipment, pipes, materials and supplies, water and qualified personnel. As a result of such shortage, the costs and delivery times of rigs, equipment and supplies often increase substantially, as well as the wages and costs of drilling rig crews and other experienced personnel and oilfield services, while the quality of these services and equipment may suffer. This impact may be magnified to the extent that the Company's ability to participate in the commodity price increases is limited by its derivative risk management activities. Cost increases in and shortages of such resources may also result from a variety of other factors beyond our control, such as general inflationary pressures, transportation constraints,
and increases in the cost of necessary inputs such as electricity, steel and other raw materials, including as a result of increased tariffs or geopolitical issues.
An excess supply of oil and natural gas in the market may in the future cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. An excess supply of oil and natural gas in the market may result in transportation and storage capacity constraints. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Further, any prolonged shut-in of our wells may result in materially decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.
Operational Risks
Our operations are dependent on third-party service providers. We contract with third-party service providers to support our operations. These contracted services are generally provided pursuant to master services agreements entered into between the third-party service providers and our operating subsidiaries. Although we have our own employees, our ability to conduct operations and generate revenues is dependent on the availability and performance of those third-party service providers and their compliance with the terms of their respective master service agreements. We cannot guarantee that we will be successful in either retaining the services of our current third-party service providers or contracting with alternative service providers in the event that our current contractors discontinue providing services to us or fail to meet their obligations under their respective master services agreements. Any failure to retain the services of our current service providers or locate alternatives will negatively affect our ability to generate revenues and continue and expand our operations.
Our operations are subject to operating hazards inherent to our industry that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage.
The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage.
We are subject to physical risks arising from climate change, which may have a negative impact on our business and results of operations. Most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere and climate change may produce significant physical effects on weather conditions, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas products or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods, increases in our costs of operation, or reductions in the efficiency of our operations, impacts on our workforce, supply chain, or distribution chain, as well as potentially increased costs for or difficulty procuring consistent levels of insurance coverages in the aftermath of such effects. The physical effects of climate change may generally result in reduced availability of relevant insurance coverage on the market. Any of these effects could have an adverse effect on our assets and operations. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. Further, energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate changes. Increased energy use due to weather changes may require us to invest in additional equipment to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. The effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have
on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the net book value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows.
Multi-well pad drilling may result in volatility in our operating results. We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations.
Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other third-party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations.
Risks Related to Marketing and Transportation
Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, available manpower, pipeline safety issues, or other reasons. In certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. In addition, we or parties that we utilize might not be able to connect new wells that we complete to pipelines. Our failure to obtain access to processing and transportation facilities and services in a timely manner and on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Other factors that affect our ability to market our production include:
•the extent of domestic production and imports/exports of oil and natural gas;
•federal regulations authorizing exports of LNG, the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the timing of the first LNG exports from such facilities;
•the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Permian oil production to the Gulf Coast;
•the proximity of hydrocarbon production to pipelines and gathering infrastructure;
•the demand for oil and natural gas by utilities and other end users;
•the availability of alternative fuel sources;
•the effects of inclement weather, including the effects of chronic and acute climate events associated with the effects of global climate change; and
•state and federal regulation of oil, natural gas and NGL marketing and transportation.
We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity.
Risks Related to Our Reserves and Drilling Locations
Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This 2023 Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this 2023 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas.
You should not assume that any PV-10 of our estimated proved reserves contained in this 2023 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the PV-10 from our estimated proved reserves at December 31, 2023 on the 12-Month Average Realized Prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the discount factor used to calculate PV-10 may not be appropriate based on our cost of capital from time to time and the risks associated with our business and the oil and gas industry.
Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.
Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability and cost of drilling, completion and production services and equipment, lease expirations, regulatory approvals, and other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures and successful drilling operations, and a substantial amount of
our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 36% of our total estimated proved reserves as of December 31, 2023 were PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume significant capital expenditures will be made to develop such reserves. We cannot be certain that the estimated capital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; the availability of capital; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
Risks Related to Technology
We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, including technological advances in fuel economy and energy generation devices or other technological advances that could reduce demand for oil and natural gas, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, transportation and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks.
Risks Related to Our Indebtedness and Financial Position
Our business requires significant capital expenditures. 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. We intend to fund our capital expenditures through a combination of cash flows from operations and, if needed, borrowings from financial institutions, the sale of debt and equity securities, and asset divestitures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
If the ability to borrow under our Credit Facility or our cash flows from operations decrease, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. The failure to obtain additional financing on terms acceptable to us, or at all, could result in a curtailment of our development activities and could adversely affect our business, financial condition and results of operations.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2023, we had aggregate outstanding indebtedness of approximately $1.9 billion. Our amount of indebtedness could affect our operations in many ways, including:
•requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to fund our operations and other business activities as well as any potential returns to shareholders;
•limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•increasing our vulnerability to downturns and adverse developments in our business and the economy;
•limiting our ability to access the capital markets to raise capital on favorable terms, to borrow under our Credit Facility or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
•making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;
•making us vulnerable to increases in interest rates as the interest we pay on our indebtedness under our Credit Facility varies with prevailing interest rates;
•placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and
•making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations.
Restrictive covenants in the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indentures governing our senior notes contain restrictive covenants that limit our ability to, among other things: incur additional indebtedness including secured indebtedness; make investments; merge or consolidate with another entity; pay dividends or make certain other payments; hedge future production or interest rates; create liens that secure indebtedness; repurchase securities; sell assets; or engage in certain other transactions without the prior consent of the holders or lenders. As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility or the indentures governing our senior notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation.
Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount and timing of availability of capital we can access, as well as the terms of any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth.
Our borrowings under our Credit Facility expose us to interest rate risk. Our borrowings under our Credit Facility make us vulnerable to increases in interest rates as they bear interest at a rate elected by us that is based on the prime, SOFR or federal funds rate plus margins ranging from 0.75% to 2.75%, depending on the rate used and the amount of the loan outstanding in relation to the elected commitment.
The ability to borrow under our Credit Facility may be restricted to an amount below the amount of borrowings outstanding thereunder or to a lesser amount than what we expect due to future borrowing base reductions or restrictions contained in our other debt agreements. The borrowing base and elected commitment amount under our Credit Facility is currently $2.0 billion and $1.5 billion, respectively, and as of December 31, 2023, we had an aggregate principal balance of $365.0 million outstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations may cause us to not be able to access adequate funding under the Credit Facility. The lenders have sole discretion in determining the amount of the borrowing base and may cause our borrowing base to be redetermined to a materially lower amount, including to below our outstanding borrowings as of such redetermination. In addition, our other debt agreements contain restrictions on the incurrence of additional debt and liens which could limit our ability to borrow under our Credit Facility. If our borrowing base were to be reduced, or if covenants in our indentures restrict our ability to access funding under the Credit Facility, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts
immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Also, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. For example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition.
Any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness.
We cannot be certain that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control.
Risks Related to Acquisitions
We may be unable to integrate successfully the operations of acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. We have completed, and may in the future complete, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions or from any acquisitions we may complete in the future. In addition, failure to integrate future acquisitions successfully could adversely affect our financial condition and results of operations.
Our acquisitions may involve numerous risks, including those related to:
•operating a larger, more complex combined organization and adding operations;
•assimilating the assets, data, and operations of the acquired business, especially if the assets acquired are in a new geographic area;
•acquired oil and natural gas reserves not being of the anticipated magnitude or as developed as anticipated;
•the loss of significant key employees, including from the acquired business;
•the inability to obtain satisfactory title to the assets we acquire;
•a decrease in our liquidity if we use a portion of our available cash to finance acquisitions;
•a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
•the diversion of management’s attention from other business concerns, which could result in, among other things, performance shortfalls;
•the failure to realize expected profitability or growth;
•the failure to realize expected synergies and cost savings;
•coordinating geographically disparate organizations, systems, data, and facilities;
•coordinating or consolidating corporate and administrative functions;
•inconsistencies in standards controls, procedures and policies; and
•integrating relationships with customers, vendors and business partners.
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. The elimination of duplicative costs, as well as the
realization of other efficiencies related to the integration of our two companies, may not initially offset integration-related costs or achieve a net benefit in the near term or at all.
If we consummate any future acquisitions, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations, which in turn, could negatively impact our future results of operations.
We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We look to acquire additional acreage in Texas or other regions. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs, and potential environmental and other liabilities. Although we conduct a review that we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Risks Related to Our Hedging Program
Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil, natural gas, and NGL prices and to achieve more predictable cash flow. Our hedges at December 31, 2023 are in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain banking institutions. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil, natural gas, and NGLs. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing and prolonged declines in oil, natural gas, and NGL prices. To the extent that oil, natural gas, and NGL prices remain at current levels or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted.
Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. The total volumes which we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. 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.
Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
Legal and Regulatory Risks
We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Business and Properties — Regulations.” These laws and regulations may:
•require that we acquire permits before commencing drilling;
•regulate the spacing of wells and unitization and pooling of properties;
•impose limitations on production or operational, emissions control and other conditions on our activities;
•restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations;
•limit or prohibit drilling activities on protected areas, such as wetlands and wilderness;
•impose requirements to protect our employees and mitigate safety risks;
•impose penalties or other sanctions for accidental or unpermitted spills or releases from our operations; or
•require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or decommissioning abandoned wells and production facilities.
Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations.
The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently review, revise and supplement environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions monitoring and control, permitting, waste handling, storage, transport, remediation or disposal for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to public health and environmental matters. Even if regulatory burdens temporarily ease from time to time, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term.
Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict, joint and several liability for costs required to investigate, clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released (i.e., liability may be imposed regardless of whether the current owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred). We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other equipment emissions, GHGs and hydraulic fracturing. Under common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability in excess of our insurance coverage or we may be required to curtail or cease production from properties in the event of environmental incidents.
Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, from time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing. Legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA regulates hydraulic fracturing with fluids containing diesel fuel under the UIC program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has recently taken steps to strengthen its methane standards. The November 2021 rule intended 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). In addition, the November 2021 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 EPA. Additionally, in November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. 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.” In December 2023, the EPA announced a final rule, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. We may incur significant operational costs associated with compliance with these and any new regulations.
In some areas of Texas, including the Permian, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the RRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the RRC were to decline to issue permits for, or impose new limits on the volumes of, injection wells into the formations that we currently utilize, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. The RRC’s “well integrity rule” includes testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, the RRC rules require applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. Further, the RRC has authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for, and limit volumes for, disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general or hydraulic fracturing in particular.
The EPA has also issued the “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States” report, concluding that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited EPA’s ability to fully characterize the severity of impacts or calculate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle. This study could result in additional regulatory scrutiny that could restrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
Climate change legislation or regulations restricting emissions of GHG or requiring the reporting of GHG emissions or climate-related information could adversely impact our operating costs and demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules and proposed additional rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce or tax emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories or regional GHG cap-and-trade programs. For a description of some existing and proposed GHG rules and regulations, see “Business and Properties—Regulations.”
In 2021, as a party to the Paris Agreement, the U.S. announced a target for the U.S. to achieve a 50% to 52% reduction from 2005 levels in economy-wide GHG emissions by 2030. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Since its formal launch at the COP26, over 150 countries have joined the pledge. At the 27th conference of parties (“COP27”), President Biden announced the EPA’s supplemental proposed rule to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At COP28, member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement, among other things, are to accelerate efforts toward the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies, and take other measures that drive the transition away from fossil fuels in energy systems. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. In addition, a number of states have begun taking actions to control or reduce emissions of GHGs.
Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce or control GHG emissions or that require the reporting of GHG emissions or other climate-related information could result in increased operational complexity, production delays, increased potential for regulatory fines and penalties, and require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements, and to monitor and report on GHG emissions. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. International commitments, re-entry into the Paris Agreement, and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. At the federal level, although no comprehensive climate change legislation regulating the emission of GHGs or directly imposing a price on carbon has been implemented to date, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future, and energy legislation and other regulatory initiatives have been proposed that are relevant to GHG emissions issues. The $1 trillion legislative infrastructure package passed by Congress in November 2021 includes a number of climate-focused spending initiatives targeted at climate resilience, enhanced response and preparation for extreme weather events and clean energy and transportation investments. The IRA also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture and other programs directed at addressing climate change. For example, the IRA imposes a fee on GHG emissions from certain oil and gas facilities. The IRA amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program, which requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. To implement the program, the IRA requires revisions to GHG reporting regulations for petroleum and natural gas systems (Subpart W) by 2024. In July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas facilities, as required by the IRA. Among other things, the proposed rule would expand the emissions events that are subject to reporting requirements to include “other large release events” and apply reporting requirements to certain new sources and sectors. The rule is expected to be finalized in the spring of 2024 and become effective on January 1, 2025 in advance of the deadline for GHG reporting for 2024 (March 2025). The fee imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our and our customers’ business and results of operations. Additionally, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks and opportunities, including financial impacts, physical and transition risks, related governance and strategy and GHG emissions, for certain public companies, and a final rule is anticipated in April 2024. We cannot predict the costs of implementation or any potential adverse impacts resulting from the rulemaking. To the extent this rulemaking is finalized as proposed, we could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. Consequently, legislation and regulatory programs to reduce or require reporting relating to GHG emissions or other climate-related information could have an adverse effect on our business, financial condition and results of operations.
In addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas, and activism, litigation and initiatives aimed at limiting climate change and reducing air pollution could impact our business activities, operations and ability to access capital. For further discussion on transition risks related to climate change legislation and regulation, see “—Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for oil and natural gas” and “—Negative public perception of the oil and gas industry could have a material and adverse effect on us.”
Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market.
Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas, including the scope of relevant definitions or exemptions, remain pending. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also
imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. On January 24, 2020, U.S. banking regulators published a new approach for calculating the quantum of exposure of derivative contracts under their regulatory capital rules. This approach to measuring exposure is referred to as the standardized approach for counterparty credit risk or SA-CCR. It requires certain financial institutions to comply with significantly increased capital requirements for over-the-counter commodity derivatives. In addition, on September 15, 2020, the CFTC issued a final rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business. These two sets of regulations and the increased capital requirements they place on certain financial institutions may reduce the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to end-users like us. On January 14, 2021, the CFTC published a final rule on position limits for certain commodities futures and their economically equivalent swaps, though like several other rules there is a bona fide hedging exemption to the application of such rule. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.
Depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, the final rules may provide beneficial exemptions and/or may require us to comply with position limits and other limitations with respect to our financial derivative activities. The Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to cease their current business as hedge providers or spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. These potential changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.
If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
Tax Risks
Our ability to use our existing net operating loss (“NOL”) carryforwards or other tax attributes could be limited. A significant portion of our NOL carryforward balance was generated prior to the effective date of limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100% of taxable income in future years, but will start to expire in the 2035 taxable year. The remainder were generated following such effective date and, thus, generally allowable as a deduction against 80% of taxable income in future years (with an exception to this rule due to the enactment of the Coronavirus Aid, Relief, and Economic Security Act, whereby the utilization of NOLs was temporarily expanded for taxable years beginning before 2021). Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period. Future ownership changes and/or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.
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. We are subject to income taxes in the U. S., and our domestic tax assets and liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including the following: changes in the valuation of our deferred tax assets and liabilities; expected timing and amount of the release of any tax valuation allowances; tax effects of stock-based compensation; costs related to intercompany restructurings; changes in tax laws, regulations or interpretations thereof; or lower than anticipated future earnings in our taxing jurisdictions. In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.
Tax laws may change over time and such changes could adversely affect our business and financial condition. From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws,
including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) changes to a depletion allowance for oil and natural gas properties, (iii) the implementation of a carbon tax, (iv) an extension of the amortization period for certain geological and geophysical expenditures, (v) changes to tax rates, and (vi) the introduction of a minimum tax. While these specific changes were not included in recent legislation such as the IRA, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition.
Other Material Risks
Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Some of our competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development.
All of our producing properties are located in the Permian of West Texas, making us vulnerable to risks associated with operating in only one geographic region. As a result of this concentration, as compared to companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, severe weather, water shortages and other disruptions to climate patterns, delays or interruptions of production from wells in this area caused by governmental regulation, specific taxes or other regulatory legislation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays, interruptions or limitations could have a material adverse effect on our financial condition and results of operations. In addition, the effect of fluctuations on supply and demand may be more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions.
The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the RRC, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unproved properties and the value of our undeveloped acreage could decline in the future.
The loss of key personnel, or inability to employ a sufficient number of qualified personnel, could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees, and third-party consultants, many of whom are not subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. Also, we may experience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected.
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results.Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 13% of
our total revenues for the year ended December 31, 2023. 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.
Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action or proceeding asserting a claim for breach of a fiduciary duty owed by any current or former director, officer, or other employee of our company to us or our shareholders, (iii) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company arising pursuant to any provision of the Delaware General Corporate Law (the “DGCL”) or our charter or bylaws (as each may be amended from time to time), (iv) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company governed by the internal affairs doctrine, or (v) any action or proceeding as to which the DGCL confers jurisdiction on the Court of Chancery shall be the Court of Chancery or, if and only if the Court of Chancery lacks subject matter jurisdiction, any state court located within the State of Delaware or, if and only if such state courts lack subject matter jurisdiction, the federal district court for the District of Delaware, in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants.
Our exclusive forum provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce the forum selection provision with respect to such claims, and in any event, our shareholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder.
Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations.
Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our Board of Directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the DGCL. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock.
We do not currently pay cash dividends on our common stock. We do not currently pay dividends on our common stock and any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors at the time of such determination. Consequently, a shareholder’s only current opportunity to achieve a return on its investment in us will be by selling its shares of our common stock at a price greater than the shareholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will exceed the price at which a shareholder purchased its shares of our common stock.
General Risk Factors
Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition. Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2022, 2023 and thus far into 2024 (although it has begun to moderate) due to a substantial increase in money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services, and we are working closely with suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical suppliers which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient, and we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage
increases have increased our operating costs for the year ended December 31, 2023 compared to 2022, which was higher as compared to 2021. We also may face shortages of these commodities and labor, which may prevent us from executing our development plan. These supply chain constraints and inflationary pressures will likely continue to adversely impact our operating costs and, if we are unable to manage our supply chain, it may impact our ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could impact our ability to distribute available cash and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
We are taking actions to mitigate supply chain and inflationary pressures.
In addition, continued hostilities related to the Russian invasion of Ukraine, the conflict in Israel and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors and other factors, combined with volatile commodity prices, and declining business and consumer confidence may contribute to an economic slowdown and a recession. Recent growing concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our business, financial condition and results of operations.
We may be subject to the actions of activist shareholders. We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our Board of Directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected.
Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of our common stock or other securities may dilute a shareholder’s ownership in us. In the future, we may continue to issue securities to raise capital. We may also continue to acquire interests in other companies by using any combination of cash and our common stock or other securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share or have an adverse impact on the price of our common stock. In addition, secondary sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. Any such reduction in the market price of our common stock could impair our ability to raise additional capital through the sale of our securities.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 1C. Cybersecurity
The Board of Directors recognizes the critical importance of maintaining the trust and confidence of our suppliers, customers, other business partners and employees. The Board of Directors is actively involved in oversight of the Company’s risk management program, and cybersecurity represents an important component of the Company’s overall approach to enterprise risk management (“ERM”). The Company’s cybersecurity policies, standards, processes, and practices are fully integrated into the Company’s ERM program and are based on recognized frameworks established by the National Institute of Standards and Technology. In general, the Company seeks to address cybersecurity risks through a comprehensive, cross-functional approach that is focused on preserving the confidentiality, security, and availability of the information that the Company collects and stores by identifying, preventing, and mitigating any cybersecurity threats and effectively responding to cybersecurity incidents should they occur.
As of the date of this 2023 Annual Report on Form 10-K, the Company is not aware of any cybersecurity threats that have materially affected or are reasonably likely to materially affect the Company, including its business strategy, results of operations, or financial condition. However, as discussed under “Item 1A. Risk Factors,” specifically the risk titled “Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss,” the sophistication of cyberattacks continues to increase, and the preventative actions the Company takes to reduce the risk of cyber incidents and protect its systems and information may be insufficient. Accordingly, no matter how well the Company’s controls are designed or implemented, it will not be able to anticipate all security breaches, and it may not be able to implement effective preventive measures against such security breaches in a timely manner. In light of these risks, the Company has also developed cybersecurity detection and response protocols as described below to attempt to mitigate the impact in the event of a breach.
Risk Management and Strategy
As one of the critical elements of the Company’s overall ERM approach, the Company’s cybersecurity program is focused on the following key areas:
•Governance –The Board of Directors has responsibility for oversight of cybersecurity risk management and regularly interacts with the Company’s ERM function, the Company’s Chief Information Officer (“CIO”), and other members of management.
•Collaborative Approach – The Company has implemented a comprehensive, cross-functional approach to identifying, preventing, and mitigating cybersecurity threats and incidents, while also implementing controls and procedures that provide for the prompt escalation of certain cybersecurity incidents so that decisions regarding the public disclosure and reporting of such incidents can be made by management in a timely manner. The Company also collaborates with others in the industry and actively participates in a specific oil and gas threat intelligence group with weekly meetings and up-to-date threat notices.
•Technical Safeguards – The Company deploys technical safeguards that are designed to protect its information systems from cybersecurity threats, including firewalls, intrusion prevention and detection systems, anti-malware software and access controls, which are evaluated and improved through vulnerability assessments and cybersecurity threat intelligence. The Company performs an annual penetration test for identification of any vulnerabilities; in 2023, this test was performed by a third-party audit firm.
•Incident Response and Recovery Planning – The Company has established and maintains comprehensive incident response and recovery plans that address the Company’s response to a cybersecurity incident, and such plans are tested and evaluated on a regular basis, with the participation of executive officers and employees in our IT, legal and operations departments.
•Third-Party Risk Management – The Company maintains a comprehensive, risk-based approach to identifying and overseeing cybersecurity risks presented by third parties, including vendors, service providers and other external users of the Company’s systems, as well as the systems of third parties that could adversely impact our business. In 2023, the Company completed a comprehensive review of certain third-party providers that have access to the Company’s data, such as banks, and SaaS vendors, and implemented a third-party risk management service which (i) allows for comprehensive vendor assessments with risk scoring, (ii) informs risk decisions with increased visibility and cybersecurity ratings, (iii) continuously monitors for vendor breaches and other significant events via various data feeds, and (iv) allows for collaboration with vendors to assess and remediate risk.
•Education and Awareness – The Company provides regular, mandatory training for personnel regarding cybersecurity threats as a means to equip the Company’s personnel with effective tools to address cybersecurity threats, and to communicate the Company’s evolving information security policies, standards, processes, and practices. In addition to our annual required training, the Company promotes awareness through regular phishing simulations and educational opportunities, including an FBI-led training in 2023.
The Company engages in the periodic assessment and testing of the Company’s policies, standards, processes, and practices that are designed to address cybersecurity threats and incidents. These efforts include a wide range of activities, including audits, assessments, tabletop exercises, threat modeling, vulnerability management, and other exercises focused on evaluating the effectiveness of our
cybersecurity measures and planning. The Company regularly engages third parties to perform assessments on our cybersecurity measures, including information security maturity and risk assessments, audits and independent reviews of our information security control environment and operating effectiveness. The results of such assessments, audits and reviews are reported to the Board of Directors, and the Company adjusts its cybersecurity policies, standards, processes, and practices as necessary based on the information provided by these assessments, audits, and reviews.
Governance
The Board of Directors oversees the Company’s ERM program, including the management of risks arising from cybersecurity threats. On an annual basis, the Board of Directors discusses the Company’s approach to cybersecurity risk management with the CIO. The Board of Directors also receives regular presentations and reports on cybersecurity risks, which address a wide range of topics including recent developments, evolving standards, vulnerability assessments, third-party and independent reviews, the threat environment, technological trends and information security considerations arising with respect to the Company’s peers and third parties.
The CIO, in coordination with the Company’s executive team, works collaboratively across the Company to implement a program designed to protect the Company’s information systems from cybersecurity threats and to promptly respond to any cybersecurity incidents in accordance with the Company’s incident response and recovery plans. To facilitate the success of the Company’s cybersecurity risk management program, multidisciplinary teams throughout the Company are deployed to address cybersecurity threats and to respond to cybersecurity incidents. Through ongoing communications with these teams, the CIO oversees the monitoring, prevention, detection, mitigation, and remediation of cybersecurity threats and incidents, and reports such threats and incidents to the Board of Directors when appropriate. The CIO is supported by, among others, a Cybersecurity Architect who is a Certified Information Systems Security Professional (CISSP) and an Application Director who is Certified in Risk and Information Systems Control.
Angelina C. Day has served as the Company’s Vice President and CIO since July 2022. In this role, she is responsible for all aspects of information technology, including cybersecurity. Prior to joining the Company, Ms. Day was IT Director at EP Energy Corporation, an independent E&P company, from May 2012 until March 2022, where she oversaw the information technology and security functions. Prior to EP Energy, Ms. Day held various roles with increasing responsibility in technology and leadership at El Paso Corporation. Ms. Day has over 20 years of energy, technology and risk management experience. She is also a member of the Houston CIO Community (Evanta) Governing Body, an organization that fosters collaboration and knowledge sharing across the Houston CIO community. Ms. Day holds a B.B.A. in Computer Information Systems from the University of Houston Downtown.
Supporting our CIO in assessing and managing the Company’s material risks from cybersecurity threats are the Company’s COO, CFO, and General Counsel, each of whom have over 20 years of experience managing risks at the Company and at similar companies, including risks arising from cybersecurity threats.
ITEM 3. Legal Proceedings
We are a party in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations.
As previously reported in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, in January 2022, we received a Notice of Violation from the United States Environmental Protection Agency (the “EPA”) related to the Clean Air Act. As previously reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, to resolve the alleged violations, on June 9, 2023, we agreed to a Consent Agreement and Final Order (“CAFO”) with the EPA, which became effective June 20, 2023. The CAFO assessed a civil penalty in the amount of approximately $1.3 million and requires us to perform certain actions over the course of the next year, including facility reviews, additional monitoring, and the submission of a final letter report in June 2024. We have begun implementing the requirements of the CAFO. We believe that the settlement was in the best interests of the Company and its shareholders to avoid the uncertainty, risk, expense, and distraction of protracted litigation.
ITEM 4. Mine Safety Disclosures
Not applicable.
PART II.
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock trades on the NYSE under the symbol “CPE.”
Holders
As of February 16, 2024 the Company had approximately 1,002 common stockholders of record.
Issuer Repurchases of Equity Securities
Our common stock repurchase activity for the year ended December 31, 2023 was as follows:
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Period | | Total Number of Shares Purchased | | Average Price Paid Per Share(1) | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(2) |
| | | | | | | | $300,000,000 | |
July 1 - July 31, 2023 | | — | | | $— | | | — | | | $300,000,000 | |
August 1 - August 31, 2023 | | 81,574 | | | $36.22 | | | 81,574 | | | $297,045,600 | |
September 1 - September 30, 2023 | | 305,145 | | | $39.38 | | | 305,145 | | | $285,027,986 | |
October 1 - October 31, 2023 | | — | | | $— | | | — | | | $285,027,986 | |
November 1 - November 30, 2023 | | 942,536 | | | $32.89 | | | 942,536 | | | $254,028,104 | |
December 1 - December 31, 2023 | | 322,397 | | | $29.47 | | | 322,397 | | | $244,528,169 | |
Total | | 1,651,652 | | | $33.59 | | | 1,651,652 | | | |
(1) The average price paid per share excludes any fees, commissions and expenses paid to repurchase stock.
(2) On May 3, 2023, we announced that on May 2, 2023, the Board of Directors approved the Share Repurchase Program pursuant to which we are authorized to repurchase up to $300.0 million of our outstanding common stock through the second quarter of 2025. Repurchases under the Share Repurchase Program may be made, from time to time, in amounts and at prices we deem appropriate and will be subject to a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The Share Repurchase Program will expire on June 30, 2025 but may be suspended, modified or discontinued by the Board of Directors at any time without prior notice.
We are restricted from making share repurchases during the period between the execution of the Merger Agreement and the Effective Time (or, if applicable, the termination date) without APA’s approval pursuant to covenants of Callon included within the Merger Agreement.
Dividends
We have not paid any cash dividends on our common stock to date. However, we continuously monitor many internal and external factors as we consider when, or if, we should implement shareholder return programs. These factors include our current and projected financial performance; our debt metrics, covenants and absolute amounts borrowed; commodity price outlooks; cash requirements; corporate and strategic plans; and macroeconomic indicators. In addition, the Merger Agreement contains certain restrictions that limit our ability to pay dividends. Ultimately, the timing, amount and form of shareholder return programs, if any, is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations.
ITEM 6. Reserved
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following management’s discussion and analysis describes the principal factors affecting our results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing.
A discussion and analysis of the Company’s financial condition and results of operations for the year ended December 31, 2021 can be found in “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2022, which was filed with the SEC on February 23, 2023.
Financial information for all prior periods has been recast to reflect the retrospective application of the successful efforts method of accounting, as discussed under “Note 2 — Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in this Form 10-K.
General
We are an independent oil and natural gas company focused on the acquisition, exploration and sustainable development of high-quality assets in the Permian Basin in West Texas. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple layers of the Wolfcamp and Bone Springs formations and the Spraberry shale. We have assembled a decade-plus inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through the acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps.
Merger Agreement
On January 3, 2024, we entered into the Merger Agreement, which provides that, among other things and subject to the terms and conditions therein, (i) Merger Sub will be merged with and into Callon, with Callon surviving and continuing as the surviving corporation in the Merger and becoming a subsidiary of APA, and (ii) at the Effective Time, each outstanding share of common stock of Callon (other than Excluded Shares (as defined in the Merger Agreement)) will be converted into the right to receive, without interest, 1.0425 shares of common stock of APA, with cash in lieu of fractional shares.
The completion of the Merger is subject to satisfaction or waiver of certain customary mutual closing conditions, and the Merger Agreement contains certain termination rights for each of APA and Callon. In certain circumstances, a termination fee would be payable by the terminating party.
If the Merger is consummated, our common stock will be delisted from the NYSE and deregistered under the Securities Exchange Act of 1934, and Callon will cease to be a publicly traded company.
For additional discussion of the Merger, please see “Part I. Items 1 and 2. Business and Properties — Merger Agreement.”
Financial and Operational Highlights
For discussion of our significant financial and operational highlights for the year ended December 31, 2023, please see “Part I. Items 1 and 2. Business and Properties — Major Developments in 2023”.
Results of Operations
Production
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| | Years Ended December 31, |
| | 2023 | | 2022 | | $ Change | | % Change |
Total production | | | | | | | | |
Oil (MBbls) | | | | | | | | |
Permian | | 19,658 | | 18,041 | | 1,617 | | | 9 | % |
Eagle Ford | | 2,233 | | 5,598 | | (3,365) | | | (60 | %) |
Total oil | | 21,891 | | 23,639 | | (1,748) | | | (7 | %) |
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Natural gas (MMcf) | | | | | | | | |
Permian | | 43,437 | | 35,519 | | 7,918 | | | 22 | % |
Eagle Ford | | 2,672 | | 6,108 | | (3,436) | | | (56 | %) |
Total natural gas | | 46,109 | | 41,627 | | 4,482 | | | 11 | % |
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NGLs (MBbls) | | | | | | | | |
Permian | | 7,554 | | 6,424 | | 1,130 | | | 18 | % |
Eagle Ford | | 457 | | 1,052 | | (595) | | | (57 | %) |
Total NGLs | | 8,011 | | 7,476 | | 535 | | | 7 | % |
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Total production (MBoe) | | | | | | | | |
Permian | | 34,452 | | 30,385 | | 4,067 | | | 13 | % |
Eagle Ford | | 3,135 | | 7,668 | | (4,533) | | | (59 | %) |
Total barrels of oil equivalent | | 37,587 | | 38,053 | | (466) | | | (1 | %) |
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Total daily production (Boe/d) | | 102,977 | | 104,254 | | (1,277) | | | (1 | %) |
Percent of total daily production | | | | | | | | |
Oil | | 58 | % | | 62 | % | | | | (4 | %) |
Natural gas | | 21 | % | | 18 | % | | | | 3 | % |
NGLs | | 21 | % | | 20 | % | | | | 1 | % |
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The decrease in production for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to the Eagle Ford Divestiture, oil volumes that were negatively impacted by weather-related power and midstream disruptions in the third quarter, and normal production decline, partially offset by the Percussion Acquisition.
Pricing
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| | Years Ended December 31, |
| | 2023 | | 2022 | | $ Change | | % Change |
Benchmark prices (1) | | | | | | | | |
WTI (per Bbl) | | $77.64 | | $94.26 | | ($16.62) | | | (18 | %) |
Henry Hub (per Mcf) | | 2.67 | | 6.54 | | (3.87) | | | (59 | %) |
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Average realized sales price (excluding impact of derivative settlements) | | | | | | |
Oil (per Bbl) | | | | | | | | |
Permian | | $77.81 | | $95.58 | | ($17.77) | | | (19 | %) |
Eagle Ford | | 75.01 | | 96.15 | | (21.14) | | | (22 | %) |
Total oil | | 77.52 | | 95.72 | | (18.20) | | | (19 | %) |
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Natural gas (per Mcf) | | | | | | | | |
Permian | | 1.74 | | 5.44 | | (3.70) | | | (68 | %) |
Eagle Ford | | 2.64 | | 6.47 | | (3.83) | | | (59 | %) |
Total natural gas | | 1.79 | | 5.59 | | (3.80) | | | (68 | %) |
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NGL (per Bbl) | | | | | | | | |
Permian | | 21.86 | | 35.18 | | (13.32) | | | (38 | %) |
Eagle Ford | | 20.26 | | 32.80 | | (12.54) | | | (38 | %) |
Total NGL | | 21.77 | | 34.84 | | (13.07) | | | (38 | %) |
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Total average realized sales price (per Boe) | | | | | | | | |
Permian | | 51.38 | | 70.55 | | (19.17) | | | (27 | %) |
Eagle Ford | | 58.63 | | 79.84 | | (21.21) | | | (27 | %) |
Total average realized sales price | | $51.98 | | $72.42 | | ($20.44) | | | (28 | %) |
(1) Reflects calendar average daily spot market prices.
Revenues
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| | Oil | | Natural Gas | | NGLs | | Total |
| | (In thousands) |
Revenues for the year ended December 31, 2022 (1) | | $2,262,647 | | $232,681 | | $260,472 | | $2,755,800 | |
Volume increase (decrease) | | (167,313) | | 25,053 | | 18,640 | | (123,620) | |
Price decrease | | (398,308) | | (175,266) | | (104,705) | | (678,279) | |
Net decrease | | (565,621) | | (150,213) | | (86,065) | | (801,899) | |
Revenues for the year ended December 31, 2023 (1) | | $1,697,026 | | $82,468 | | $174,407 | | $1,953,901 | |
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Percent of total revenues | | 87 | % | | 4 | % | | 9 | % | | |
(1) Excludes sales of oil and gas purchased from third parties and sold to our customers.
The decrease in revenues for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to a 28% decrease in the average realized sales price, which decreased to $51.98 per Boe from $72.42 per Boe, as shown above.
Operating Expenses
Lease Operating Expenses
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| | Years Ended December 31, |
| | 2023 | | 2022 | | Total Change | | Boe Change |
| | Amount | | Per Boe | | Amount | | Per Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
Permian | | $270,836 | | | $7.86 | | | $218,040 | | | $7.18 | | | $52,796 | | | 24 | % | | $0.68 | | | 9 | % |
Eagle Ford | | 32,527 | | | 10.38 | | | 72,446 | | | 9.45 | | | (39,919) | | | (55 | %) | | 0.93 | | | 10 | % |
Lease operating | | $303,363 | | | $8.07 | | | $290,486 | | | $7.63 | | | $12,877 | | | 4 | % | | $0.44 | | | 6 | % |
The increase in lease operating expenses, as well as lease operating expenses per Boe, for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to increases in certain operating expenses such as saltwater disposal and fuel and power.
Production and Ad Valorem Taxes
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| | Years Ended December 31, |
| | 2023 | | 2022 | | Total Change | | Boe Change |
| | Amount | | Per Boe | | Amount | | Per Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
Permian | | $101,035 | | | $2.93 | | | $122,957 | | | $4.05 | | | ($21,922) | | | (18 | %) | | ($1.12) | | | (28 | %) |
Eagle Ford | | 12,477 | | | 3.98 | | | 36,963 | | | 4.82 | | | (24,486) | | | (66 | %) | | (0.84) | | | (17 | %) |
Production and ad valorem taxes | | $113,512 | | | $3.02 | | | $159,920 | | | $4.20 | | | ($46,408) | | | (29 | %) | | ($1.18) | | | (28 | %) |
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Percent of total revenues | | 5.8% | | | | 5.8% | | | | | | —% | | | | |
The decrease in production and ad valorem taxes for the year ended December 31, 2023 compared to the same period of 2022 was primarily related to a 29% decrease in total revenues which decreased production taxes, partially offset by an increase in ad valorem taxes due to higher expected property tax valuations as a result of higher commodity prices during 2022 compared to 2021. The increase in production and ad valorem taxes as a percentage of total revenues for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to an increase in ad valorem taxes during the year ended December 31, 2023, as discussed above, with a decrease in total revenues during the year ended December 31, 2023.
Gathering, Transportation and Processing Expenses
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| | Years Ended December 31, |
| | 2023 | | 2022 | | Total Change | | Boe Change |
| | Amount | | Per Boe | | Amount | | Per Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
Permian | | $101,975 | | | $2.96 | | | $82,459 | | | $2.71 | | | $19,516 | | | 24 | % | | $0.25 | | | 9 | % |
Eagle Ford | | 6,246 | | | 1.99 | | | 14,443 | | | 1.88 | | | (8,197) | | | (57 | %) | | 0.11 | | | 6 | % |
Gathering, transportation and processing | | $108,221 | | | $2.88 | | | $96,902 | | | $2.55 | | | $11,319 | | | 12 | % | | $0.33 | | | 13 | % |
The increase in gathering, transportation and processing expenses, as well as the increase in gathering, transportation and processing expenses per Boe, for the year ended December 31, 2023 compared to the same period of 2022 was primarily related to new gathering agreements put into place during the year ended December 31, 2023.
Exploration Expenses
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| | Years Ended December 31, |
| | 2023 | | 2022 | | Total Change | | Boe Change |
| | Amount | | Per Boe | | Amount | | Per Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
Exploration | | $9,143 | | | $0.24 | | | $9,703 | | | $0.25 | | | ($560) | | | (6 | %) | | ($0.01) | | | (4 | %) |
For the year ended December 31, 2023 compared to the same period in 2022, exploration expense, as well as exploration expense per Boe, decreased by an immaterial amount.
Depreciation, Depletion and Amortization (“DD&A”). The following table sets forth the components of our DD&A for the periods indicated:
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| | Years Ended December 31, |
| | 2023 | | 2022 | | Total Change | | Boe Change |
| | Amount | | Per Boe | | Amount | | Per Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
DD&A of proved oil and gas properties | | $527,966 | | | $14.05 | | | $485,585 | | | $12.76 | | | $42,381 | | | 9 | % | | $1.29 | | | 10 | % |
Depreciation of other property and equipment | | 1,461 | | | 0.04 | | | 1,685 | | | 0.04 | | | (224) | | | (13 | %) | | — | | | — | % |
Amortization of other assets | | 2,341 | | | 0.06 | | | 2,962 | | | 0.08 | | | (621) | | | (21 | %) | | (0.02) | | | (25 | %) |
Accretion of asset retirement obligations | | 3,893 | | | 0.10 | | | 3,997 | | | 0.11 | | | (104) | | | (3 | %) | | (0.01) | | | (9 | %) |
DD&A | | $535,661 | | | $14.25 | | | $494,229 | | | $12.99 | | | $41,432 | | | 8 | % | | $1.26 | | | 10 | % |
The increase in DD&A and DD&A per Boe for the year ended December 31, 2023 compared to the same period of 2022 was primarily attributable to higher proved oil and gas property balances as a result of the capital expenditures throughout 2023, partially offset by the cessation of depletion on the assets associated with the Eagle Ford Divestiture as a result of being classified as assets held for sale during the second quarter of 2023.
See “Note 5 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional details regarding the Eagle Ford Divestiture.
General and Administrative (“G&A”)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022 | | Total Change | | Boe Change |
| | Amount | | Per Boe | | Amount | | Per Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
General and administrative | | $115,344 | | | $3.07 | | | $97,996 | | | $2.58 | | | $17,348 | | | 18 | % | | $0.49 | | | 19 | % |
The increase in G&A for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to an increase in employee-related costs as well as an increase in stock compensation expense between the two periods.
Impairment of Oil and Gas Properties. We recognized an impairment of proved oil and gas properties in the second quarter of 2023 of $406.9 million as the fair value less cost to sell was less than the carrying amount of the net assets associated with the Eagle Ford Divestiture that were classified as assets held for sale. We recognized an impairment of unproved oil and gas properties in the fourth quarter of 2022 of $2.2 million due to certain leases approaching the end of their lease terms with no future plans to develop the acreage.
Other Income and Expenses
Interest Expense. The following table sets forth the components of our interest expense for the periods indicated:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022 | | Change |
| | (In thousands) |
Interest expense on Senior Notes | | $126,575 | | | $124,694 | | | $1,881 | |
Interest expense on second lien notes | | — | | | 13,825 | | | (13,825) | |
Interest expense on Credit Facility | | 41,907 | | | 36,860 | | | 5,047 | |
Amortization of debt issuance costs, premiums and discounts | | 10,790 | | | 12,333 | | | (1,543) | |
Other interest expense | | 33 | | | 80 | | | (47) | |
Interest expense | | $179,305 | | | $187,792 | | | ($8,487) | |
Interest expense for the year ended December 31, 2023 was $179.3 million, a decrease as compared to the same period of 2022 as a result of the redemption of our 9.0% second lien notes in June 2022 and our 8.25% Senior Notes, partially offset by an increase in interest expense due to the issuance of our 7.5% Senior Notes due 2030 in June 2022 as well as increases in interest rates on our outstanding borrowings under the Credit Facility.
See “Note 8 - Borrowings” of the Notes to our Consolidated Financial Statements for additional details.
(Gain) Losson Derivative Contracts. The net (gain) loss on derivative contracts for the periods indicated includes the following:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022 | | Change |
| | (In thousands) |
(Gain) loss on oil derivatives | | ($22,371) | | | $287,379 | | | ($309,750) | |
(Gain) loss on natural gas derivatives | | (4,990) | | | 38,803 | | | (43,793) | |
Loss on NGL derivatives | | 2,663 | | | 4,771 | | | (2,108) | |
Loss on contingent consideration arrangements | | 5,800 | | | — | | | 5,800 | |
| | | | | | |
(Gain) loss on derivative contracts | | ($18,898) | | | $330,953 | | | ($349,851) | |
See “Note 9 – Derivative Instruments and Hedging Activities” and “Note 10 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information.
(Gain) Losson Extinguishment of Debt. For the year ended December 31, 2023, we recognized a gain on extinguishment of debt of $1.2 million as a result of the redemption of the 8.25% Senior Notes.
For the year ended December 31, 2022, we recognized a loss on extinguishment of debt of $45.7 million as a result of the redemptions of the 6.125% senior notes and second lien notes and the termination of our Prior Credit Facility.
See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.
Sales and Cost of Purchased Oil and Gas. We purchase oil and gas from third parties in order to fulfill portions of our pipeline commitments. For the years ended December 31, 2023 and 2022, we recorded sales of purchased oil and gas of $389.1 million and $475.2 million, respectively, and cost of purchased oil and gas of $399.2 million and $478.4 million, respectively, related to commodities purchased from third parties and sold to our customers.
Income Tax Expense. We recorded income tax benefit of $189.8 million for the year ended December 31, 2023 compared to income tax expense of $13.8 million for the same period of 2022. The changes from the statutory income tax rate for the year ended December 31, 2023 is a result of releasing the valuation allowance that was in place against our net deferred tax assets. See “Note 13 – Income Taxes” of the Notes to our Consolidated Financial Statements for further discussion.
Liquidity and Capital Resources
Pricing Outlook. Oil prices continue to remain volatile as the daily NYMEX benchmark price for oil ranged between approximately $67 and $94 per barrel during 2023. Overall for 2023, the average price of $78 per barrel remained significantly below the average of $95 per barrel for 2022. Additionally, during 2023, the daily NYMEX benchmark price for natural gas decreased approximately 59% from the average for 2022 to $2.67 per Mcf. We expect to continue to see volatility in oil prices, as well as natural gas and NGL prices.
Capital Efficiency Outlook. We recently transitioned to a business unit design in our operations group to improve focus on capital efficiency and capital allocation. We have identified structural drilling efficiency gains from well design changes and expect to continue to identify incremental structural efficiency gains as we move into 2024. The identified improvements are expected to reduce our 2024 average total well costs, including facilities, by at least 15%.
Sources and Uses of Cash. Our primary uses of capital are for the exploration and development of our oil and natural gas properties. Because we are the operator of a high percentage of our properties, we can control the well design and the development pace associated with our capital expenditures. We plan our capital expenditure program to achieve disciplined reinvestment rates to drive capital efficiency through an enhanced multi-zone, scaled development program.
We believe that existing cash and cash equivalents, cash flows from operations and available borrowings under our credit facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter. 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.
Historically, our primary sources of capital have been cash flows from operations, borrowings under our credit facility, proceeds from the issuance of debt securities and public equity offerings, and asset dispositions. Up to the completion of the Merger, our liquidity requirements will remain funded by our cash flow from operations, borrowings under our credit facility and certain other capital activities allowed under the Merger Agreement. In particular, we are subject to restrictions under the Merger Agreement on assuming additional debt, issuing additional equity or debt, repurchasing equity, making certain capital expenditures, and entering into certain acquisition, disposition and leasing transactions, among other restrictions.
Overview of Cash Flow Activities. For the year ended December 31, 2023, cash and cash equivalents decreased $0.1 million to $3.3 million compared to $3.4 million at December 31, 2022.
| | | | | | | | | | | |
| Years Ended December 31, |
| 2023 | | 2022 |
| (In thousands) |
Net cash provided by operating activities | $1,092,529 | | | $1,355,673 | |
Net cash used in investing activities | (707,311) | | | (853,183) | |
Net cash used in financing activities | (385,288) | | | (508,977) | |
Net change in cash and cash equivalents | ($70) | | | ($6,487) | |
Operating Activities. Net cash provided by operating activities was $1.1 billion and $1.4 billion for the years ended December 31, 2023 and 2022, respectively. The decrease in net cash provided by operating activities was primarily attributable to the following:
•A decrease in revenue primarily driven by a 28% decrease in total average realized sales price; partially offset by
•A decrease in the cash paid for commodity derivative settlements.
Investing Activities. Net cash used in investing activities was $707.3 million and $853.2 million for the years ended December 31, 2023 and 2022, respectively. The change in net cash used in investing activities was primarily attributable to proceeds from the Eagle Ford Divestiture and a decrease in cash paid for the settlement of contingent consideration agreements, partially offset by cash paid for the Percussion Acquisition and an increase in operational capital expenditures.
Financing Activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility, term debt and equity offerings. For the year ended December 31, 2023, net cash used in financing activities was $385.3 million compared to $509.0 million during 2022. The change was primarily attributable to the redemption of the 8.25% Senior Notes and the initiation of our Share Repurchase Program during 2023 compared to the redemptions of the 6.125% Senior Notes and Second Lien Notes, partially offset by the issuance of the 7.5% Senior Notes in 2022.
Credit Facility. As of December 31, 2023, our Credit Facility had a maximum credit amount of $5.0 billion, a borrowing base of $2.0 billion and an elected commitment amount of $1.5 billion, with borrowings outstanding of $365.0 million at a weighted-average interest rate of 7.54%, and letters of credit outstanding of $21.4 million.
Redemption of 8.25% Senior Notes. On August 2, 2023, we redeemed all $187.2 million of our outstanding 8.25% Senior Notes using borrowings under our Credit Facility. See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information on our long-term debt.
Income Taxes. Due to the issuance of common stock pursuant to the acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”), the Company incurred a cumulative ownership change, and as such, the Company’s NOLs prior to the acquisition are subject to a combined annual limitation under Internal Revenue Code (the “IRC”) Section 382 in the amount of $32.2 million, which is comprised of $15.7 million of Carrizo’s NOLs and $16.5 million of Callon’s NOLs. At December 31, 2023, the Company had approximately $2.0 billion of NOLs, some of which i) are subject to annual limitation under Section 382, ii) are subject to the IRC’s 80% taxable income limitation rule, or iii) expire between 2034 and 2037, as summarized in the table below.
| | | | | | | | | | | | | | | | | | | | |
Subject to Annual Limitation Under Section 382 | | Subject to IRC’s 80% Taxable Income Limitation | | Years of Expiration | | NOL Balance |
| | | | | | (In millions) |
Yes | | Yes | | N/A | | $710.0 | |
No | | Yes | | N/A | | 841.5 | |
Yes | | No | | 2034 to 2037 | | 399.3 | |
| | | | | | $1,950.8 | |
The Company also has a net interest expense carryforward of $401.0 million under Section 163(j) of the Code, subject to indefinite carryforward.
Material Cash Requirements. As of December 31, 2023, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements and other purchase obligations as well as estimates of future asset retirement obligations. See “Note 15 – Asset Retirement Obligations” and “Note 18 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional details.
We estimate that the combination of our sources of capital, as discussed above, will continue to be adequate to fund our short- and long-term contractual obligations.
Critical Accounting Estimates
For discussion regarding our significant accounting policies, see “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements. We have outlined below the policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.
Recast Financial Information for Change in Accounting Principle
In the first quarter of 2023, we voluntarily changed our method of accounting for our oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Accordingly, the financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ASC 932
“Extractive Activities — Oil and Gas.” See “Note 2 — Summary of Significant Accounting Policies” and “Note 3 — Change in Accounting Principle” of the Notes to our Consolidated Financial Statements for additional discussion.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities and revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of proved oil and natural gas property costs, the present value of estimated future net revenues, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates.
Oil and Natural Gas Properties
Oil and natural gas properties are accounted for using the successful efforts method of accounting under which drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, associated with development wells are capitalized to proved oil and gas properties and are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Acquired proved properties and proved leasehold acquisition costs are depleted on the same asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. The calculation of depletion expense takes into consideration estimated asset retirement costs, net of estimated salvage values. Proved oil and gas properties are assessed for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the recoverability of the net book value of such property.
The process of estimating proved oil and gas reserves requires that our independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. Additionally, operating costs, production and ad valorem taxes, and future development costs are estimated based on current costs. A significant change to our estimated volumes of oil and gas reserves as well as changes to the estimates of prices and costs could have an impact on the depletion rate calculation as well as result in an impairment of oil and gas properties.
Impairment of Oil and Natural Gas Properties
We assess our proved oil and gas properties for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the recoverability of the net book value of such property. We estimate the expected future net cash flows of our proved oil and gas properties and compare these undiscounted cash flows to the net book value of the proved oil and gas properties to determine if the net book value is recoverable. If the net book value exceeds the estimated undiscounted future net cash flows, we will recognize an impairment to reduce the net book value of the proved oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future development costs and operating costs, and discount rates, which are based on a weighted average cost of capital. Fair value estimates are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment is measured. See “Note 5 — Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for details of the impairment of $406.9 million recorded in the second quarter of 2023 associated with the assets held for sale classification resulting from the agreement to sell all of our interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. We recognized an impairment of unproved oil and gas properties in the fourth quarter of 2022 of $2.2 million due to certain leases approaching the end of their lease terms with no future plans to develop the acreage.
We evaluate significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data.
Derivative Instruments
We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not use these instruments for speculative or trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional
information regarding our derivatives instruments and their fair values, see “Note 9 – Derivative Instruments and Hedging Activities” and “Note 10 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements.
Our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments as a result of the volatility of oil and gas prices. See “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” for the impact on the fair values of our derivative instruments assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2023.
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards.
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that our net deferred tax assets will be utilized prior to their expiration. As previously disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, beginning in the second quarter of 2020 and through the fourth quarter of 2022, we maintained a valuation allowance against our net deferred tax assets. Considering all available evidence (both positive and negative), we concluded that it is more likely than not that the deferred tax assets would be realized and released the valuation allowance in the first quarter of 2023. This release resulted in deferred income tax benefit of $187.3 million for the year ended December 31, 2023. See “Note 13 – Income Taxes” of the Notes to our Consolidated Financial Statements for additional discussion.
Recently Adopted and Recently Issued Accounting Pronouncements
See “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board.
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments.
Commodity Price Risk
Our revenues are derived from the sale of our oil, natural gas, and NGL production. The prices for oil, natural gas, and NGLs remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, government actions, economic conditions, and weather conditions.
From time to time, we enter into derivative financial instruments to manage oil, natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices.
We may utilize fixed price swaps, which reduce our exposure to decreases in commodity prices, but limit the benefit we might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous or subsequent sale or purchase of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales.
We also may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to us, and if the price rises above the ceiling, the counterparty receives the difference from us. Additionally, we may sell put options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), our net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.
Additionally, we may enter into basis swap contracts which fix the basis differentials between the index price at which the Company sells its production and the relevant NYMEX benchmark price used in swap or collar contracts.
We may purchase put options, which reduce our exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to us.
We enter into these various agreements from time to time to reduce the effects of volatile oil, natural gas and NGL prices and do not enter into derivative transactions for speculative or trading purposes. Presently, none of our derivative positions are designated as hedges for accounting purposes.
The following table sets forth the fair values of our commodity derivative instruments as of December 31, 2023 as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2023 |
| | Oil | | Natural Gas | | NGLs | | Total |
| | (In thousands) |
Fair value asset (liability) as of December 31, 2023 (1) | | $4,237 | | | ($414) | | | ($426) | | | $3,397 | |
| | | | | | | | |
Impact of a 10% increase in forward commodity prices | | ($14,830) | | | ($1,022) | | | ($777) | | | ($16,629) | |
Impact of a 10% decrease in forward commodity prices | | $21,040 | | | $263 | | | ($75) | | | $21,228 | |
(1)Spot prices for oil and natural gas were $71.71 and $2.51, respectively, as of December 31, 2023.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2023, we had $365.0 million outstanding under the Credit Facility with a weighted average interest rate of 7.54%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual interest expense of approximately $3.7 million, based on the balance outstanding as of December 31, 2023. See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for more information on our Credit Facility.
Counterparty and Customer Credit Risk
Our principal exposures to credit risk are through receivables from the sale of our oil, natural gas and NGL production, joint interest receivables and receivables resulting from derivative financial contracts.
For the year ended December 31, 2023, four purchasers each accounted for more than 10% of our oil, natural gas, and NGL revenues. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require our customers to provide financial security. We are generally paid by our purchasers within 30 to 90 days after the month of production and currently do not believe that we have a risk of not collecting.
Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. As of December 31, 2023, our joint interest receivables were approximately $34.6 million and we had no material past due balances.
See “Note 9 – Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for discussion of counterparty credit risk associated with our commodity derivative arrangements.
ITEM 8. Financial Statements and Supplementary Data
| | | | | |
| Page |
Reports of Independent Registered Public Accounting Firm (PCAOB ID Number 248) | |
Consolidated Balance Sheets as of December 31, 2023 and 2022 | |
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021 | |
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021 | |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021 | |
Notes to Consolidated Financial Statements | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Callon Petroleum Company
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2023, and our report dated February 26, 2024expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Houston, Texas
February 26, 2024
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Callon Petroleum Company
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 26, 2024 expressed an unqualified opinion.
Change in accounting principle
As discussed in Note 3 to the consolidated financial statements, the Company changed the method in which it accounts for oil and natural gas exploration and development activities from the full cost method to the successful efforts method in 2023. This matter is also discussed below as a critical audit matter.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
The development of estimated proved reserves used in the calculation of depletion, depreciation and amortization expense (DD&A) under the successful efforts method of accounting and the valuation of crude oil and natural gas properties in the 2023 Percussion Acquisition (herein referred to as “the crude oil and natural gas reserves”)
As described further in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the successful efforts method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record DD&A expense. Additionally, as described in Note 4 to the financial statements, the Company acquired significant oil and natural gas properties during the year through the Percussion Acquisition. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of DD&A expense. For acquired reserves, management also utilizes an estimated fair value pricing model in determining the corresponding value of proved reserves.
We identified the estimation of proved reserves of oil and natural gas properties, including proved reserves in the Percussion Acquisition, due to its impact on DD&A expense and acquisition accounting, as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions necessary to estimate the volumes and future net revenues of the Company’s proved reserves require a high degree of subjectivity and could have a significant impact on the measurement of DD&A expense and acquisition accounting. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others.
•We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating DD&A expense and management’s estimation of fair value of the acquired oil and natural gas properties in the Percussion Acquisition.
•We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
•To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to historical pricing differentials, operating costs, estimated development costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following:
◦We compared the estimated pricing differentials used in the reserve report to prices realized by the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials
◦We tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs
◦We evaluated the method used to determine estimated future development costs used in the reserve report and compared management’s estimate to amounts expended for recently drilled and completed wells to ascertain its reasonableness
◦We tested the working and net revenue interests used in the reserve report by inspecting land and division order records
◦We evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability and intent to develop the proved undeveloped properties,
◦We evaluated the reasonableness of the Company’s classification of reserves as proved or unproved, and
◦We applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results and to the prior year reserve report.
◦As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we utilized a valuation specialist to evaluate the appropriateness of forecasted pricing used in the reserve report by comparing the pricing forecast to published product pricing on the acquisition closing date;
◦As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we utilized a valuation specialist to evaluate whether the Company’s valuation methodology was reasonable and for certain inputs and assumptions, evaluated the process used to develop the estimate and developed an independent expectation of the estimate to evaluate its reasonableness;
◦As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we evaluated the appropriateness of the future operating cost and capital expenditure assumptions used in the reserve report by comparing forecasted amounts to historical operating costs and capital expenditures of similarly located properties;
◦As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we compared, on a sample basis, the working and net revenue interests used in the reserve report to the purchase and sale agreement; and
◦As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we evaluated, on a sample basis, the appropriateness of management’s estimated future production volumes of proved developed producing properties to subsequent actual production results and management’s estimated future production volumes of proved undeveloped properties by comparing the estimated ultimate recovery per foot to producing wells in the field.
Change in Accounting Principle from the Full Cost Method to the Successful Efforts Method
As described above and in Note 3 to the financial statements, during the first quarter of 2023, the Company voluntarily changed its method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. As a result of its change in accounting principle, management recorded significant impairments to its proved oil and natural gas properties, and made significant adjustments to DD&A expense, in historical periods to arrive at the recast financial information. As described in Note 2, under the successful efforts method of accounting, drilling and completion costs, including lease and well equipment, intangible development costs, and operation support facilities in the field, associated with the development wells, are capitalized to proved oil and gas properties and are depleted on an asset group basis (properties aggregated
based on geological features or stratigraphic conditions, such as a reservoir or field) using the units-of-production method based on estimated proved developed oil and gas reserves. As further disclosed by management, estimates of oil and natural gas reserves and their fair values used in determining impairment under the successful efforts method of accounting are impacted by, future commodity prices, future production estimates, estimated future development and operating costs, and discount rates, which are based on a weighted average cost of capital. The estimation of reserves requires significant assumptions by management and is also impacted by management’s judgments and estimates regarding the financial performance of wells with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the measurement of DD&A expense and impairment. We identified the change in accounting principle from the full cost method to the successful efforts method of accounting, due to its impacts on DD&A expense and impairment, as a critical audit matter.
The principal considerations for our determination that performing procedures relating to the change in accounting principle from the full cost method to the successful efforts method is a critical audit matter are there was significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves for purposes of reflecting the retrospective application of the successful efforts method, including the calculation of DD&A expense and the calculation of impairment charges recorded to prior periods. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the significant assumptions used in developing those estimates. In addition, the audit effort involved the use of professionals with specialized skill and knowledge in evaluating the audit evidence obtained from these procedures.
Our audit procedures related to the change in accounting principle from full cost method to successful efforts method included the following, among others.
•We tested the design and operating effectiveness of controls related to management’s application of the successful efforts method of accounting to historical periods, inclusive of those related to the determination of reserves in measuring DD&A expense and impairment.
•We evaluated the Company’s asset groupings under the successful efforts method of accounting based on geological conditions and stratigraphic features.
•We tested the allocation of properties to each asset group within the Company’s historical accounting records and reserve databases, and the assignment of such costs to leasehold and acquisition, and all other tangible and intangible drilling categories which impact the determination of DD&A expense and impairment.
•We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes.
•We compared the historical reserve databases used for calculating DD&A expense under the full cost method of accounting to those used in calculating DD&A expense under the successful efforts method of accounting for consistency, as adjusted for the grouping of assets under the successful efforts method of accounting.
•To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions in measuring impairment under the successful efforts method of accounting are derived from the Company’s accounting records, including, but not limited to historical pricing differentials, operating costs, estimated development costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis, or to those utilized in the preparation of reserve reports in previously audited periods. Specifically, our audit procedures involved testing management’s assumptions by performing the following:
◦We tested forward commodity pricing used in establishing reserve estimates with the assistance of our valuation specialist;
◦We tested the working and revenue interests used in the reserve report by comparing to historical accounting records;
◦We compared the estimated pricing differential used in the reserve reports to historical accounting records, as adjusted to reflect expected future conditions as applicable;
◦We evaluated the risk adjustments applied to proved undeveloped reserve volumes by comparing against industry accepted factors;
◦We compared future development and operating costs against the Company’s historical estimates and accounting records;
◦We compared future production estimates against historical future production estimates;
◦We evaluated the reasonableness of the weighted average cost of capital; and
◦We applied analytical procedures to production forecasts in the fair value reserve report by comparing to forecasts established in the historical SEC case reserve report used for DD&A expense determinations.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2016.
Houston, Texas
February 26, 2024
Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except par and share amounts) | | | | | | | | | | | |
| December 31, |
| 2023 | | 2022* |
ASSETS | | | |
Current assets: | | | |
Cash and cash equivalents | $3,325 | | | $3,395 | |
Accounts receivable, net | 206,791 | | | 237,128 | |
Fair value of derivatives | 11,857 | | | 21,332 | |
Other current assets | 30,154 | | | 35,783 | |
Total current assets | 252,127 | | | 297,638 | |
Oil and natural gas properties, successful efforts accounting method: | | | |
Proved properties, net | 5,086,973 | | | 4,851,529 | |
Unproved properties | 1,063,033 | | | 1,225,768 | |
Total oil and natural gas properties, net | 6,150,006 | | | 6,077,297 | |
| | | |
Other property and equipment, net | 26,784 | | | 26,152 | |
Deferred income taxes | 180,963 | | | — | |
| | | |
| | | |
Other assets, net | 101,596 | | | 87,382 | |
Total assets | $6,711,476 | | | $6,488,469 | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
Current liabilities: | | | |
Accounts payable and accrued liabilities | $526,446 | | | $536,233 | |
| | | |
| | | |
| | | |
| | | |
Fair value of derivatives | 24,147 | | | 16,197 | |
Other current liabilities | 96,369 | | | 150,384 | |
Total current liabilities | 646,962 | | | 702,814 | |
Long-term debt | 1,918,655 | | | 2,241,295 | |
| | | |
Asset retirement obligations | 42,653 | | | 53,892 | |
| | | |
| | | |
Fair value of derivatives | 29,880 | | | 13,415 | |
Other long-term liabilities | 81,965 | | | 51,272 | |
Total liabilities | 2,720,115 | | | 3,062,688 | |
Commitments and contingencies | | | |
Stockholders’ equity: | | | |
Common stock, $0.01 par value, 130,000,000 shares authorized; 66,474,525 and 61,621,518 shares outstanding, respectively | 665 | | | 616 | |
Capital in excess of par value | 4,186,524 | | | 4,022,194 | |
Accumulated deficit | (195,828) | | | (597,029) | |
Total stockholders’ equity | 3,991,361 | | | 3,425,781 | |
Total liabilities and stockholders’ equity | $6,711,476 | | | $6,488,469 | |
*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Operations
(In thousands, except per share amounts) | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| 2023 | | 2022* | | 2021* |
Operating Revenues: | | | | | |
Oil | $1,697,026 | | | $2,262,647 | | | $1,516,225 | |
Natural gas | 82,468 | | | 232,681 | | | 141,493 | |
Natural gas liquids | 174,407 | | | 260,472 | | | 193,861 | |
Sales of purchased oil and gas | 389,083 | | | 475,164 | | | 193,451 | |
Total operating revenues | 2,342,984 | | | 3,230,964 | | | 2,045,030 | |
| | | | | |
Operating Expenses: | | | | | |
Lease operating | 303,363 | | | 290,486 | | | 203,141 | |
Production and ad valorem taxes | 113,512 | | | 159,920 | | | 100,160 | |
Gathering, transportation and processing | 108,221 | | | 96,902 | | | 80,970 | |
Exploration | 9,143 | | | 9,703 | | | 6,470 | |
Cost of purchased oil and gas | 399,242 | | | 478,445 | | | 201,088 | |
Depreciation, depletion and amortization | 535,661 | | | 494,229 | | | 388,612 | |
Impairment of oil and gas properties | 406,898 | | | 2,201 | | | 52,295 | |
Gain on sale of oil and gas properties | (23,476) | | | — | | | — | |
General and administrative | 115,344 | | | 97,996 | | | 91,605 | |
Merger, integration and transaction | 11,198 | | | 769 | | | 14,289 | |
| | | | | |
Total operating expenses | 1,979,106 | | | 1,630,651 | | | 1,138,630 | |
Income From Operations | 363,878 | | | 1,600,313 | | | 906,400 | |
| | | | | |
Other (Income) Expenses: | | | | | |
Interest expense | 179,305 | | | 187,792 | | | 201,659 | |
(Gain) loss on derivative contracts | (18,898) | | | 330,953 | | | 522,300 | |
(Gain) loss on extinguishment of debt | (1,238) | | | 45,658 | | | 41,040 | |
Other (income) expense | (6,684) | | | 2,645 | | | 7,660 | |
Total other (income) expense | 152,485 | | | 567,048 | | | 772,659 | |
| | | | | |
Income Before Income Taxes | 211,393 | | | 1,033,265 | | | 133,741 | |
Income tax benefit (expense) | 189,808 | | | (13,822) | | | (180) | |
Net Income | $401,201 | | | $1,019,443 | | | $133,561 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Net Income Per Common Share: | | | | | |
Basic | $6.20 | | | $16.54 | | | $2.75 | |
Diluted | $6.19 | | | $16.47 | | | $2.65 | |
| | | | | |
Weighted Average Common Shares Outstanding: | | | | | |
Basic | 64,692 | | | 61,620 | | | 48,612 | |
Diluted | 64,852 | | | 61,904 | | | 50,311 | |
*Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(In thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Common | | Capital in | | | | Total |
| Stock | | Excess | | Accumulated | | Stockholders’ |
| Shares | | $ | | of Par | | Deficit | | Equity |
Previously reported at December 31, 2020 | 39,759 | | | $398 | | | $3,222,959 | | | ($2,512,355) | | | $711,002 | |
Effect of change in accounting principle | — | | | — | | | — | | | 762,322 | | | 762,322 | |
Balance at December 31, 2020 as recast* | 39,759 | | | $398 | | | $3,222,959 | | | ($1,750,033) | | | $1,473,324 | |
Net income | — | | | — | | | — | | | 133,561 | | | 133,561 | |
Restricted stock units | 156 | | | 2 | | | 10,949 | | | — | | | 10,951 | |
Warrant exercises | 6,913 | | | 69 | | | 134,748 | | | — | | | 134,817 | |
Common stock issued for Primexx Acquisition | 9,030 | | | 90 | | | 420,610 | | | — | | | 420,700 | |
Common stock issued for Second Lien Notes Exchange | 5,513 | | | 55 | | | 223,092 | | | — | | | 223,147 | |
Balance at December 31, 2021* | 61,371 | | | $614 | | | $4,012,358 | | | ($1,616,472) | | | $2,396,500 | |
Net income | — | | | — | | | — | | | 1,019,443 | | | 1,019,443 | |
Restricted stock units | 266 | | | 3 | | | 8,735 | | | — | | | 8,738 | |
| | | | | | | | | |
Common stock issued for Primexx Acquisition | (15) | | | (1) | | | 1,101 | | | — | | | 1,100 | |
| | | | | | | | | |
Balance at December 31, 2022* | 61,622 | | | $616 | | | $4,022,194 | | | ($597,029) | | | $3,425,781 | |
Net income | — | | | — | | | — | | | 401,201 | | | 401,201 | |
Restricted stock units | 272 | | | 3 | | | 11,033 | | | — | | | 11,036 | |
Common stock issued for Percussion Acquisition | 6,233 | | | 62 | | | 208,785 | | | — | | | 208,847 | |
Repurchase and retirement of common stock | (1,652) | | | (16) | | | (55,488) | | | — | | | (55,504) | |
Balance at December 31, 2023 | 66,475 | | | $665 | | | $4,186,524 | | | ($195,828) | | | $3,991,361 | |
*Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Cash Flows
(In thousands) | | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2023 | | 2022* | | 2021* |
Cash flows from operating activities: | | | | | |
Net income | $401,201 | | | $1,019,443 | | | $133,561 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
Depreciation, depletion and amortization | 535,661 | | | 494,229 | | | 388,612 | |
Impairment of oil and gas properties | 406,898 | | | 2,201 | | | 52,295 | |
Amortization of non-cash debt related items, net | 10,790 | | | 12,332 | | | 20,033 | |
Deferred income tax (benefit) expense | (187,270) | | | 6,308 | | | — | |
(Gain) loss on derivative contracts | (18,898) | | | 330,953 | | | 522,300 | |
Cash received (paid) for commodity derivative settlements, net | 2,922 | | | (493,714) | | | (395,097) | |
Gain on sale of oil and gas properties | (23,476) | | | — | | | — | |
(Gain) loss on extinguishment of debt | (1,238) | | | 45,658 | | | 41,040 | |
Non-cash expense related to share-based awards | 11,413 | | | 8,042 | | | 25,857 | |
| | | | | |
| | | | | |
| | | | | |
Other, net | 5,387 | | | 7,136 | | | 11,037 | |
Changes in current assets and liabilities: | | | | | |
Accounts receivable | 48,285 | | | (3,480) | | | (86,402) | |
Other current assets | (16,462) | | | (15,392) | | | (10,399) | |
Accounts payable and accrued liabilities | (82,684) | | | (58,043) | | | 146,910 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Net cash provided by operating activities | 1,092,529 | | | 1,355,673 | | | 849,747 | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (968,982) | | | (848,688) | | | (454,361) | |
Acquisition of oil and gas properties | (287,939) | | | (26,706) | | | (493,462) | |
Proceeds from sales of assets | 553,222 | | | 27,093 | | | 188,101 | |
Cash paid for settlement of contingent consideration arrangement | — | | | (19,171) | | | — | |
Other, net | (3,612) | | | 14,289 | | | 7,718 | |
Net cash used in investing activities | (707,311) | | | (853,183) | | | (752,004) | |
Cash flows from financing activities: | | | | | |
Borrowings on credit facility | 3,513,000 | | | 3,286,000 | | | 2,140,500 | |
Payments on credit facility | (3,651,000) | | | (3,568,000) | | | (2,340,500) | |
Issuance of 7.5% Senior Notes due 2030 | — | | | 600,000 | | | 650,000 | |
Redemption of 8.25% Senior Notes due 2025 | (187,238) | | | — | | | — | |
Redemption of 6.125% Senior Notes due 2024 | — | | | (467,287) | | | (542,755) | |
Redemption of 9.0% Second Lien Senior Secured Notes due 2025 | — | | | (339,507) | | | — | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Payment of deferred financing costs | (922) | | | (21,898) | | | (12,672) | |
Cash paid to repurchase common stock | (55,505) | | | — | | | — | |
| | | | | |
| | | | | |
Other, net | (3,623) | | | 1,715 | | | (2,670) | |
Net cash used in financing activities | (385,288) | | | (508,977) | | | (108,097) | |
Net change in cash and cash equivalents | (70) | | | (6,487) | | | (10,354) | |
Balance, beginning of period | 3,395 | | | 9,882 | | | 20,236 | |
Balance, end of period | $3,325 | | | $3,395 | | | $9,882 | |
*Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | | | | | | | | | | | |
1. | | 11. | |
2. | | 12. | |
3. | Change in Accounting Principle | 13. | |
4. | | 14. | |
5. | | 15. | |
6. | | 16. | |
7. | | 17. | |
8. | | 18. | |
9. | | 19. | |
10. | | 20. | |
Note 1– Description of Business
Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and sustainable development of high-quality assets in the Permian Basin in West Texas. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
Merger Agreement
On January 3, 2024, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with APA Corporation (“APA”) and Astro Comet Merger Sub Corp., a wholly owned subsidiary of APA (“Merger Sub”). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, (i) Merger Sub will be merged with and into Callon (the “Merger”), with Callon surviving and continuing as the surviving corporation in the Merger, and (ii) at the effective time of the Merger (the “Effective Time”), each outstanding share of common stock of Callon (other than Excluded Shares (as defined in the Merger Agreement)) will be converted into the right to receive, without interest, 1.0425 shares of common stock of APA, with cash in lieu of fractional shares.
The Company’s board of directors (the “Board of Directors”) has unanimously (i) determined that the Merger Agreement and the transactions contemplated thereby are in the best interests of, and advisable to, Callon and Callon shareholders, (ii) approved and declared advisable the Merger Agreement and the transactions contemplated thereby, (iii) resolved to recommend that Callon stockholders approve the Merger Agreement and the transactions contemplated thereby, and (iv) approved the execution, delivery and performance by Callon of the Merger Agreement and the consummation of the transactions contemplated thereby.
The completion of the Merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including (i) the receipt of the required approvals from Callon shareholders and APA shareholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), (iii) the absence of any governmental order or law prohibiting consummation of the Merger, (iv) the effectiveness of the registration statement on Form S-4 to be filed by APA, pursuant to which the shares of APA common stock to be issued in connection with the Merger will be registered with the SEC, and (v) the APA common stock to be issued pursuant to the Merger Agreement being authorized for listing on the Nasdaq Stock Market. The obligation of each party to consummate the Merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions), the other party having performed in all material respects its obligations under the Merger Agreement and the non-occurrence of any material adverse effect with respect to the other party since the date of the Merger Agreement.
The Merger Agreement contains certain termination rights for each of APA and Callon, and in certain circumstances, a termination fee would be payable by the terminating party.
If the Merger is consummated, the Company’s common stock will be delisted from the New York Stock Exchange (the “NYSE”) and deregistered under the Securities Exchange Act of 1934, and Callon will cease to be a publicly traded company.
For additional information related to the Merger, refer to the filings made with the SEC in connection with such transaction. The Company has prepared this 2023 Annual Report on Form 10-K as if it is going to remain an independent company. If the Merger is consummated, many of the forward-looking statements contained in this 2023 Annual Report on Form 10-K will no longer be applicable.
Note 2– Summaryof Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassifications did not have a material impact on prior period financial statements. The Company evaluates events subsequent to the balance sheet date through the date the financial statements are issued.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, evaluation of oil and gas properties for impairment, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates.
Recast Financial Information for Change in Accounting Principle
In the first quarter of 2023, the Company voluntarily changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Accordingly, the financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB Accounting Standards Codification (“ASC”) 932 “Extractive Activities — Oil and Gas.” Although the full cost method of accounting continues to be an accepted alternative, the successful efforts method of accounting is the generally preferred method of the SEC and, because it is more widely used in the industry, the Company expects the change to improve the comparability of its financial statements to its peers. The Company also believes the successful efforts method provides a more representational depiction of assets and operating results and provides for its investments in oil and natural gas properties to be assessed for impairment in accordance with ASC Topic 360 “Property Plant and Equipment,” rather than valuations based on prices and costs prescribed under the full cost method as of the balance sheet date. As required by ASC 250 “Accounting Changes and Error Corrections,” the Company has presented the accumulated effect of the change in accounting principle as a change in the beginning balance of retained earnings (accumulated deficit) of the earliest period presented in the consolidated financial statements. For detailed information regarding the effects of the change to the successful efforts method, see “Note 3 — Change in Accounting Principle.”
Cash and Cash Equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be fully federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.
Accounts Receivable, Net
Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for credit losses and bad debt expense was immaterial for all periods presented.
Concentration of Credit Risk and Major Customers
The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available
in its primary areas of activity. The Company had the following major customers that represented 10% or more of its oil, natural gas and NGL revenues for at least one of the periods presented:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 (1) | | 2022 (1) | | 2021 (1) |
Vitol Inc. | | 13% | | * | | * |
Plains Marketing, L.P. | | 12 | | * | | * |
Rio Energy International, Inc. | | 12 | | 12% | | * |
BP Products North America, Inc. | | 12 | | * | | * |
Valero Marketing and Supply Company | | * | | 15 | | 13% |
Shell Trading Company | | * | | * | | 20 |
Trafigura Trading, LLC | | * | | * | | 15 |
Occidental Energy Marketing, Inc. | | * | | * | | 13 |
| | | | | | |
(1) The customers that represented over 10% of the Company’s sales of purchased oil and gas were Vitol Inc. and Plains Marketing, L.P., for the years ended December 31, 2023 and 2022, and Vitol Inc. for the year ended December 31, 2021.
* - Less than 10% for the respective years.
See “Note 9 – Derivative Instruments and Hedging Activities” for discussion of credit risk related with the Company’s commodity derivative counterparties.
Oil and Natural Gas Properties
Proved Oil and Natural Gas Properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, associated with development wells are capitalized to proved oil and gas properties and are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Acquired proved properties and proved leasehold acquisition costs are depleted on the same asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. The calculation of depletion expense takes into consideration estimated asset retirement costs, net of estimated salvage values.
Proved oil and gas properties are assessed for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the recoverability of the net book value of such property. The Company estimates the expected future net cash flows of its proved oil and gas properties and compares these undiscounted cash flows to the net book value of the proved oil and gas properties to determine if the net book value is recoverable. If the net book value exceeds the estimated undiscounted future net cash flows, the Company will recognize an impairment to reduce the net book value of the proved oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future development costs and operating costs, and discount rates, which are based on a weighted average cost of capital. See “Note 5 — Acquisitions and Divestitures” for details of the impairment recorded in the second quarter of 2023 associated with the sale of all the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. There were no impairments of proved oil and gas properties for the years ended December 31, 2022 and 2021.
The partial sale of a proved property within an existing asset group is accounted for as a normal retirement and no net gain or loss on divestiture is recognized as long as the treatment does not significantly alter the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture is recognized in the consolidated statements of operations for all other sales of proved properties.
Unproved Oil and Natural Gas Properties. Unproved oil and gas properties consist of costs incurred in obtaining a mineral interest or a right in a property such as a lease, in addition to broker fees, recording fees and other similar costs. Leasehold costs are classified as unproved until proved reserves are discovered on or otherwise attributed to the property, at which time the related unproved oil and gas property costs are reclassified to proved oil and gas properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves.
The Company evaluates significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on the Company’s historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of unproved oil and gas properties are recognized as “Impairment of oil and gas properties” in the consolidated statements of operations.
Exploratory. Exploratory costs, including personnel and other internal costs, geological and geophysical expenses and delay rentals for oil and gas leases, are expensed as incurred. Exploratory well costs are initially capitalized pending the determination of whether proved reserves have been discovered. If proved reserves are discovered, exploratory well costs are capitalized as proved oil and gas properties. If proved reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes.
Capitalized Interest. The Company capitalizes interest on expenditures made in connection with exploration and development projects that meet certain thresholds and are not subject to current amortization. For projects that meet these thresholds, interest is capitalized only for the period that activities are in process to bring the projects to their intended use. Capitalized interest cannot exceed interest expense for the period capitalized. During the years ended December 31, 2023, 2022 and 2021, the Company did not have any projects that met the thresholds, therefore, had no capitalized interest.
Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two to twenty years.
DeferredFinancingCosts
Deferred financing costs associated with the Unsecured Senior Notes and previously with the Second Lien Notes, both defined below, are classified as a reduction of the related carrying value on the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related debt. Deferred financing costs associated with the Credit Facility, as defined below, are classified in “Other assets, net” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility.
Asset Retirement Obligations
The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to proved oil and gas properties in the consolidated balance sheets. See “Note 15 – Asset Retirement Obligations” for additional information.
Derivative Instruments
The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. The Company does not enter into commodity derivative instruments for speculative or trading purposes. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract.
Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 10 – Fair Value Measurements” for additional information regarding fair value.
The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 9 – Derivative Instruments and Hedging Activities” and “Note 10 – Fair Value Measurements” for further discussion.
Revenue Recognition
The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer.
For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. See “Note 4 – Revenue Recognition” for further discussion.
Income Taxes
Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. See “Note 13 – Income Taxes” for further discussion.
Share-Based Compensation
The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 11 – Compensation Plans” for further details of the awards discussed below.
RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at the grant date as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU awards that the Company expects, or is required, to settle in cash are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period, with the estimated fair value recognized over the vesting period.
Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs” and together with Cash-Settled RSU Awards, the “Cash-Settled Awards”) are remeasured at fair value at the end of each reporting period with the change in fair value recorded as share-based compensation expense. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs outstanding will expire in 2025 and 2026.
Share Repurchase Program
The Company repurchases shares of its common stock from time to time under a program authorized by the Board of Directors. The Company retires shares acquired through share repurchases and returns those shares to the status of authorized but unissued. The repurchased and retired shares are recorded as a reduction to “Common stock” and “Capital in excess of par value” in the consolidated balance sheets. See “Note 12 — Stockholders’ Equity” for further discussion.
SupplementalCash Flow Information
The following table sets forth supplemental cash flow information for the periods indicated:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022* | | 2021* |
| | (In thousands) |
Interest paid | | $175,076 | | | $192,220 | | | $168,235 | |
Income taxes paid (1) | | 4,477 | | | — | | | — | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | |
Operating cash flows from operating leases | | $7,735 | | | $7,096 | | | $26,681 | |
Investing cash flows from operating leases | | 42,765 | | | 32,060 | | | 18,598 | |
Non-cash investing and financing activities: | | | | | | |
Change in accrued capital expenditures | | ($4,251) | | | $11,696 | | | $63,903 | |
Change in asset retirement costs | | 10,636 | | | 6,500 | | | 2,905 | |
| | | | | | |
ROU assets obtained in exchange for lease liabilities: | | | | | | |
Operating leases | | $46,098 | | | $56,291 | | | $24,301 | |
Financing leases | | — | | | — | | | — | |
*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
(1) The Company did not pay or receive a refund for any federal income tax for the years ended December 31, 2022, and 2021. For the years ended December 31, 2023, 2022 and 2021, the Company had net payments of approximately $4.7 million, $0.2 million, and $3.2 million, respectively, in state income taxes.
Earnings per Share
The Company’s basic net income (loss) per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a net loss per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and are therefore excluded from the calculation of diluted weighted average shares outstanding. See “Note 7 – Earnings Per Share” for further discussion.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States.
Recently Adopted Accounting Standards
As of December 31, 2023, and through the filing of this report, no new accounting standards have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s consolidated financial statements and related disclosures.
Recently Issued Accounting Standards
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. In December 2022, the FASB issued ASU 2022-06 which extends the effective date through December 31, 2024. As of December 31, 2023, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 8 – Borrowings” for discussion of the Credit Agreement (as defined below) which references SOFR.
Note 3– Change in Accounting Principle
In the first quarter of 2023, the Company voluntarily changed its method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geophysical and geological costs, delay rentals, unproved leasehold impairments and exploration overhead are expensed as incurred as opposed to being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential proved oil and gas property impairments by comparing the net book value of proved oil and gas properties to associated estimated undiscounted future net cash flows. If the net book value exceeds the estimated undiscounted future net cash flows, an impairment is recorded to reduce the net book value to fair value. Under the full cost method of accounting, an impairment would be required if the net book value of oil and natural gas properties exceeds a full cost ceiling using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are recognized more frequently on the divestitures of oil and gas properties under the successful efforts method, as opposed to an adjustment to the net book value of the oil and gas properties under the full cost method.
The “Impairment of oil and gas properties” and “Gain on sale of oil and gas properties” line items presented in the tables below are in connection with the sale of all of the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. See “Note 5 — Acquisitions and Divestitures” for additional details.
The following tables present the effects of the change to the successful efforts method in the consolidated balance sheets:
| | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2023 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands) |
| | | | | | |
| | | | | | |
Oil and natural gas properties: | | | | | | |
Proved properties | | $11,661,279 | | | ($2,004,174) | | | $9,657,105 | |
Accumulated depreciation, depletion, amortization and impairments | | (6,881,323) | | | 2,311,191 | | | (4,570,132) | |
Unproved properties | | 1,559,952 | | | (496,919) | | | 1,063,033 | |
Total oil and gas properties, net | | 6,339,908 | | | (189,902) | | | 6,150,006 | |
Deferred income taxes | | 136,144 | | | 44,819 | | | 180,963 | |
Total assets | | $6,856,559 | | | ($145,083) | | | $6,711,476 | |
Stockholders’ equity: | | | | | | |
Accumulated deficit | | (50,745) | | | (145,083) | | | (195,828) | |
Total stockholders' equity | | 4,136,444 | | | (145,083) | | | 3,991,361 | |
Total liabilities and stockholders' equity | | $6,856,559 | | | ($145,083) | | | $6,711,476 | |
| | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2022 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands) |
Oil and natural gas properties: | | | | | | |
Proved properties | | $10,367,478 | | | ($1,099,343) | | | $9,268,135 | |
Accumulated depreciation, depletion, amortization and impairments | | (6,343,875) | | | 1,927,269 | | | (4,416,606) | |
Unproved properties | | 1,711,306 | | | (485,538) | | | 1,225,768 | |
Total oil and gas properties, net | | 5,734,909 | | | 342,388 | | | 6,077,297 | |
Total assets | | $6,146,081 | | | $342,388 | | | $6,488,469 | |
Deferred income taxes (1) | | 4,279 | | | 2,029 | | | 6,308 | |
Stockholders’ equity: | | | | | | |
Accumulated deficit | | (937,388) | | | 340,359 | | | (597,029) | |
Total stockholders' equity | | 3,085,422 | | | 340,359 | | | 3,425,781 | |
Total liabilities and stockholders' equity | | $6,146,081 | | | $342,388 | | | $6,488,469 | |
(1) Included in “Other long-term liabilities” in the consolidated balance sheets.
The following tables present the effects of the change to the successful efforts method in the consolidated statements of operations:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2023 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands, except per share amounts) |
Operating Expenses: | | | | | | |
Exploration | | $— | | | $9,143 | | | $9,143 | |
Depreciation, depletion and amortization | | 545,144 | | | (9,483) | | | 535,661 | |
Impairment of oil and gas properties | | — | | | 406,898 | | | 406,898 | |
Gain on sale of oil and gas properties | | — | | | (23,476) | | | (23,476) | |
General and administrative | | 77,464 | | | 37,880 | | | 115,344 | |
Income From Operations | | 784,840 | | | (420,962) | | | 363,878 | |
| | | | | | |
Other Expenses: | | | | | | |
Interest expense | | 67,977 | | | 111,328 | | | 179,305 | |
| | | | | | |
Income Before Income Taxes | | 743,683 | | | (532,290) | | | 211,393 | |
Income tax benefit | | 142,960 | | | 46,848 | | | 189,808 | |
Net Income | | $886,643 | | | ($485,442) | | | $401,201 | |
Net Income Per Common Share: | | | | | | |
Basic | | $13.71 | | | | | $6.20 | |
Diluted | | $13.67 | | | | | $6.19 | |
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2022 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands, except per share amounts) |
Operating Expenses: | | | | | | |
Exploration | | $— | | | $9,703 | | | $9,703 | |
Depreciation, depletion and amortization | | 466,517 | | | 27,712 | | | 494,229 | |
Impairment of oil and gas properties | | — | | | 2,201 | | | 2,201 | |
General and administrative | | 57,393 | | | 40,603 | | | 97,996 | |
Income From Operations | | 1,680,532 | | | (80,219) | | | 1,600,313 | |
| | | | | | |
Other Expenses: | | | | | | |
Interest expense | | 79,667 | | | 108,125 | | | 187,792 | |
| | | | | | |
Income Before Income Taxes | | 1,221,609 | | | (188,344) | | | 1,033,265 | |
Income tax expense | | (11,793) | | | (2,029) | | | (13,822) | |
Net Income | | $1,209,816 | | | ($190,373) | | | $1,019,443 | |
Net Income Per Common Share: | | | | | | |
Basic | | $19.63 | | | | | $16.54 | |
Diluted | | $19.54 | | | | | $16.47 | |
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2021 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands, except per share amounts) |
Operating Expenses: | | | | | | |
Exploration | | $— | | | $6,470 | | | $6,470 | |
Depreciation, depletion and amortization | | 356,556 | | | 32,056 | | | 388,612 | |
Impairment of oil and gas properties | | — | | | 52,295 | | | 52,295 | |
General and administrative | | 50,483 | | | 41,122 | | | 91,605 | |
Income From Operations | | 1,038,343 | | | (131,943) | | | 906,400 | |
| | | | | | |
Other Expenses: | | | | | | |
Interest expense | | 102,012 | | | 99,647 | | | 201,659 | |
| | | | | | |
Income Before Income Taxes | | 365,331 | | | (231,590) | | | 133,741 | |
Income tax expense | | (180) | | | — | | | (180) | |
Net Income | | $365,151 | | | ($231,590) | | | $133,561 | |
Net Income Per Common Share: | | | | | | |
Basic | | $7.51 | | | | | $2.75 | |
Diluted | | $7.26 | | | | | $2.65 | |
The following tables present the effects of the change to the successful efforts method in the consolidated statements of cash flows:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2023 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands) |
Cash flows from operating activities: | | | | | | |
Net income | | $886,643 | | | ($485,442) | | | $401,201 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
Depreciation, depletion and amortization | | 545,144 | | | (9,483) | | | 535,661 | |
Impairment of oil and gas properties | | — | | | 406,898 | | | 406,898 | |
Amortization of non-cash debt related items, net | | 4,064 | | | 6,726 | | | 10,790 | |
Deferred income tax benefit | | (140,422) | | | (46,848) | | | (187,270) | |
Gain on sale of oil and gas properties | | — | | | (23,476) | | | (23,476) | |
Non-cash expense related to share-based awards | | 4,019 | | | 7,394 | | | 11,413 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
Net cash provided by operating activities | | 1,236,760 | | | (144,231) | | | 1,092,529 | |
Cash flows from investing activities: | | | | | | |
Capital expenditures | | (1,104,070) | | | 135,088 | | | (968,982) | |
Acquisition of oil and gas properties | | (297,082) | | | 9,143 | | | (287,939) | |
Net cash used in investing activities | | (851,542) | | | 144,231 | | | (707,311) | |
Net change in cash and cash equivalents | | (70) | | | — | | | (70) | |
Balance, beginning of period | | 3,395 | | | — | | | 3,395 | |
Balance, end of period | | $3,325 | | | $— | | | $3,325 | |
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2022 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands) |
Cash flows from operating activities: | | | | | | |
Net income | | $1,209,816 | | | ($190,373) | | | $1,019,443 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
Depreciation, depletion and amortization | | 466,517 | | | 27,712 | | | 494,229 | |
Impairment of oil and gas properties | | — | | | 2,201 | | | 2,201 | |
Amortization of non-cash debt related items, net | | 5,280 | | | 7,052 | | | 12,332 | |
Deferred income tax expense | | 4,279 | | | 2,029 | | | 6,308 | |
Non-cash expense related to share-based awards | | 2,507 | | | 5,535 | | | 8,042 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
Net cash provided by operating activities | | 1,501,517 | | | (145,844) | | | 1,355,673 | |
Cash flows from investing activities: | | | | | | |
Capital expenditures | | (992,985) | | | 144,297 | | | (848,688) | |
Acquisition of oil and gas properties | | (28,253) | | | 1,547 | | | (26,706) | |
Net cash used in investing activities | | (999,027) | | | 145,844 | | | (853,183) | |
Net change in cash and cash equivalents | | (6,487) | | | — | | | (6,487) | |
Balance, beginning of period | | 9,882 | | | — | | | 9,882 | |
Balance, end of period | | $3,395 | | | $— | | | $3,395 | |
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2021 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands) |
Cash flows from operating activities: | | | | | | |
Net income | | $365,151 | | | ($231,590) | | | $133,561 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
Depreciation, depletion and amortization | | 356,556 | | | 32,056 | | | 388,612 | |
Impairment of oil and gas properties | | — | | | 52,295 | | | 52,295 | |
Amortization of non-cash debt related items, net | | 10,124 | | | 9,909 | | | 20,033 | |
Deferred income tax expense | | — | | | — | | | — | |
Non-cash expense related to share-based awards | | 12,923 | | | 12,934 | | | 25,857 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
Net cash provided by operating activities | | 974,143 | | | (124,396) | | | 849,747 | |
Cash flows from investing activities: | | | | | | |
Capital expenditures | | (578,487) | | | 124,126 | | | (454,361) | |
Acquisition of oil and gas properties | | (493,732) | | | 270 | | | (493,462) | |
Net cash used in investing activities | | (876,400) | | | 124,396 | | | (752,004) | |
Net change in cash and cash equivalents | | (10,354) | | | — | | | (10,354) | |
Balance, beginning of period | | 20,236 | | | — | | | 20,236 | |
Balance, end of period | | $9,882 | | | $— | | | $9,882 | |
The following tables present the effects of the change to the successful efforts method in the consolidated statements of stockholders’ equity:
| | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2023 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands) |
Accumulated deficit | | ($50,745) | | | ($145,083) | | | ($195,828) | |
Total stockholders’ equity | | $4,136,444 | | | ($145,083) | | | $3,991,361 | |
| | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2022 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands) |
Accumulated deficit | | ($937,388) | | | $340,359 | | | ($597,029) | |
Total stockholders’ equity | | $3,085,422 | | | $340,359 | | | $3,425,781 | |
| | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2021 |
| | Under Full Cost | | Changes | | Under Successful Efforts |
| | (In thousands) |
Accumulated deficit | | ($2,147,204) | | | $530,732 | | | ($1,616,472) | |
Total stockholders’ equity | | $1,865,768 | | | $530,732 | | | $2,396,500 | |
Note 4– Revenue Recognition
Revenue from contracts with customers
Oil Sales
Under the Company’s oil sales contracts, it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. The Company has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering, transportation and processing” in its consolidated statements of operations.
Natural Gas and NGL Sales
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and either remits proceeds to the Company for the resulting sale of NGLs and residue gas or, in take in-kind arrangements, provides the Company the resulting NGLs and/or residue gas for sale to downstream customers. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that the Company maintains control through processing or has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the contractual index price received.
The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing.
Oil and Gas Purchase and Sale Arrangements
The Company proactively evaluates development plans and looks to enter into pipeline transportation contracts to mitigate market exposures and help ensure certainty of flow for its oil and gas production, in some cases multiple years in advance of development. Additionally, as the Company looks to optimize its operations and reduce exposures, in certain instances, the Company purchases oil and gas from third parties which is utilized to fulfill portions of its pipeline commitments. Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. As of December 31, 2023 and 2022, receivables from the sales of purchased oil and gas were $33.9 million and $30.5 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. As of December 31, 2023 and 2022, amounts owed for purchases of oil and gas were $34.8 million and $31.1 million, respectively, and are presented in “Other current liabilities” in the consolidated balance sheets.
Accounts Receivable from Revenues from Contracts with Customers
Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2023 and 2022 of $132.3 million and $174.1 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets.
Note 5 – Acquisitions and Divestitures
2023 Acquisitions and Divestitures
Eagle Ford Divestiture
On May 3, 2023, the Company entered into an agreement with Ridgemar Energy Operating, LLC (“Ridgemar”) for the sale of all its oil and gas properties in the Eagle Ford (the “Eagle Ford Divestiture”) for consideration of $655.0 million in cash, subject to customary purchase price adjustments, as well as contingent consideration where the Company could receive up to $45.0 million if the WTI price of oil exceeds certain thresholds in 2024 (“Contingent Eagle Ford Consideration”). See “Note 9 — Derivative Instruments and Hedging Activities” for further discussion of the Contingent Eagle Ford Consideration. Upon signing, Ridgemar paid approximately $49.1 million as a deposit into a third-party escrow account. The transaction was structured as the acquisition by Ridgemar of 100% of the limited liability company interests of the Company’s wholly owned subsidiary, Callon (Eagle Ford) LLC.
During the second quarter of 2023, the Company classified the assets and liabilities associated with the Eagle Ford Divestiture as held for sale, and recorded an impairment of $406.9 million against properties associated with the Eagle Ford Divestiture as the fair value less cost to sell was less than the carrying amount of the net assets. On July 3, 2023, the Company closed the Eagle Ford Divestiture. The Eagle Ford Divestiture has an adjusted purchase price of approximately $549.6 million in cash, inclusive of the deposit paid at signing. As a result, the Company recorded a gain on sale of assets of $23.5 million in the third quarter of 2023.
Percussion Acquisition
On May 3, 2023, the Company entered into an agreement (the “Percussion Agreement”) with Percussion Petroleum Management II, LLC (“Percussion”) for the purchase of its oil and gas properties in the Delaware Basin (the “Percussion Acquisition”) for consideration of $475.0 million, which consisted of $255.0 million in cash, inclusive of the repayment of Percussion’s indebtedness of approximately $220.0 million, and $210.0 million of shares of the Company’s common stock, subject to customary purchase price adjustments. Upon signing, the Company paid $36.0 million as a deposit into a third-party escrow account. The transaction was structured as the acquisition by Callon Petroleum Operating Company of 100% of the limited liability company interests of Percussion’s wholly owned subsidiary, Percussion Petroleum Operating II, LLC (“Percussion Operating”).
On July 3, 2023, the Company closed the Percussion Acquisition. The Percussion Acquisition has an adjusted purchase price of approximately $248.5 million in cash, inclusive of the deposit paid at signing and the repayment of Percussion Operating’s indebtedness of approximately $220.0 million, and approximately 6.2 million shares of the Company’s common stock for total consideration of $457.3 million. The Company funded the cash portion of the total consideration with proceeds from the Eagle Ford Divestiture. Additionally, the Company assumed Percussion Operating’s (as defined below) existing hedges and transportation contract liabilities, and could have to pay up to $62.5 million if the WTI price of oil exceeds certain thresholds in 2023, 2024, and 2025 (“Percussion Earn-Out Obligation”). See “Note 9 - Derivative Instruments and Hedging Activities” for further discussion of the Percussion Earn-Out Obligation.
The Percussion Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date.
The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $457.3 million to the assets acquired and liabilities assumed as of the acquisition date.
| | | | | | | | |
| | Preliminary Purchase Price Allocation |
| | (In thousands) |
Assets: | | |
Accounts receivable, net | | $30,135 | |
Proved properties, net | | 490,330 | |
Unproved properties | | 52,475 | |
Total assets acquired | | $572,940 | |
| | |
Liabilities: | | |
Accounts payable and accrued liabilities | | $42,585 | |
Fair value of derivatives - current | | 20,660 | |
Other current liabilities | | 11,471 | |
Asset retirement obligations | | 2,323 | |
Fair value of derivatives - long-term | | 27,979 | |
Other long-term liabilities | | 10,619 | |
Total liabilities assumed | | $115,637 | |
| | |
Total consideration | | $457,303 | |
Approximately $131.0 million of revenues and $32.5 million of direct operating expenses attributed to the assets acquired in the Percussion Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on July 3, 2023 through December 31, 2023.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2023 and 2022 was derived from the historical financial statements of the Company and gives effect to the Percussion Acquisition, as if it had occurred on January 1, 2022. The below information reflects pro forma adjustments for the issuance of the Company’s common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Percussion Acquisition.
The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Percussion Acquisition taken place on January 1, 2022 and is not intended to be a projection of future results.
| | | | | | | | | | | | | | | | | | |
| | | | Year ended December 31, |
| | | | | | 2023 | | 2022* |
| | | | | | (In thousands, except per share amounts) |
Revenues | | | | | | $2,480,799 | | | $3,603,315 | |
Income from operations | | | | | | 434,369 | | | 1,840,018 | |
Net income | | | | | | 529,869 | | | 1,123,754 | |
Basic earnings per common share | | | | | | $8.19 | | | $16.56 | |
Diluted earnings per common share | | | | | | $8.17 | | | $16.49 | |
*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
2022 Acquisitions and Divestitures
The Company did not have any material acquisitions or divestitures for the year ended December 31, 2022.
2021 Acquisitions and Divestitures
Primexx Acquisition
On October 1, 2021, the Company closed on the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition,
LLC (“BPP”) for an adjusted purchase price of approximately $444.8 million in cash, inclusive of the deposit paid at signing, 8.84 million shares of the Company’s common stock and approximately $25.2 million paid upon final closing for total consideration of $877.0 million (the “Primexx Acquisition”). The Company funded the cash portion of the total consideration with borrowings under its credit facility. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”). Pursuant to the Primexx PSAs, 1.3 million of the shares held in escrow were released to the sellers six months after the closing date, which was on April 1, 2022. In early October 2022, the remaining 1.2 million shares were released to the sellers, net of shares that were released to the Company for the satisfaction of indemnification claims made under the Primexx PSAs and subsequently retired.
Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $31.8 million, net of customary purchase price adjustments, of which $22.4 million closed during the fourth quarter of 2021 and the remaining $9.4 million closed during the first quarter of 2022.
The Primexx Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate.
The following table sets forth the Company’s final allocation of the purchase price of $908.9 million to the assets acquired and liabilities assumed as of the acquisition date.
| | | | | | | | |
| | Final Purchase Price Allocation |
| | (In thousands) |
Assets: | | |
Other current assets | | $8,174 | |
Proved properties, net | | 695,838 | |
Unproved properties | | 278,370 | |
Total assets acquired | | $982,382 | |
| | |
Liabilities: | | |
Suspense payable | | $16,447 | |
Other current liabilities | | 45,745 | |
Asset retirement obligation | | 1,898 | |
Other long-term liabilities | | 9,425 | |
Total liabilities assumed | | $73,515 | |
| | |
Total consideration | | $908,867 | |
Approximately $570.7 million of revenues and $141.2 million of direct operating expenses attributed to the Primexx Acquisition were included in the Company’s consolidated statements of operations for the year ended December 31, 2022. For the period from the closing date of the Primexx Acquisition on October 1, 2021 through December 31, 2021, approximately $114.3 million of revenues and $32.1 million of direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2021.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2021 and 2020 was derived from the historical financial statements of the Company giving effect to the Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock and the borrowings under the Credit Facility as total consideration, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition.
The pro forma consolidated statements of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results.
| | | | | | | | |
| | Year Ended December 31, 2021 |
| | (In thousands, except per share amounts) |
Revenues | | $2,294,893 | |
Income (loss) from operations | | 1,151,493 | |
Net income (loss) | | 482,690 | |
Basic earnings per common share | | $8.37 | |
Diluted earnings per common share | | $8.13 | |
Non-Core Asset Divestitures
During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for net proceeds of $29.6 million. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position.
On November 19, 2021, the Company closed on its divestiture of certain non-core assets in the Eagle Ford Shale, comprised of producing properties as well as an undeveloped acreage position, for net proceeds of $91.9 million.
In the fourth quarter of 2021, the Company closed on the divestiture of certain non-core assets in the Midland Basin, comprised of producing properties as well as an undeveloped acreage position for net proceeds of $30.5 million.
On October 28, 2021, the Company closed on the divestiture of certain non-core water infrastructure for net proceeds of $27.9 million, as well as up to $18.0 million of incremental contingent consideration based on completed lateral length for wells in a specified area.
The aggregate net proceeds for each of the 2021 divestitures discussed above were recognized as a reduction of proved oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves.
Note 6 – Property and Equipment, Net
As of December 31, 2023 and 2022, total property and equipment, net consisted of the following:
| | | | | | | | | | | | | | |
| | As of December 31, |
| | 2023 | | 2022* |
Oil and natural gas properties, successful efforts accounting method | | (In thousands) |
Proved properties | | $9,657,105 | | | $9,268,135 | |
Accumulated depreciation, depletion, amortization and impairments | | (4,570,132) | | | (4,416,606) | |
Proved properties, net | | 5,086,973 | | | 4,851,529 | |
Unproved properties | | 1,063,033 | | | 1,225,768 | |
Total oil and natural gas properties, net | | $6,150,006 | | | $6,077,297 | |
| | | | |
Other property and equipment | | $41,011 | | | $40,530 | |
Accumulated depreciation | | (14,227) | | | (14,378) | |
Other property and equipment, net | | $26,784 | | | $26,152 | |
*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
Capitalized Exploratory Well Cost
The following table reflects the changes in capitalized exploratory costs pending the determination of proved reserves and included in unproved properties for the periods presented:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022* | | 2021* |
| | (In thousands) |
Beginning of period | | $— | | | $19,640 | | | $13,768 | |
Additions pending the determination of proved reserves | | 29,687 | | | 47,711 | | | 49,294 | |
Reclassifications to proved properties | | (29,401) | | | (67,351) | | | (43,422) | |
End of period | | $286 | | | $— | | | $19,640 | |
*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
For the years ended December 31, 2023, 2022 and 2021, the Company did not have any exploratory well costs capitalized for a period greater than one year after drilling.
Impairment of Oil and Gas Properties
The Company recognized an impairment of proved oil and gas properties for the year ended December 31, 2023 of $406.9 million as the fair value less cost to sell was less than the carrying amount of the net assets associated with the Eagle Ford Divestiture. See “Note 5 - Acquisitions and Divestitures” for further discussion of the Eagle Ford Divestiture. The Company recognized an impairment of unproved oil and gas properties in the fourth quarter of 2022 of $2.2 million due to certain leases approaching the end of their lease terms with no future plans to develop the acreage.
Note 7– Earnings Per Share
Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted stock units and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive.
The following table sets forth the computation of basic and diluted earnings per share:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022* | | 2021* |
| | (In thousands, except per share amounts) |
| | | | | | |
| | | | | | |
| | | | | | |
Net Income | | $401,201 | | | $1,019,443 | | | $133,561 | |
Basic weighted average common shares outstanding | | 64,692 | | | 61,620 | | | 48,612 | |
Dilutive impact of restricted stock units | | 160 | | | 284 | | | 296 | |
Dilutive impact of warrants | | — | | | — | | | 1,403 | |
Diluted weighted average common shares outstanding | | 64,852 | | | 61,904 | | | 50,311 | |
| | | | | | |
Net Income Per Common Share | | | | | | |
Basic | | $6.20 | | | $16.54 | | | $2.75 | |
Diluted | | $6.19 | | | $16.47 | | | $2.65 | |
| | | | | | |
Restricted stock units (1) | | 64 | | | 30 | | | 7 | |
Warrants (1) | | 481 | | | 455 | | | 481 | |
*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
(1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.
Note 8– Borrowings
The Company’s borrowings consisted of the following:
| | | | | | | | | | | | | | | | |
| | As of December 31, | | |
| | 2023 | | 2022 | | |
| | (In thousands) | | |
8.25% Senior Notes due 2025 | | $— | | | $187,238 | | | |
6.375% Senior Notes due 2026 | | 320,783 | | | 320,783 | | | |
Senior Secured Revolving Credit Facility due 2027 | | 365,000 | | | 503,000 | | | |
8.0% Senior Notes due 2028 | | 650,000 | | | 650,000 | | | |
7.5% Senior Notes due 2030 | | 600,000 | | | 600,000 | | | |
Total principal outstanding | | 1,935,783 | | | 2,261,021 | | | |
Unamortized premium on 8.25% Senior Notes | | — | | | 1,715 | | | |
Unamortized deferred financing costs for Senior Unsecured Notes | | (17,128) | | | (21,441) | | | |
Long-term debt (1) | | $1,918,655 | | | $2,241,295 | | | |
(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $12.8 million and $18.8 million as of December 31, 2023 and 2022, respectively, which are classified in “Other assets, net” in the consolidated balance sheets.
Senior Secured Revolving CreditFacility
On December 20, 2019, upon consummation of the acquisition of Carrizo Oil & Gas, Inc. (the “Carrizo Acquisition”), the Company entered into the credit agreement with a syndicate of lenders (the “Prior Credit Facility”). The Prior Credit Facility provided for interest-only payments until December 20, 2024, when the Prior Credit Facility would mature and any outstanding borrowings would become due. The maximum credit amount under the Prior Credit Facility was $5.0 billion.
On October 19, 2022, the Company entered into the Amended & Restated Credit Agreement (the “Credit Agreement” and the senior secured revolving credit facility thereunder, the “Credit Facility”) on substantially similar terms as those in the credit agreement governing the Prior Credit Facility. The Credit Agreement, among other things, extended the term to provide for interest-only payments until October 19, 2027 when the Credit Agreement matures and any outstanding borrowings are due, established a borrowing base of $2.0 billion, with an elected commitment amount of $1.5 billion, replaced all provisions and related definitions regarding LIBOR with SOFR, and decreased the maximum leverage ratio from 4.00 to 1.00 to 3.50 to 1.00. As of December 31, 2023, the borrowing base under the Credit Facility was $2.0 billion, with an elected commitment amount of $1.5 billion, and borrowings outstanding of $365.0 million at a weighted-average interest rate of 7.54%, and letters of credit outstanding of $21.4 million.
Borrowings outstanding under the Credit Agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 0.75% to 1.75%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50%, and the SOFR plus 0.1% (“Adjusted SOFR”) for a one month period plus 1.00%, or (ii) an Adjusted SOFR plus a margin between 1.75% to 2.75%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% on the unused portion of lender commitments, which are included in “Interest expense” in the consolidated statements of operations.
The borrowing base under the Credit Agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the Credit Agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. On October 31, 2023, as part of the Company’s fall 2023 redetermination, the borrowing base of $2.0 billion and elected commitment amount of $1.5 billion was reaffirmed.
Senior Unsecured Notes
Redemption of 8.25% Senior Notes. On August 2, 2023, the Company used borrowings under the Credit Facility to redeem all $187.2 million of its outstanding 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”). The Company recognized a gain on extinguishment of debt of approximately $1.2 million in its consolidated statements of operations, which primarily related to the remaining unamortized premium.
7.5% Senior Notes. On June 24, 2022, the Company issued and sold $600.0 million in aggregate principal amount of 7.5% senior unsecured notes due 2030 (the “7.5% Senior Notes”) in a private placement for proceeds of approximately $588.0 million, net of initial purchasers’ discounts and commissions. The 7.5% Senior Notes mature on June 15, 2030, and interest is payable semi-annually each June 15 and December 15, commencing on December 15, 2022.
At any time prior to June 15, 2025, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.5% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of
the aggregate principal amount of the 7.5% Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to June 15, 2025, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 7.5% Senior Notes at 100.0% of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after June 15, 2025, the Company may redeem all or a portion of the 7.5% Senior Notes at redemption prices decreasing annually from 103.75% to 100.0% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control that are accompanied by a ratings decline, each holder of the 7.5% Senior Notes may require the Company to repurchase all or a portion of such holder’s 7.5% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest.
8.0% Senior Notes.On July 6, 2021, the Company issued $650.0 million aggregate principal amount of 8.0% Senior Notes due 2028 (the “8.0% Senior Notes”) in a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. The 8.0% Senior Notes mature on August 1, 2028 and have interest payable semi-annually each February 1 and August 1.
At any time prior to August 1, 2024, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 8.0% Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 108.0% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the aggregate principal amount of the 8.0% Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to August 1, 2024, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 8.0% Senior Notes at 100.0% of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after August 1, 2024, the Company may redeem all or a portion of the 8.0% Senior Notes at redemption prices decreasing annually from 104.0% to 100.0% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control, the Company must make an offer to repurchase all or a portion of each holder’s 8.0% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest.
6.375% Senior Notes.The Company’s 6.375% Senior Notes due 2026 (the “6.375% Senior Notes”) mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. Since July 1, 2022, the Company may redeem all or a portion of the 6.375% Senior Notes at redemption prices decreasing annually from 102.125% to 100% of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 6.375% Senior Notes may require the Company to repurchase all or a portion of the 6.375% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.
Each of the Senior Unsecured Notes described above are guaranteed on a senior unsecured basis by the Company’s wholly owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.
Covenants
The Credit Agreement and the indentures governing the 6.375% Senior Notes, the 8.0% Senior Notes, and the 7.5% Senior Notes (collectively, the “Senior Unsecured Notes”) limit the Company and certain of its subsidiaries with respect to the amount of additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters, along with maintenance of certain financial ratios.
Under the Credit Agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Leverage Ratio (as defined in the Credit Agreement) of no more than 3.50 to 1.00 and (2) a Current Ratio (as defined in the Credit Agreement) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2023.
The Credit Agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).
Note 9 – Derivative Instruments and Hedging Activities
Objectives and Strategies for Using Derivative Instruments
The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, put and call options, and basis differential swaps to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty Risk and Offsetting
The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to ISDA Agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
The Company strives to minimize its credit exposure to any individual counterparty and, as such, the Company had outstanding commodity derivative instruments with nine counterparties as of December 31, 2023. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s Credit Facility. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the Credit Agreement, thus eliminating the need for independent collateral posting.
Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty.
While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 10 – Fair Value Measurements” for further discussion.
Contingent Consideration Arrangements
Percussion Earn-Out Obligation. As a result of the Percussion Acquisition, the Company assumed an earn-out obligation from Percussion Operating, where the Company could be required to pay up to $62.5 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $60.00 per barrel for each of the 2023, 2024, and 2025 calendar years. The specified threshold for 2023 was met and the Company paid $12.5 million in January 2024, which will be classified as cash flows from investing activities in the consolidated statements of cash flows in 2024.
Contingent Eagle Ford Consideration. As a result of the Eagle Ford Divestiture, the Company received a contingent consideration arrangement from Ridgemar. The Company could receive up to $45.0 million if the average daily settlement price of WTI crude oil for 2024 is at least $80.00 per barrel. If the average daily settlement price of WTI crude oil for 2024 is less than $80.00 per barrel but at least $75.00 per barrel, then the Company would receive $20.0 million.
The Company determined that the Percussion Earn-Out Obligation and Contingent Eagle Ford Consideration receipt were not clearly and closely related to the Percussion Acquisition and Eagle Ford Divestiture membership interest purchase agreements, and therefore bifurcated these embedded features and recorded these derivatives at their acquisition date fair value and divestiture date fair value of $34.9 million and $10.9 million, respectively, in the consolidated financial statements. As of December 31, 2023, the estimated fair values of the Percussion Earn-Out Obligation and Contingent Eagle Ford Consideration were $42.4 million and $12.6 million, respectively, and are presented in “Fair value of derivatives” in the consolidated balance sheets.
Ranger Divestiture and Carrizo Acquisition Contingent Consideration. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin. Additionally, on December 20, 2019, the Company completed the Carrizo Acquisition. Both of these transactions included potential additional contingent consideration if certain specified pricing thresholds were met through the end of 2021. Those pricing thresholds were met for 2021, resulting in a cash receipt and cash payment, respectively, during the first quarter of 2022. Cash received or paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities or cash flows from investing activities, respectively, up to the divestiture or acquisition date fair value, respectively, with any excess classified as cash flows from operating activities. As a result, the Company received $20.8 million, of which $8.5 million is presented in cash flows from financing activities with the remaining $12.3 million presented in cash flows from operating activities, and paid $25.0 million, of which $19.2 million is presented in cash flows from
investing activities with the remaining $5.8 million presented in cash flows from operating activities. Both of these contingent consideration arrangements were completed as of the end of 2021.
Financial Statement Presentation and Settlements
The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value, as well as settlements during the period, as “(Gain) loss on derivative contracts” in the consolidated statements of operations. The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheets as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
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| As of December 31, 2023 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
| (In thousands) |
Derivative Assets | | | | | |
Commodity derivative instruments | $25,813 | | | ($13,956) | | | $11,857 | |
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Fair value of derivatives - current | $25,813 | | | ($13,956) | | | $11,857 | |
Commodity derivative instruments | $— | | | $— | | | $— | |
Contingent consideration arrangements | 12,580 | | | — | | | 12,580 | |
Other assets, net | $12,580 | | | $— | | | $12,580 | |
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Derivative Liabilities | | | | | |
Commodity derivative instruments (1) | ($25,603) | | | $13,956 | | | ($11,647) | |
Contingent consideration arrangements | (12,500) | | | — | | | (12,500) | |
Fair value of derivatives - current | ($38,103) | | | $13,956 | | | ($24,147) | |
Commodity derivative instruments | $— | | | $— | | | $— | |
Contingent consideration arrangements | (29,880) | | | — | | | (29,880) | |
Fair value of derivatives - non-current | ($29,880) | | | $— | | | ($29,880) | |
(1) Includes approximately $4.1 million of deferred premiums, which will be paid as the applicable contracts settled.
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| As of December 31, 2022 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
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Fair value of derivatives - current | $51,984 | | | ($30,652) | | | $21,332 | |
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Other assets, net | $1,343 | | | ($889) | | | $454 | |
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Derivative Liabilities | | | | | |
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Fair value of derivatives - current | ($46,849) | | | $30,652 | | | ($16,197) | |
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Fair value of derivatives - non-current | ($14,304) | | | $889 | | | ($13,415) | |
The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:
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| Years Ended December 31, |
| 2023 | | 2022 | | 2021 |
| (In thousands) |
(Gain) loss on oil derivatives | ($22,371) | | | $287,379 | | | $429,156 | |
(Gain) loss on natural gas derivatives | (4,990) | | | 38,803 | | | 33,621 | |
Loss on NGL derivatives | 2,663 | | | 4,771 | | | 6,768 | |
(Gain) loss on contingent consideration arrangements | 5,800 | | | — | | | (2,635) | |
Loss on September 2020 Warrants liability (1) | — | | | — | | | 55,390 | |
(Gain) loss on derivative contracts | ($18,898) | | | $330,953 | | | $522,300 | |
(1) A detailed discussion of the Company’s September 2020 Warrants can be found in “Part II, Item 8. Financial Statements and Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022.
The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash received (paid) for settlements of contingent consideration arrangements, net” are as follows for the respective periods:
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| Years Ended December 31, |
| 2023 | | 2022 | | 2021 |
| (In thousands) |
Cash flows from operating activities | | | | | |
Cash paid on oil derivatives | ($14,626) | | | ($429,017) | | | ($350,340) | |
Cash received (paid) on natural gas derivatives | 18,109 | | | (60,914) | | | (34,576) | |
Cash paid on NGL derivatives | (561) | | | (3,783) | | | (10,181) | |
Cash received (paid) for commodity derivative settlements, net | $2,922 | | | ($493,714) | | | ($395,097) | |
Cash received for settlements of contingent consideration arrangements, net (1) | $— | | | $6,492 | | | $— | |
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Cash flows from investing activities | | | | | |
Cash paid for settlement of contingent consideration arrangement | $— | | | ($19,171) | | | $— | |
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Cash flows from financing activities | | | | | |
Cash received for settlement of contingent consideration arrangement | $— | | | $8,512 | | | $— | |
Derivative Positions
Listed in the tables below are the outstanding oil, natural gas, and NGL derivative contracts as of December 31, 2023:
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| For the Full Year | | | |
Oil Contracts (WTI) | 2024 | | | |
Deferred Premium Put Contracts (1)(2)
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Total volume (Bbls) | 1,076,300 | | | | |
Weighted average price per Bbl | $81.66 | | | | |
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Three-Way Collar Contracts | | | | |
Total volume (Bbls) | 3,963,025 | | | | |
Weighted average price per Bbl | | | | |
Ceiling (short call) | $78.86 | | | | |
Floor (long put) | $58.16 | | | | |
Floor (short put) | $48.16 | | | | |
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(1) Deferred premium put contracts are a combination of a short fixed price swap and a long call option which then performs as a long put position.
(2) Premiums associated with the Company’s deferred premium puts were approximately $4.1 million, which will be paid as the applicable contracts settle.
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| Experience •Chief Executive Officer, Banco Itaú International, a global bank •Executive Advisor to the Dean, School of Business, University of Miami, a private university •Interim Dean, School of Business, University of Miami, a private university •President, US Trust Company, Bank of America Private Wealth Management, a trust company focusing on investment management, wealth structuring, and credit and lending services •President and CEO, US Trust Company, a trust company focusing on investment management, wealth structuring, and credit and lending services •Various operational and management positions at Citigroup’s private banking business, including President of Latin America Private Banking, President of Europe Private Banking, and Head of International Trust Business |
Frances Aldrich Sevilla-Sacasa Age: 68 Independent Director since 2019 Committees: •Audit (Chair) •Compensation |
Other Boards •Independent Director, Invitation Homes Inc., a publicly traded real estate company (2023 – present) •Independent Director, Camden Property Trust, a publicly traded real estate investment trust (2011 – present) •Independent Director, Delaware Funds by Macquarie, a full service asset manager (2011 – present) •Former Independent Director, New Senior Investment Group, a publicly traded real estate investment trust (2021 – 2021) •Former Independent Director and Board Chair, Carrizo Oil and Gas, Inc., a publicly traded oil and gas company that merged with Callon Petroleum Company in 2019 (2018 – 2019) •Member, Florida chapter of National Association of Corporate Directors (2022 – present) |
| Qualifications and Expertise Provided to our Board For•Deep investment management company and private banking experience brings strong financial acumen to the Full YearBoard’s financial and investment decisions and supports alignment with the priorities of Company shareholders
•Her designation as a “financial expert” and knowledge of public company reporting requirements make her well-suited to lead the Company’s Audit Committee •Experience in C-suite and other senior executive roles brings valuable strategic and leadership insights to the Board •Considerable service on the boards of other companies, including in multiple committee leadership roles, has provided her with meaningful corporate governance experience •Board Leadership Fellow of National Association of Corporate Directors | | | |
Natural Gas Contracts (Henry Hub) | 2024 | | | |
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Education Collar Contracts•B.A., University of Miami
•M.B.A., Thunderbird School of Global Management | | | | |
Total volume (MMBtu) | 8,598,557 | | | | |
Weighted average price per MMBtu | | | | |
Ceiling (short call) | $3.89 | | | | |
Floor (long put) | $3.00 | | | | |
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Natural Gas Contracts (Waha Basis Differential) | | | | |
Swap Contracts | | | | |
Total volume (MMBtu) | 7,320,000 | | | | |
Weighted average price per MMBtu | ($1.06) | | | | |
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Natural Gas Contracts (HSC Basis Differential) | | | | |
Swap Contracts | | | | |
Total volume (MMBtu) | 14,640,000 | | | | |
Weighted average price per MMBtu | ($0.42) | | | | |
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| For the Full Year | | | |
NGL Contracts (Mont Belvieu Normal Butane) | 2024 | | | |
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Swap Contracts | | | | |
Total volume (Bbls) | 72,105 | | | | |
Weighted average price per Bbl | $33.18 | | | | |
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NGL Contracts (Mont Belvieu Isobutane) | | | | |
Swap Contracts | | | | |
Total volume (Bbls) | 23,462 | | | | |
Weighted average price per Bbl | $33.18 | | | | |
Note 10 – Fair Value Measurements
Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2 – Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 – Unobservable inputs for which there is little or no market data and for which the Company makes its own assumptions about how market participants would price the assets and liabilities.
Fair Value of Financial Instruments
Cash, Cash Equivalents, and Restricted Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Senior Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy.
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| | December 31, 2023 | | December 31, 2022 |
| | Principal Amount | | Fair Value | | Principal Amount | | Fair Value |
| | (In thousands) |
8.25% Senior Notes | | $— | | | $— | | | $187,238 | | | $186,719 | |
6.375% Senior Notes | | 320,783 | | | 320,119 | | | 320,783 | | | 301,732 | |
8.0% Senior Notes | | 650,000 | | | 665,164 | | | 650,000 | | | 616,935 | |
7.5% Senior Notes | | 600,000 | | | 606,414 | | | 600,000 | | | 550,812 | |
Total | | $1,570,783 | | | $1,591,697 | | | $1,758,021 | | | $1,656,198 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate fair value:
Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and as there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 9 – Derivative Instruments and Hedging Activities” for further discussion.
Contingent Consideration Arrangements - Embedded Derivative Financial Instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 9 - Derivative Instruments and Hedging Activities” for further discussion.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2023 and 2022:
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| Experience •Chairman, CEO and President, Rosetta Resources Inc., an independent oil and gas company •Senior Vice President – Drilling & Production Operations, Rosetta Resources Inc., an independent oil and gas company •Chief Operating Officer, BPI Energy, Inc., an E&P start-up company focused on coal bed methane development •Various technical, operational, and strategic roles, including Chief Engineer, at Burlington Resources, Inc. and its predecessor companies |
Other Boards •Independent Director, Crescent Point Energy Corp., a publicly traded oil and gas company (2019 – present) •Independent Director, Amplify Energy Corp., a publicly traded oil and natural gas company (2023 – present) •Former Independent Director, Civitas Resources, Inc., a publicly traded oil and gas exploration company (2021 – 2021) •Former Independent Director, Templar Energy LLC, an independent upstream oil and gas company (2017 – 2019) •Former Independent Director, Noble Energy Inc., a publicly traded oil and gas E&P company (2015 – 2020) •Former Director, Rosetta Resources Inc., an independent oil and gas company, until its merger with Noble Energy Inc. |
James E. Craddock Age: 65 Independent Director since 2023 Committees: •N&ESG •Operations & Reserves |
| Qualifications and Expertise Provided to our Board •Seasoned upstream executive and director who possesses broad-based technical and operational knowledge of U.S. onshore operations with over 30 years of experience •Wide-ranging experience in corporate strategy and oversight as a board member and executive of multiple E&P companies •Service on the boards of other publicly traded companies that has provided him with exposure to oversight, risk assessment, and corporate governance that will bring diverse experience to the Board |
| | | | | | | | | | Education •B.S. in Mechanical Engineering, Texas A&M University |
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| | December 31, 2023 |
| | Level 1 | | Level 2 | | Level 3 |
| | (In thousands) |
Derivative Assets | | | | | | |
Commodity derivative assets | | $— | | | $11,857 | | | $— | |
Contingent consideration arrangements | | — | | | 12,580 | | | — | |
Total net assets | | $— | | | $24,437 | | | $— | |
Derivative Liabilities | | | | | | |
| Experience Commodity derivative liabilities •(1)Major General (2-stars), United States Air Force (1982 - 2014), the air service branch of the United States Armed Forces
•Progressive posts and rankings over a 32-year career with the U.S. Air Force, which culminated in her being in the top 150 leaders of a 320,000-person global organization • Her last assignment was as Vice Commander (COO) and interim Commander (CEO) of a 37,000-person organization conducting all global Department of Defense air cargo, passenger, and medical patient movements with 1,100 military aircraft plus contracted commercial aircraft |
Barbara J. Faulkenberry Age: 64 Independent Director since 2018 Committees: •N&ESG (Chair) •Compensation | | Other Boards $—
| | | ($11,647) | | | $— | |
Contingent consideration arrangements | | — | | | (42,380) | | | — | |
Total net assets (liabilities) | | $—•Former independent Director, Target Hospitality Corp., a national provider of vertically integrated modular accommodations and hospitality services (2021 - 2023) | | | ($54,027)
| | | $—•Former Independent Director, USA Truck Inc., a publicly traded provider of trucking services (2016 - 2022) | |
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| | December 31, 2022•Advisory Director, Momentum Aerospace Group (2014 – 2018), an aerial intelligence, surveillance, and reconnaissance company
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| | Qualifications and Expertise Provided to our Board Level 1•
| | Level 2Specialized substantive knowledge in cybersecurity deployment and management, including earning the Carnegie Mellon/NACD CERT Certificate in Cybersecurity Oversight and the Digital Directors Network certification as a “Qualified Technical Expert,” which are areas of increased focus for the Company and the Board | | Level 3•Broad leadership experience and uniquely valuable global perspective gained during her U.S. Air Force career, which supports and aligns with the Board’s strategic planning role and risk oversight function
•Deep supply chain management and logistics knowledge stemming from commanding global mobilization and logistics efforts •Career experience in leadership development and succession planning •Service on the boards of other publicly traded companies, including leadership roles, has provided her exposure to different industries and approaches to governance that further enhances the Board •National Association of Corporate Directors Board Certified |
| | Education (In thousands)•B.S. in Operations Research, United States Air Force Academy
•M.B.A., Georgia College & State University •Master of National Security, National Defense University •Completed strategic leadership courses at Harvard University, University of Cambridge, and Syracuse University |
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Commodity derivative assets | | $— | | | $21,786 | | | $— | |
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Commodity derivative liabilities | | $— | | | ($29,612) | | | $— | |
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(1) Includes approximately $4.1 million of deferred premiums, which will be paid as the applicable contracts settled.
There were no transfers between any of the fair value levels during any period presented.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Acquisitions. The fair value of assets acquired and liabilities assumed are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 5 – Acquisitions and Divestitures” for additional discussion.
Asset Retirement Obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and that, therefore, are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities, restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 15 – Asset Retirement Obligations” for additional discussion.
Note 11 – Compensation Plans | | | | | |
| Experience •Senior Vice President and Chief Financial Officer, CF Industries, Inc., a publicly traded manufacturer in global agricultural and industrial markets •Vice President and Chief Financial Officer, Merisant Worldwide Inc., a privately held company specializing in the selling and distribution of food additives •Chief Financial Officer, BP Chemicals, a global chemical business •Various financial and management positions at Amoco Corporation, including service as Amoco’s Vice President and Controller |
Other Boards •Former Director, Terra Nitrogen LP, a manufacturer in agricultural and industrial markets •Former Director, Keytrade AG, a global fertilizer trading organization •Former Director, Vysis Corporation, a provider of genomic disease management products and related customer and technical services •Former Director, Chicagoland Chamber of Commerce, a non-profit organization •Member, National Council of the McKelvey School of Engineering advising the Dean of Engineering at Washington University in St. Louis |
Anthony J. Nocchiero Age: 72 Independent Director since 2011 Committees: •Compensation (Chair) •Audit |
| Qualifications and Expertise Provided to our Board •Broad knowledge of the finance, energy, and commodities industries and extensive experience with finance and M&A related transactions •Status as a “financial expert” and knowledge of public company financial reporting regulations, compliance requirements, audit functions and internal controls contribute valuable expertise to the Board and Audit Committee •Professional experience in risk identification and mitigation that are additive to the Board’s risk assessment capabilities •Service on the boards of other companies has provided him exposure to different industries and approaches to governance that further enhances the Board’s oversight function |
| Education •B.S. in Chemical Engineering, Washington University in St. Louis •M.B.A. in Finance, Northwestern University |
2020 Omnibus Incentive Plan
Shares-based awards are granted under the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “2018 Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the 2018 Plan; however, awards previously granted under the 2018 Plan will remain outstanding in accordance with their terms. At December 31, 2023, there were 1,326,047 shares available for future share-based awards under the 2020 Plan.
RSU Equity Awards
The following table summarizes RSU Equity Award activity for the year ended December 31, 2023:
| | | | | | | | | | | | | | |
| | RSU Equity Awards (In thousands) | | Weighted Average Grant-Date Fair Value per Share |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Unvested at the beginning of the year | | 800 | | | $44.79 | |
Granted | | 654 | | | $34.33 | |
Vested | | (374) | | | $39.89 | |
Forfeited | | (225) | | | $42.75 | |
Unvested at the end of the year | | 855 | | | $39.46 | |
Grant activity for the years ended December 31, 2023, 2022 and 2021 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards with a weighted average grant date fair value of $34.33, $57.85 and $38.59, respectively.
For performance-based RSU Equity Awards vested on December 31, 2022 and December 31, 2021, the number of performance-based RSU Equity Awards that could vest was based on a calculation that compares the Company’s TSR to the same calculated return of a group of peer companies selected by the Company and can range between 0% and 300% and 0% and 200% of the target units, respectively. No performance-based RSU Equity Awards vested during 2023.
The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers.
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
Performance-based Equity Awards | | 2022 | | 2021 |
Vesting Multiplier | | 18 | % | | 50 | % |
Target | | 86,455 | | 28,356 |
Vested at end of performance period | | 15,559 | | 14,177 |
Did not vest at end of performance period | | 70,896 | | 14,179 |
The aggregate fair value of RSU Equity Awards that vested during the years ended December 31, 2023, 2022 and 2021 was $12.5 million, $22.4 million and $8.7 million, respectively. As of December 31, 2023, unrecognized compensation costs related to unvested RSU Equity Awards were $22.1 million and will be recognized over a weighted average period of 1.7 years.
Cash-Settled Awards
As of December 31, 2023 and 2022, the Company had a total liability of $2.2 million and $6.5 million, respectively, for the outstanding Cash-Settled Awards.
Share-Based Compensation Expense, Net
Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled Awards is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022* | | 2021* |
| | (In thousands) |
RSU Equity Awards expense | | $14,658 | | | $15,535 | | | $13,230 | |
Cash-Settled Awards (benefit) expense | | (3,245) | | | (7,493) | | | 12,627 | |
Total share-based compensation expense, net | | $11,413 | | | $8,042 | | | $25,857 | |
| | | | | |
| Experience •Chief Executive Officer, BP Angola, a subsidiary of BP focused on offshore E&P activities •Chief Operating Officer, BP Angola, a subsidiary of BP focused on offshore E&P activities • Director General, BP Vietnam, a subsidiary of BP focused on offshore E&P activities and onshore processing and power generation • Various operational, engineering, and management positions at BP and Amoco Corporation |
Mary Shafer-Malicki Age: 63 Independent Director since 2022 Committees: •Operations & Reserves (Chair) •Audit | Other Boards •Independent Director, Ag Growth International Inc., a publicly traded farm machinery and equipment company (2024 - present) •Independent Director, Gulfport Energy Corp., a publicly traded oil and gas E&P company (2023 – present) •Former Independent Director and Board Chair, QEP Resources, Inc., a publicly traded oil and gas E&P company (2017 – 2021) •Former Independent Director, Wood Plc, a Scotland-based engineering, operations and maintenance services provider for the oil & gas, infrastructure and power generation markets (2012 – 2021) •Former Independent Director, McDermott International Inc., publicly traded EPC company, including when it filed voluntary petitions for reorganization in the United States Bankruptcy Court for the Southern District of Texas in January 2020 (2011 – 2020) •Director and Chair, University of Wyoming Foundation, a foundation with the mission of securing resources and delivering stewardship of funding for the university (2016 – present) •Member, Industry Advisory Board for Chemical Engineering Department at the University of Wyoming (2010 – present) •Member, Strategic Advisory Counsel to the Dean of Engineering at Oklahoma State University (2021 – present) •Former Independent Director, Ausenco Limited, an Australian-based engineering services company |
| Qualifications and Expertise Provided to our Board •Over 25 years of operations, engineering, and management experience across the energy value chain positions her to advise on complex issues of strategy and execution •Deep technical expertise developed through her professional career and academic engagements make her well-suited for oversight of the Company’s reserves process •Service on the boards of other publicly traded companies, including in leadership roles, has provided her exposure to a wide range of strategic decision making and approaches to corporate governance that enhances the Board’s deliberations •Experience with safety, environmental and regulatory matters contributes to the Board’s oversight function |
| Education •B.S. in Chemical Engineering, Oklahoma State University •Completed the Executive Education Program at University of Cambridge •Completed the New Global Business Environment Executive Program at Harvard University |
*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
401(k) Plan
The Company has a defined contribution plan (“401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute 1% to 100% of their qualified annual earnings, as defined by the 401(k) Plan, up to the contribution limits established under the Internal Revenue Code (the “IRC”). The Company matches 100% of each employee’s contributions, up to 6% of the employee’s eligible compensation, and may make additional contributions as may be determined by the Company’s Board of Directors. The Company’s contributions to the 401(k) Plan were $3.6 million, $3.0 million, and $2.2 million for the years ended December 31, 2023, 2022, and 2021, respectively.
Note 12– Stockholders’ Equity
Share Repurchase Program
On May 2, 2023, the Board of Directors approved a share repurchase program (the “Share Repurchase Program”), pursuant to which the Company is authorized to repurchase up to $300.0 million of its outstanding common stock through the second quarter of 2025. Repurchases under the Share Repurchase Program may be made, from time to time, in amounts and at prices the Company deems appropriate and will be subject to a variety of factors, including the market price of the Company’s common stock, general market and economic conditions and applicable legal requirements. The Share Repurchase Program may be suspended, modified or discontinued by the Board of Directors at any time without prior notice. Pursuant to the Merger Agreement, we are restricted from making further repurchases under such program without APA’s approval.
During the year ended December 31, 2023, the Company repurchased and retired 1.7 million shares of common stock at a weighted average purchase price of $33.59 per common share for a total cost of approximately $55.5 million. As of December 31, 2023, the remaining authorized repurchase amount under the Share Repurchase Program was $244.5 million.
Percussion Acquisition
During the year ended December 31, 2023, the Company issued approximately 6.2 million shares of common stock in connection with the Percussion Acquisition. See “Note 5 – Acquisitions and Divestitures” for additional details.
Second Lien Note Exchange
On November 3, 2021, at a special meeting of shareholders, the Company obtained the requisite shareholder approval for the issuance of approximately 5.5 million shares of the Company’s common stock in exchange for an aggregate of $197.0 million principal amount of Second Lien Notes. The exchange was completed on November 5, 2021 and the exchanged Second Lien Notes were immediately cancelled.
Primexx Acquisition
During the fourth quarter of 2021, the Company issued approximately 9.0 million shares of common stock in connection with the Primexx Acquisition, inclusive of the shares of common stock issued to those certain interest owners who exercised their option to sell their interest in the properties included in the Primexx Acquisition. See “Note 5 – Acquisitions and Divestitures” for additional details.
Warrant Exercises
During the year ended December 31, 2021, holders of the September 2020 Warrants and November 2020 Warrants provided notice and exercised all outstanding warrants. As a result of the exercises in 2021, the Company issued a total of 6.9 million shares of its common stock in exchange for 9.0 million outstanding warrants determined on a net shares settlement basis. A detailed discussion of the Company’s September 2020 Warrants and November 2020 Warrants can be found in “Part II, Item 8. Financial Statements and
Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. As of December 31, 2023, December 31, 2022 and December 31, 2021, no September 2020 or November 2020 Warrants were outstanding.
Note 13 – Income Taxes
The components of the Company’s income tax expense are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022* | | 2021* |
| | (In thousands) |
Current | | | | | | |
Federal | | ($2,271) | | | $2,977 | | | $— | |
State | | (266) | | | 4,537 | | | 180 | |
Total current income tax expense (benefit) | | (2,537) | | | 7,514 | | | 180 | |
| | | | | | |
Deferred | | | | | | |
Federal | | (188,911) | | | — | | | — | |
State | | 1,640 | | | 6,308 | | | — | |
Total deferred income tax expense (benefit) | | (187,271) | | | 6,308 | | | — | |
Total income tax expense (benefit) | | ($189,808) | | | $13,822 | | | $180 | |
*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
A reconciliation of the income tax expense calculated at the federal statutory rate of 21% to income tax expense is as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022* | | 2021* |
| | (In thousands) |
Income before income taxes | | $211,393 | | | $1,033,265 | | | $133,741 | |
Income tax expense computed at the statutory federal income tax rate | | 44,393 | | | 216,986 | | | 28,086 | |
State income tax expense (benefit), net of federal benefit | | 1,430 | | | 11,393 | | | 2,905 | |
Non-deductible expenses related to capital structure transactions | | — | | | (2,896) | | | (11,875) | |
| | | | | | |
Equity based compensation | | 385 | | | (1,496) | | | 564 | |
| | | | | | |
| | | | | | |
Other | | 2,364 | | | (1,223) | | | 10,247 | |
Change in valuation allowance | | (238,380) | | | (208,942) | | | (29,747) | |
Income tax expense (benefit) | | ($189,808) | | | $13,822 | | | $180 | |
| | |
| Experience •Managing Partner (2005 – present), of AEC Partners and its predecessor Avista Capital Partners, which are private equity firms engaged in venture capital and investment activities in energy and other industries •Co-founder (1993 – 2019), Carrizo Oil & Gas, Inc., a publicly traded oil and gas company that merged with Callon Petroleum Company in 2019 •Chair, Global Energy Partners, an affiliate of DLJ Merchant Banking and CSFB Private Equity •CEO and President, R&B Falcon Corporation, an offshore drilling contractor and successor to Falcon Drilling Company, a drilling company that he founded •Founder or seed investor in numerous other private and public companies, including Grey Wolf, Inc. (a land drilling rig contractor), Hercules Offshore, Inc. (an offshore drilling rig contractor), and Crown Resources Corporation (a precious metals exploration company) |
Steven A. Webster Age: 72 Independent Director since 2019 Committees: •N&ESG •Operations & Reserves |
Other Boards •Independent Director, Camden Property Trust, a publicly traded real estate investment trust (2011 – present) •Independent Director, Oceaneering International, Inc., a subsea engineering and applied technology company (2015 – present) •Former Independent Director and Board Chair, Carrizo Oil & Gas, Inc., a publicly traded oil and gas company that merged with Callon Petroleum Company in 2019 (1993 – 2019) •Former Independent Director, Era Group Inc., a global manufacturing company (2013 – 2020) •Former Independent Director and Board Chair, Basic Energy Services, Inc., a privately held well services contractor •Former Independent Director and Board Chair, Solitario Zinc Corp., a gold, silver, platinum-palladium, and base metal exploration company •Former Independent Director, Brigham Exploration Company, an oil and gas company |
| Qualifications and Expertise Provided to our Board •Distinctive investment experience in energy and other industries that brings valuable insight to the Company’s investment decisions and financial strategies •Over 30 years of board, executive, and investor experience with a large number of publicly and privately held companies in energy and energy-related fields •Extensive entrepreneurial and executive leadership experience in founding and managing multiple companies brings a unique perspective to the Board in strategic, value-based decision making, oversight and risk assessment •Exceptionally deep board experience, including board chair of multiple companies has provided him exposure to strategic decision making and approaches to governance that brings diversity of experience to the Board |
| Education •B.S. in Industrial Management, Purdue University •M.B.A., Harvard University (Baker Scholar) •Honorary Doctorate in Management, Purdue University |
*
Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
The income tax benefit of $189.8 million for the year ended December 31, 2023 differs from income tax expense as calculated using the federal statutory rate primarily as a result of releasing the valuation allowance that was recorded against the Company’s net deferred tax assets. See “— Deferred Tax Asset Valuation Allowance” below for additional details.
As of December 31, 2023 and 2022, the net deferred income tax assets and liabilities are comprised of the following:
| | | | | | | | | | | | | | |
| | As of December 31, |
| | 2023 | | 2022* |
| | (In thousands) |
Deferred tax assets | | | | |
Federal net operating loss carryforward and credits | | $412,401 | | | $359,784 | |
Net interest expense limitation | | 84,202 | | | 74,628 | |
Derivative instruments | | 6,507 | | | 12,758 | |
Operating lease right-of-use assets | | 15,724 | | | 13,180 | |
Asset retirement obligations | | 10,165 | | | 13,049 | |
Unvested RSU equity awards | | 6,214 | | | 5,391 | |
Other | | 4,260 | | | 11,675 | |
Total deferred tax assets | | $539,473 | | | $490,465 | |
Deferred income tax valuation allowance | | — | | | (238,380) | |
Net deferred tax assets | | $539,473 | | | $252,085 | |
Deferred tax liability | | | | |
Oil and natural gas properties | | ($346,050) | | | ($248,508) | |
| | | | |
Operating lease liabilities | | (12,460) | | | (9,885) | |
Total deferred tax liability | | ($358,510) | | | ($258,393) | |
Net deferred tax asset (liability) | | $180,963 | | | ($6,308) | |
*Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information.
Deferred Tax Asset Valuation Allowance
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net deferred tax assets will be utilized prior to their expiration. Beginning in the second quarter of 2020 and through the fourth quarter of 2022, the Company maintained a valuation allowance against its net deferred tax assets. Considering all available evidence (both positive and negative), the Company concluded that it was more likely than not that the deferred tax assets would be realized and released the valuation allowance in the first quarter of 2023. This release resulted in deferred income tax benefit of $187.3 million for the year ended December 31, 2023.
Federal Net Operating Losses (“NOLs”) & Interest Limitation Carryforwards
Due to the issuance of common stock pursuant to the acquisition of Carrizo, the Company incurred a cumulative ownership change, and as such, the Company’s NOLs prior to the acquisition are subject to a combined annual limitation under the IRC Section 382 in the amount of $32.2 million, which is comprised of $15.7 million of Carrizo’s NOLs and $16.5 million of Callon’s NOLs. At December 31, 2023, the Company had approximately $2.0 billion of NOLs of which $399.3 million expire between 2034 and 2037 and $1.5 billion have an indefinite carryforward life. The Company also has a net interest expense carryforward of $401.0 million under Section 163(j) of the Code, subject to indefinite carryforward.
Uncertain Tax Positions
During 2023, the Company recorded a $4.1 million reserve for unrecognized tax benefits related to estimated current year research and development tax credits. If recognized, the net tax benefit of $4.1 million would not have a material effect on the Company's effective tax rate. The Company recognized an immaterial amount of interest associated with the uncertain tax position in income tax expense.
In the Company’s major tax jurisdictions, the earliest year open to examination is 2019.
Note 14 – Leases
The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment. The tables below, which present the components of lease costs and
supplemental balance sheet information, are presented on a gross basis. Other joint owners inCommittees of the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment.Board
The Board of Directors (the “Board”) currently maintains four standing committees: the Audit Committee, the Compensation Committee, the Nominating & ESG Committee, and the Operations & Reserves Committee. The following table below presentsprovides the componentscomposition of the Company’s lease costs for the year ended December 31, 2023.
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| | (In thousands) |
Components of Lease Costs | | | | | | |
Finance lease costs | | $262 | | | $228 | | | $277 | |
Amortization of right-of-use assets (1) | | 251 | | | 203 | | | 237 | |
Interest on lease liabilities (2) | | 11 | | | 25 | | | 40 | |
Operating lease cost (3) | | 49,502 | | | 38,803 | | | 37,734 | |
| | | | | | |
Short-term lease cost (4) | | 24,860 | | | 19,426 | | | 347 | |
Variable lease costs (5) | | 3,327 | | | 2,098 | | | 284 | |
Total lease costs | | $77,951 | | | $60,555 | | | $38,642 | |
(1)Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations.
(2)Included as a component of “Interest expense” in the consolidated statements of operations.
(3)For the years ended December 31, 2023, 2022 and 2021, approximately $42.1 million, $33.3 million and $23.0 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Proved properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations.
(4)Short-term lease cost primarily consists of drilling rigs with contract terms of less than one year.
(5)Variable lease costs include additional payments that were not included in the initial measurementCommittees of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs.
The table below presents supplemental balance sheet information for the Company’s operating leases including the line item in the consolidated balance sheets where each is presented. The Company’s financing leases are immaterial.
| | | | | | | | | | | | | | |
| | As of December 31, |
| | 2023 | | 2022 |
| | (In thousands) |
Leases | | | | |
Operating leases: | | | | |
Other assets, net - Operating lease ROU assets | | $59,268 | | | $47,018 | |
| | | | |
Other current liabilities - Current operating lease liabilities | | $22,070 | | | $40,809 | |
Other long-term liabilities - Long-term operating lease liabilities | | 52,723 | | | 21,882 | |
Total operating lease liabilities | | $74,793 | | | $62,691 | |
The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leasesBoard as of December 31, 2023.March 15, 2024.
| | | | | | | | | | | | | | | | | |
| | December 31, 2023Callon Committees |
Weighted Average Remaining Lease Terms (In years)Name and Independence | Audit | Compensation | N&ESG | Operations & Reserves |
Class I Directors (term expires in 2025) |
| Mary Shafer-Malicki Independent | ○ | | | ● |
| Steven A. Webster Independent | | | ○ | ○ |
Class II Directors (term expires in 2026) |
| Matthew R. Bob Independent | ☐ | ☐ | ☐ | ☐ |
| James E. Craddock Independent | | | ○ | ○ |
| Anthony J. Nocchiero Independent | ○ | ● | | |
Operating leases | | 7.9Class III Directors (term expires in 2024) |
Financing leases | Frances Aldrich Sevilla-Sacasa Independent | ● | | 0.2 |
| | |
Weighted Average Discount Rate○ | | |
Operating leases | Barbara J. Faulkenberry Independent | | 8.9 ○ | %● | |
Financing leases | Joseph C. Gatto, Jr. President and Chief Executive Officer | | | | |
6.6●
| %Chair ○Member ☐Non-Voting Member |
Audit Committee
The Audit Committee currently consists of Mses. Aldrich Sevilla-Sacasa (Chair) and Shafer-Malicki, and Messrs. Nocchiero and Bob (non-voting member). Membership on the Audit Committee is limited to independent directors, and the Board has determined that all members meet the independence requirements of the SEC and New York Stock Exchange (the “NYSE”) rules and the financial literacy requirements of the NYSE. The Board has also determined that all members of the Audit Committee are sufficiently proficient in reading and understanding financial statements to serve on the Audit Committee, that each of Ms. Aldrich Sevilla-Sacasa and Mr. Nocchiero qualifies as an “audit committee financial expert” under the rules of the SEC, and that all members meet the “financial literacy” standard as defined under the NYSE Listed Company Manual. Members of the Audit Committee may not simultaneously serve on the audit committee of more than two other public companies.
The Audit Committee held five meetings in 2023. The Board has adopted a separate written charter for the Audit Committee, which is available at www.callon.com.
Compensation Committee
The Compensation Committee currently consists of Mses. Aldrich Sevilla-Sacasa and Faulkenberry, and Messrs. Nocchiero (Chair) and Bob (non-voting member). Consistent with the listing requirements of the NYSE, the Compensation Committee is composed entirely of independent members of the Board, as each member meets the independence requirements set by the NYSE and applicable federal securities laws.
The Compensation Committee held nine meetings in 2023. The Board has adopted a separate written charter for the Compensation Committee, which is available at www.callon.com.
Nominating & ESG Committee
The
table below presents the maturityNominating & ESG Committee currently consists of Ms. Faulkenberry (Chair) and Messrs. Craddock, Webster, and Bob (non-voting member). Each member of the
Company’s lease liabilities asN&ESG Committee meets the independence requirements of
December 31, 2023. | | | | | | | | | | | | | | |
| | Operating Leases | | Financing Leases |
| | (In thousands) |
2024 | | $27,207 | | | $38 | |
2025 | | 8,066 | | | — | |
2026 | | 9,439 | | | — | |
2027 | | 9,526 | | | — | |
2028 | | 9,645 | | | — | |
Thereafter | | 42,528 | | | — | |
Total lease payments | | 106,411 | | | 38 | |
Less imputed interest | | (31,618) | | | — | |
Total lease liabilities | | $74,793 | | | $38 | |
Note 15– Asset Retirement Obligationsthe NYSE and applicable federal securities laws.
The table below summarizes the activityNominating & ESG Committee held seven meetings in 2023. The Board has adopted a separate written charter for the Company’s asset retirement obligations:Nominating & ESG Committee, which is available at www.callon.com.
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022 |
| | (In thousands) |
Asset retirement obligations, beginning of period | | $60,435 | | | $56,707 | |
Accretion expense | | 3,465 | | | 3,997 | |
Liabilities incurred | | 2,379 | | | 669 | |
Increase due to acquisition of oil and gas properties | | 2,323 | | | — | |
Liabilities settled | | (4,228) | | | (2,008) | |
Dispositions | | (25,551) | | | (4,760) | |
Revisions to estimates | | 8,256 | | | 5,830 | |
Asset retirement obligations, end of period | | 47,079 | | | 60,435 | |
Less: Current asset retirement obligations | | (4,426) | | | (6,543) | |
Non-current asset retirement obligations | | $42,653 | | | $53,892 | |
Operations & Reserves CommitteeCertainThe Operations & Reserves Committee currently consists of Ms. Shafer-Malicki (Chair) and Messrs. Craddock, Webster, and Bob (non-voting member). Each member of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded onOperations & Reserves Committee meets the consolidated balance sheets at December 31, 2023 and 2022 as long-term restricted investments were $3.5 million, and are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for severalindependence requirements of the Company’s oilNYSE and natural gas properties.applicable federal securities laws.
The Operations & Reserves Committee held six meetings in 2023. The Board has adopted a separate written charter for the Operations & Reserves Committee, which is available at www.callon.com.
Code of Business Conduct and Ethics
Our Code of Business Conduct and Ethics (the “Code”) sets forth the policies and expectations for Callon’s officers, employees and directors as well as consultants, representatives, agents, and contractors while acting on Callon’s behalf. The Code addresses a number of topics including conflicts of interest, compliance with laws, insider trading, prohibitions on discrimination and harassment, workplace safety and protection of the environment, and fair disclosure. In addition, the Code explicitly prohibits directors, officers and employees from engaging in hedging transactions in Callon stock. It also states that no corporate funds may be used for political contributions.
The Code meets the NYSE’s requirements for a code of business conduct and ethics and also includes a code of ethics applicable to our senior financial officers consistent with the requirements of the SEC. A copy of the Code is available on our website at www.callon.com/about-callon/governance. We intend to satisfy the disclosure requirements regarding any amendment to, or any waiver of, a provision of the Code by promptly posting such information on our website. Concerns about potential violations of the Code can be anonymously reported to our ethics helpline by calling 1-844-471-7637 or accessing the following website: callon.ethicspoint.com.
Note 16 – Accounts Receivable, Net
| | | | | | | | | | | |
| As of December 31, |
| 2023 | | 2022 |
| (In thousands) |
Oil and natural gas receivables | $132,332 | | | $174,107 | |
Joint interest receivables | 34,555 | | | 16,778 | |
Other receivables | 41,072 | | | 48,277 | |
Total | 207,959 | | | 239,162 | |
Allowance for credit losses | (1,168) | | | (2,034) | |
Total accounts receivable, net | $206,791 | | | $237,128 | |
Note 17 – Accounts Payable and Accrued Liabilities | | | | | | | | | | | |
| As of December 31, |
| 2023 | | 2022 |
| (In thousands) |
Accounts payable | $204,339 | | | $191,133 | |
Revenues and royalties payable | 226,804 | | | 244,408 | |
Accrued capital expenditures | 59,599 | | | 58,395 | |
Accrued interest | 35,704 | | | 42,297 | |
Total accounts payable and accrued liabilities | $526,446 | | | $536,233 | |
Note 18–CommitmentsITEM 11. Executive Compensation
Compensation Discussion and ContingenciesAnalysis
The Company is involved2023 Named Executive Officers
Our named executive officers (“NEOs”) include the individuals who served as the Company’s Chief Executive Officer or Chief Financial Officer during 2023 and the three other most highly compensated executive officers who were serving in various claims and lawsuits incidental to its business. Insuch capacity at the opinionend of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.2023.
The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made,Our former Chief Operating Officer, Dr. Jeffrey S. Balmer, retired from the Company believes that, absentin June 2023, and Russell E. Parker was appointed Chief Operating Officer as of June 28, 2023. The Compensation Committee (the “Committee”) reviewed and approved Mr. Parker’s initial compensation package as described in this CD&A and also authorized the occurrence of an extraordinary event, compliance with existing federal, stateSeparation Agreement and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position ofConsulting Agreement between the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder,Dr. Balmer as described below under the heading “Employment Agreements, Termination of Employment and claimsChange in Control Arrangements - Separation Agreement.” Despite his retirement, Dr. Balmer meets the requirement of a NEO for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.
The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements which require minimum volumes of oil, natural gas, or produced water to be delivered and other purchase obligations, as of December 31, 2023.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 | | 2027 | | 2028 | | 2029 and Thereafter | | Total |
| | (In thousands) |
Office space | | $5,203 | | | $6,280 | | | $9,409 | | | $9,526 | | | $9,645 | | | $41,883 | | | $81,946 | |
Drilling rig and frac service commitments (1) | | 41,875 | | | — | | | — | | | — | | | — | | | — | | | 41,875 | |
Pipeline transportation commitments (2) | | 34,155 | | | 35,196 | | | 35,196 | | | 25,553 | | | 23,202 | | | 85,143 | | | 238,445 | |
Produced water disposal commitments (3) | | 8,532 | | | 4,509 | | | 569 | | | 113 | | | — | | | — | | | 13,723 | |
Purchase obligations (4) | | 9,004 | | | 8,980 | | | 8,980 | | | 8,980 | | | 9,004 | | | 4,030 | | | 48,978 | |
Other operating leases | | 3,098 | | | 1,786 | | | 30 | | | — | | | — | | | 646 | | | 5,560 | |
Total | | $101,867 | | | $56,751 | | | $54,184 | | | $44,172 | | | $41,851 | | | $131,702 | | | $430,527 | |
Our NEOs for 2023 were: | | | | | | | | |
NEO | Age(a) | Title |
Joseph C. Gatto, Jr. | 53 | President, Chief Executive Officer and Director |
Kevin Haggard | 53 | Senior Vice President and Chief Financial Officer |
Russell E. Parker(b) | 47 | Senior Vice President and Chief Operating Officer |
Michol L. Ecklund | 49 | Senior Vice President, Chief Sustainability Officer, General Counsel and Corporate Secretary |
Gregory F. Conaway | 48 | Vice President and Chief Accounting Officer |
Jeffrey S. Balmer(b) | 59 | Former Senior Vice President and Chief Operating Officer |
(a) As of March 15, 2024.
(b) Dr. Balmer retired from the Company in June 2023. The Company named Russell E. Parker as Senior Vice President and Chief Operating Officer effective June 28, 2023.
Executive Compensation Philosophy
Our executive compensation program is designed to achieve the following objectives:
•Emphasize pay for performance, in which Company and individual performance against preset goals are inherently linked to the amount realized by a NEO;
•Attract and retain a qualified and motivated management team by offering industry competitive opportunities and providing the majority of NEO compensation in the form of long-term incentives that vest over a three-year period;
•Incentivize NEOs and appropriately reward them for their contributions to the achievement of our key short-term and long-term strategic objectives with variable compensation; and
•Align the compensation of our NEOs with the interests of our long-term shareholders by providing 60% of the LTI mix in the form of performance-based incentives and 40% in the form of RSUs.
Executive Pay Program and Decisions
Base Salaries
We provide our employees, including the NEOs, with an annual base salary that is reflective of individual skills, scope of responsibility, experience and expertise to compensate them for their service throughout the year. The Committee evaluates our NEOs’ salaries and other components of their compensation to ensure that the NEOs’ total compensation is competitive relative to market practices, reflective of the executive’s performance and value to the Company, and consistent with the Committee’s compensation philosophy. In early 2023, the Committee established base salaries for each of the NEOs as set forth in the table below with the input of its independent compensation consultant.
Increases in base salary ranged from 5% to 17% for our NEOs. Mr. Haggard received a 15% increase to reflect his continued growth in the role and to better position the executive versus the market median. Mr. Conaway received a 17% increase to recognize expansion in his responsibilities and strong individual performance and to better position the executive versus the market median.
| | | | | | | | | | | | | | | | | | | | |
NEO | 2022 Base Salary | 2023 Base Salary |
Joseph C. Gatto, Jr. | | $ | 908,250 | | | | $ | 952,000 | | |
Kevin Haggard | | $ | 485,000 | | | | $ | 560,000 | | |
Russell E. Parker | | N/A | | | $ | 600,000 | | |
Michol L. Ecklund | | $ | 455,000 | | | | $ | 484,000 | | |
Gregory F. Conaway | | $ | 325,000 | | | | $ | 379,000 | | |
Jeffrey S. Balmer | | $ | 535,000 | | | | $ | 560,000 | | |
Performance-Based Annual Cash Bonus Incentive
Each year, the Committee establishes an annual incentive bonus program that is designed to align NEO compensation with the annual business plan and strategic priorities for the year. When establishing the annual bonus program for 2023, the Committee approved the following annual incentive bonus opportunities for the NEOs. | | | | | | |
NEO | | 2023 Target Bonus Opportunity (% of Base Salary)(1) |
Joseph C. Gatto, Jr. | | 125% |
Kevin Haggard | | 90% |
Russell E. Parker | | 95% |
Michol L. Ecklund | | 90% |
Gregory F. Conaway | | 75% |
Jeffrey S. Balmer | | 95% |
(1)Drilling rig and frac service commitments represent gross contractual obligations and accordingly, other joint owners inActual bonus awards under the properties operatedprogram can range from 0 - 200% of target based on the achievement of pre-established performance metrics as described below.
2023 Annual Bonus Metrics
The performance metrics established by the Company will generally be billedCommittee for their working interest share of such costs.
(2)Pipeline transportation commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts2023 annual bonus program are shown in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas.below. These metrics are intended to directly align executive compensation opportunities with investor and Company priorities for financial and sustainability performance to support long-term value creation for shareholders. The Committee established a 2023 annual bonus program to:
•Focus on pay-for-performance by maintaining 80% weighting on quantitative metrics;
(3)•Produced water disposal commitments represent contractual obligationsPrioritize financial results by tying 65% of the Company has entered into for certain service agreements which require minimum volumes of produced waterprogram to be delivered. The amounts infinancial metrics and excluding traditional operational metrics from the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.program;
(4)•Purchase obligations represent multi-yearAlign incentive payouts with the shareholder experience by including a relative total shareholder return (“TSR”) comparison to the companies within the XOP energy purchase agreements the Company has entered into to lock in rates for electricity utilized in its operations. Under these contracts, the Company is obligated to purchase a minimum supply of electricity at a fixed price. If the Company does not utilize the minimum amounts of electricity on a monthly basis, the supplier would sell the underutilized quantity at the then market price. The amounts in the table above reflect the aggregate undiscounted financial commitments pursuant to these purchase agreements.index; and
Other Commitments•Support our sustainability objectives by including a quantitative sustainability category (weighted 15%) and aligning with long-term sustainability objectives within the qualitative component of the program.
The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2023:
| | | | | | | | | | | |
| Objective | Description | Weighting |
Quantitative Objectives - Financial (65%) | Net Debt/Adjusted EBITDAX(i) | Measure of our ability to cover our debt, which is impacted by cash flow, and ensures focus on a strong balance sheet | 20% |
Capital Efficiency (Adjusted Free Cash Flow/Adjusted EBITDAX)(ii) | Measure of efficiency for converting earnings into Adjusted Free Cash Flow for shareholder value initiatives | 20% |
Operating Cash Margin(iii) | Measure of revenue and cost management to support near-term cash flow | 15% |
TSR vs. XOP Peers | Measure of competitiveness of shareholder return relative to competing investor alternatives | 10% |
Quantitative Objectives - Sustainability (15%) | Environmental - Flaring Intensity (volumes flared / gas produced) | Measure of one component of GHG emissions that represents potential lost revenue due to flaring | 5% |
Environmental - GHG Intensity (mtCO2e/MBOE) | Progress on GHG emissions intensity reduction goals as measured by year-end exit rate | 5% |
Safety(iv) | Measure of rate of occurrence and severity of injuries throughout our workforce | 5% |
Qualitative Objectives (20%) | Other key organizational mandates | Measure of our success relative to key objectives tied to human capital initiatives, digital transformation, corporate cost of capital reduction, life-of-field development model, long-term strategy, regulatory and sustainability developments, and management of unforeseen industry events | 20% |
(i) Net Debt to Adjusted EBITDAX is calculated as the sum of total long-term debt less unrestricted cash and cash equivalents divided by Adjusted EBITDAX. See Appendix A for a reconciliation of non-GAAP financial measures.
(ii) Capital Efficiency is defined as Adjusted Free Cash Flow divided by Adjusted EBITDAX.
(iii) Operating Cash Margin is oil, natural gas and NGL revenues sales price less lease operating expense, production and ad valorem taxes and gathering, transportation and processing fees divided by total production.
(iv) Includes measures related to total reportable incident rates, zero level 4 or 5 severe injury incidents, potential serious incident and fatality events, and tier 1 process safety events.
For the financial elements of the program, the Committee selected metrics to align with evolving investor priorities for the energy industry, including strong balance sheets, capital efficiency, and free cash flow generation, all of which support a pathway to potential returns of capital. In addition, the Committee incorporated a relative TSR metric that compared the Company’s stock price performance for the year to those of representative companies across the energy value chain as represented in the XOP index. The Committee also established quantitative sustainability metrics to align with safety and environmental priorities.
To establish the threshold, target and maximum goals for each financial metric at the beginning of the year, the Committee sought to align the goals with publicly stated guidance for the year and then considered sensitivities for key performance variables and for commodity prices (based on probabilistic commodity price scenarios for the year based on the NYMEX options market), to arrive at a range of potential outcomes. In each instance, the Committee adopted an expanded upside range to align maximum goals with “stretch” performance.
2023 Performance Results
After the close of the 2023 calendar year, the Committee assessed the Company’s and the NEOs’ annual performance overall and relative to the frameworks established for the annual incentive compensation program as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
Quantitative Objective | Weighting | Threshold | Target | Max | Actual Results 12/31/2023 | Performance Factor | Funding Level |
Net Debt/Adjusted EBITDAX(i) | 20% | 1.5x | 1.3x | 1.0x | 1.46x | 61% | 12% |
Capital Efficiency(ii) | 20% | 17% | 25% | 35% | 14.2% | 0% | 0% |
Operating Cash Margin(iii) | 15% | $38.00 | $41.00 | $46.00 | $38.01 | 50% | 8% |
TSR vs. XOP(iv) | 10% | P30 | P50 | P90 | P31 | 50% | 5% |
Sustainability | | | | | | | |
Flaring (Mcf/Bbl) | 5% | ≤1.0% | 1.0% | 100% | 5% |
GHG Intensity - Exit Rate (mtCO2e/MBOE) | 5% | <15.0 | 11.1 | 200% | 10% |
Safety TRIR Zero level 4 or 5 injury incidents Potential SIFs Tier 1 process safety events | 5% | <0.48 0 ≤3 ≤3 | 0.51 0 1 3 | 50% 100% 150% 100% | 5% |
Total Quantitative | 80% | | | | | | 45% |
(i) Net Debt to Adjusted EBITDAX is calculated as the sum of total long-term debt less unrestricted cash and cash equivalents divided by Adjusted EBITDAX. See Appendix A for a reconciliation of non-GAAP financial measures.
(ii) Cash Efficiency is defined as Adjusted Free Cash Flow divided by Adjusted EBITDAX.
(iii) Operating Cash Margin is oil, natural gas and NGL revenues sales price less lease operating expense, production and ad valorem taxes and gathering, transportation and processing fees divided by total production.
(iv) For purposes of calculating relative TSR, the Committee excluded from the final calculation four XOP companies who were acquired during the measurement period.
When determining the weighted contribution for the qualitative component of the program for 2023, the Committee considered Callon’s and management’s performance overall and relative to the qualitative performance factors set forth in the table below. The Committee determined that the management team met or exceeded expectations relative to the established qualitative goals. The Committee also considered additional strategic accomplishments by the management team in 2023, including the simultaneous closing of the Delaware Basin asset acquisition and Eagle Ford sale to streamline operational focus and improve the balance sheet, the initiation of a return of capital program, and the successful execution of a company-wide reorganization that has led to meaningful reductions in the Company’s capital cost structure and improvements in well performance that are driving capital efficiency for 2024 and beyond. The Committee also considered management’s efforts throughout the year to assess various options and engage with multiple potential counterparties throughout the year to evaluate the Company’s long-term strategic alternatives in light of rapid industry consolidation.
In considering the totality of these qualitative factors, the Committee elected to fund the qualitative component of the annual bonus program at 40%.
| | | | | |
Goals | Results |
Human capital initiatives | • 2023 hiring initiatives increased racial/ethnic diversity to 43% and gender diversity to 25%, including the addition of two new diverse female officers • Facilitated a company-wide reorganization and supported over 30% of employees into new development roles |
Sustainability initiatives | • Achieved corporate GHG goals one year early • Successfully established Sustainability organization • Advanced the long-term GHG investment framework with marginal cost of carbon abatement and forecasting tools and prepared for anticipated environmental regulatory developments |
Improving corporate cost of capital | • Initiated a shareholder return of capital program, repurchasing more than $50 million in equity • Reduced absolute debt by $325 million, improved credit metrics and achieved upgrades with credit ratings agencies Fitch and S&P |
Digital transformation | • Successfully implemented a new architecture data framework with widely-available operational and financial dashboards • Increased automation of core processes • Enhanced cybersecurity infrastructure and response plans |
Evaluate evolving industry landscape | • Closed accretive Delaware Basin acquisition and Eagle Ford sale to streamline operational focus and improve balance sheet • Conducted extensive market reviews and counterparty engagements throughout the year to evaluate options in light of rapid industry consolidation |
Advance life-of-field development model and delineation of organic resource opportunities | • Expand strategies to increase inventory and net revenue interest via organic and inorganic opportunities • Continue to improve upon strategic planning baseline and robust scenario analysis for capital allocation |
2023 Annual Incentive Compensation Payouts
Based on the Committee’s assessment of 2023 performance relative to the pre-established annual bonus programs as described above, the Committee awarded annual incentive compensation payouts of 85% of target for the NEOs, other than Dr. Balmer. Accordingly, individual bonus payouts for 2023 were as follows:
| | | | | | | | | | | | | | |
NEO | Payout as a % of Target | 2023 Annual Bonus |
Joseph C. Gatto, Jr. | 85% | | $ | 1,011,500 | | |
Kevin Haggard | 85% | | $ | 428,400 | | |
Russell E. Parker | 85% | | $ | 484,500 | | |
Michol L. Ecklund | 85% | | $ | 370,260 | | |
Gregory F. Conaway | 85% | | $ | 241,613 | | |
Jeffrey S. Balmer(a) | —% | | $ | — | | |
(a) Per the terms of Dr. Balmer’s Separation Agreement, Dr. Balmer did not receive a 2023 Annual Bonus.
Annual Award of Long-Term Incentives
In the first quarter of 2023, the Committee considered the design of the long-term incentive compensation awards for the upcoming year with the input of FW Cook. The Committee continued the core structure of the refreshed incentive design adopted in 2021, as well as the evolution adopted in 2022 to better link the program to sustainability performance by incorporating long-term GHG reduction goals.
The Committee adopted a 2023 long-term incentive program that incorporated two elements:
| | | | | | | | |
Type of Commitment (1)
| | Start DateLTI Vehicle | | End DateWeighting | | Committed Volumes (Bbls/d) |
Oil sales contract | | January 2024 | | March 2024 | | 10,000 |
Oil sales contract | | January 2024 | | December 2024 | | 15,000 |
Oil sales contract | | February 2022 | | January 2027 | | 5,000 |
Oil sales contract | | January 2020 | | December 2024 | | 10,000Objective |
Firm transportation agreement (2)(3)Cash Performance Units
(Three-year Cliff Vest) | | August 202060% | | July 2030 | | 11,140• Reward for adjusted free cash flow generation • Align with long-term Return on Capital Employed results • Tie a portion of compensation to our three-year GHG reduction targets |
Firm transportation agreement (2)Time-Based RSUs
(Three-year Ratable Vest) | | April 202040% | | March 2027 | | 15,000 |
Firm transportation agreement (2)• Create direct alignment with shareholder interests
| | April 2020 | | March 2027 | | 10,000• Provide direct retention incentives for our executives |
(1)For eachthe grant of LTI awards to NEOs, the Committee considers market analysis and the advice of its independent compensation consultant to determine the program design and target award amounts. For 2023, the Committee increased the target award value for the CEO by 14% and for the NEOs by 18% on average, including Dr. Balmer. These increases were intended to recognize expanded responsibilities for Mr. Conaway and strong individual performance for all of the commitments shownexecutives.
| | | | | | | | | | | | | | | | | | | | |
NEO | 2022 Target Value(a) | 2023 Target Value(a) |
Joseph C. Gatto, Jr. | | $ | 4,290,000 | | | | $ | 4,899,000 | | |
Kevin Haggard | | $ | 1,800,000 | | | | $ | 2,177,000 | | |
Russell E. Parker | | $ | — | | | | $ | 2,400,000 | | |
Michol L. Ecklund | | $ | 1,350,000 | | | | $ | 1,457,000 | | |
Gregory F. Conaway | | $ | 525,000 | | | | $ | 729,000 | | |
Jeffrey S. Balmer(b) | | $ | 2,060,000 | | | | $ | 2,120,000 | | |
(a) Represents the intended target value of the awards, which is different from the grant date fair value computed in accordance with FASB ASC Topic 718 as reported in the table above,Summary Compensation Table. The methodology adopted by the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expectCommittee for awarding LTI equity awards uses the 20-day average closing price of Callon stock as of the grant date to fulfill these delivery commitments with our existing production or throughdetermine the purchasesnumber of third-party commodities.RSUs granted.
(2)(b) EachDr. Balmer ceased serving as Senior Vice President and Chief Operating Officer for the Company effective June 28, 2023, due to his retirement, and the RSUs granted to Dr. Balmer on March 2, 2023, were forfeited.
The target LTI values were delivered to each NEO as a grant of RSUs for 40% of the firm transportation agreements showntarget value and grant of cash performance units (“CPUs”) for 60% of the target value as described in more detail below.
RSU Program
In 2023, the table above grant us accessCommittee awarded each NEO with time-based RSUs that will vest annually in one-third increments beginning on April 15, 2024, provided the NEO continues to delivery pointsbe employed by the Company on each applicable vesting date. The RSUs will be settled in several locations alongshares of Callon’s common stock. In June 2023, upon his commencement of employment with Callon, the Gulf Coast. The costs associatedCommittee awarded Mr. Parker with these agreements are recorded30,318 time-based RSUs as an inducement and retention award. These RSUs will vest in full on July 1, 2026, provided he continues to “Gathering, transportationbe employed by the Company on the vesting date. In September 2023, upon her promotion to Chief Sustainability Officer, the Committee awarded Ms. Ecklund with 20,000 time-based RSUs to recognize her expanded responsibilities. These RSUs will vest in full on October 1, 2026, provided she continues to be employed by the Company on the vesting date.
Cash Performance Units
In 2023, the Committee continued its use of CPUs. Each CPU has a target value of $1 and processing”will pay out in cash within the Company’s consolidated statementsrange of operations.0-200% of target based on Company results relative to pre-established performance targets for the 2023-2025 calendar years.
(3)
The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2023-July 2027 and August 2027-July 2030, the committed volumes are 10,000 Bbls/d and 12,500 Bbls/d, respectively.
The 2023 CPUs are comprised of the following table includes the Company’s current natural gas firm transportation agreements as of December 31, 2023:two components:
| | | | | | | | | | | |
CPU | Objective | Description | Measurement |
Business Sustainability CPUs (70% of target CPU value) | Adjusted Free Cash Flow | Key investor priority providing a clear path to absolute debt reduction and cash return to shareholders over time | Three, one-year performance periods with the opportunity to earn between 0% and 200% of target |
GHG Intensity | Based on Year 3 performance of GHG intensity | Modifier, which adjusts the overall payout between 80% and 120% based on achievement of our 2025 GHG intensity target |
Return CPUs (30% of target CPU value) | Return on Capital Employed (“ROCE”) | Profitability metric that allows for comparability to cost of capital and returns across sectors | Three-year average ROCE performance relative to established goals, including a threshold goal requiring three-year ROCE of at least 10% |
Performance Based Special Purpose Equity Award for Our CEO
In April 2023, to provide additional equity ownership and retention as well as further alignment with shareholder interests, the Committee awarded 100,000 Market Stock Units (“MSUs”) to Mr. Gatto. The MSUs will vest based on the Company’s annualized absolute TSR over a 36- month performance period (May 1, 2023 to April 30, 2026), calculated based on the 20-day average closing stock price at the beginning and end of the performance period. No other executive officers or directors hold MSUs. The MSUs are eligible to vest, subject to Mr. Gatto’s continued employment with the Company until the end of the performance period (April 30, 2026), and will settle in shares of Callon’s common stock. The number of MSUs to be issued at the end of the performance period will be determined by multiplying the target number of MSUs by a multiplier between 0% and 150%, as set forth in the table below based on the Company’s annualized absolute TSR for the performance period. In the event the annualized absolute TSR is between the performance levels show below, the number of MSUs that will performance vest will be determined through linear interpolation:
| | | | | |
Callon’s Annualized Absolute TSR During the Performance Period | Modifier |
50% or greater | 150% |
15% | 100% |
-25% | 50% |
Less than -25% | 0% |
Vesting of 2021-2023 Cash Performance Units
In 2021, the Committee granted cash performance units to the then-executive officers covering a three-year performance period beginning in 2021 and ending in 2023. The Company’s adjusted free cash flow and ROCE for the performance period relative to the goals established in advance by the Committee resulted in the 2021 CPUs vesting at 103% of target. The table below provides the associated cash payments that were made to the NEOs in March of 2024:
| | | | | | | | | | | |
NEO | Target Value of CPUs | Payout as a % of Target | Payout Value of CPUs |
Joseph C. Gatto, Jr. | $2,340,000 | 103% | $2,410,818 |
Kevin Haggard | $877,500 | 103% | $904,057 |
Russell E. Parker(a) | $— | —% | $— |
Michol L. Ecklund | $733,950 | 103% | $756,162 |
Gregory F. Conaway | $286,380 | 103% | $295,047 |
Jeffrey S. Balmer(b) | $1,164,975 | —% | $— |
(a) Mr. Parker was not employed by the Company on March 12, 2021, when the awards were granted.
(b) Dr. Balmer ceased serving as Senior Vice President and Chief Operating Officer for the Company effective June 28, 2023. Pursuant to his Separation Agreement and the terms and conditions of his 2021 Cash Performance Units, Dr. Balmer received payment of $1,295,179 as
“Qualified Retirement” benefits under the CPU Agreement. See “Employment Agreements, Termination of Employment and Change in Control Arrangements” for additional details.
Perquisites and Other Benefits
Benefits represent a relatively small part of our overall compensation package; however, these benefits help attract and retain senior level executives. We provide benefits commonly offered in the E&P industry to all of our employees, including our NEOs, and review these benefits annually to ensure that they are competitive with industry norms. These benefits consist of:
•Group medical and dental insurance program for employees and their qualified dependents;
•Group life insurance for employees and their spouses;
•Accidental death and dismemberment coverage for employees;
•Short-term disability coverage;
•Long-term disability coverage;
•Callon’s sponsored cafeteria plan; and
•401(k) employee savings and protection plan (the “401(k) plan”).
We pay the full costs of these benefits, including the 401(k) plan administration, for all employees.
Under our 401(k) plan, all eligible employees may elect to defer a portion of their compensation up to the statutorily prescribed limit. In 2023, the Company provided a matching contribution of up to 6% and a profit sharing contribution of up to 2% of the employee’s IRS eligible salary for qualified employees, including our NEOs.
Our NEOs are entitled to certain benefits that are not otherwise available to all of our employees. Until the program was terminated in early 2023 by the Committee, we provided our NEOs with the use of a Company vehicle, which included the purchase or lease of the vehicle and the payment for all maintenance, repairs, insurance, and fuel. Each NEO is required to recognize taxable income using the IRS’s annual lease value method for personal use of the vehicle. As part of the executive officer vehicle plan termination, the Committee approved supplemental salary payments to the NEOs who were impacted by the plan termination (please see “Executive Compensation Tables - Table of All Other Compensation for 2023” below). We also reimburse our NEOs for their out-of-pocket cost of an executive physical, up to $2,500. The costs associated with these benefits for the NEOs are reported as “All Other Compensation” in the Summary Compensation Table. The Committee believes these perquisites are modest, yet competitive when compared to the perquisites provided to similarly situated industry executives.
We do not sponsor any qualified or non-qualified defined benefit plans, or any non-qualified defined contribution plan for our NEOs or other employees.
Change in Control; Severance and Retirement Arrangements; Employment Agreements
We have no employment agreements with our NEOs. Our NEOs participate in the Callon Executive Change in Control Severance Plan (the “Executive CIC Plan”), which provides for certain protections upon a change in control, and the Callon Executive Severance Pay Plan (the “Severance Pay Plan”), which provides for certain protections upon an involuntary termination of employment. The Committee believes that the Executive CIC Plan and the Severance Pay Plan serve shareholders’ best interests by aligning executive interests with shareholders, helping ensure retention of management and diminishing potential distractions for our executive officers in the event of an involuntary termination of employment or change in control transaction. However, the Committee believes that executives should not be unduly enriched, and all benefits under the Executive CIC Plan and Severance Pay Plan require a “double-trigger.” For a detailed description of the Executive CIC Plan and the Severance Pay Plan, please see “Employment Agreements, Termination of Employment and Change in Control Arrangements - Executive Severance Compensation Plans” below.
Our NEOs may also receive retirement benefits under the RSU Agreements (as defined below) and the CPU Agreements (as defined below) for the purposes of attracting and retaining top talent and incentivizing early notice of impending retirements to ensure smooth transitions. For a detailed description of the retirement benefits, which are available at the discretion of the Committee to eligible officers who provide at least six months’ notice prior to retirement, please see “Employment Agreements, Termination of Employment and Change in Control Arrangements - Long-Term Incentive Award Agreements” below.
How We Make Compensation Decisions
Role of Independent Compensation Consultant
For 2023, the Committee continued its engagement of FW Cook as its independent compensation consultant to provide information and objective advice regarding executive officer and director compensation.
The Committee makes all final decisions with respect to our executive compensation. When designing pay programs and setting compensation levels for our NEOs, the Committee considers the independent compensation consultant’s advice as one factor among many other factors discussed within this CD&A. Other factors include our overall Company performance; individual NEO performance, experience, skills and tenure with the Company; competitive market data; and industry trends.
The compensation consultant reports solely to the Committee, and the Committee determines the scope of the engagement. In an effort to ensure that our NEO compensation programs are competitive and consistent with our compensation philosophy, FW Cook assists the Committee as follows:
•Regularly attending meetings of the Committee and meeting privately in executive session with the Committee to discuss its recommendations;
•Providing recommendations on executive compensation matters to align the Committee’s actions with shareholder interests, our business strategy and pay philosophy, prevailing market practices and relevant legal and regulatory requirements;
•Periodically evaluating our peer group and providing peer company data for the Committee to use in its decision-making process, including assessment of pay and performance relative to peers;
•Providing competitive market data to consider in evaluating the competitiveness of the executive base salaries and short- and long-term incentive plans and awards;
•Reviewing data in connection with the Committee’s determination of annual cash incentive performance objectives and performance-based incentive vesting levels for completed performance periods;
•Advising on Callon’s compensation arrangements for its non-employee directors, including providing peer group data;
•Reviewing and providing feedback on our SEC filings relating to executive compensation disclosures, including our CD&A disclosures; and
•Informing the Committee about compensation trends in the industry, best practices and other general trends and developments affecting executive compensation.
The Committee has the final authority to hire and terminate the compensation consultant, and the Committee evaluates the consultant’s performance annually.
Pursuant to applicable SEC and NYSE rules, the Committee has determined that no conflicts of interest existed related to FW Cook’s engagement by the Committee in 2023.
Role of Management
The Committee considers input from our CEO in making determinations regarding our executive compensation program and the individual compensation of each of the executives other than himself. The officer team makes recommendations to the Committee regarding potential objectives for the incentive programs and provides information to the Committee regarding the performance of the Company for the Committee’s determination of incentive compensation outcomes. The Committee makes the final determination of all elements of NEO compensation. Our CEO makes no recommendations regarding, and does not participate in discussions about, his own compensation.
Role of Market Data
The Committee reviews compensation of our NEOs annually. Individual compensation amounts reflect the Committee’s subjective analysis of a number of factors, including:
•The NEO’s experience, skills, contributions and tenure with Callon;
•Changes to the NEO’s position within Callon;
•Competitive market data within our peer group and industry; and
•The NEO’s roles, responsibilities and expected future contributions to Callon’s success.
On an annual basis, the Committee reviews and discusses compensation data for our CEO and other NEOs as compared with compensation data for similarly situated executive officers at peer companies recommended by the compensation consultant and approved by the Committee. The peer group is selected based on multiple factors, such as:
•Size, including enterprise value and market capitalization;
•Similar geographic footprint and operational focus;
•Comparability of asset portfolio;
•Competition for executive talent in the market; and
•Availability of compensation data.
The Committee believes the selected peer group provides a reasonable point of reference for comparing the compensation of our NEOs to others holding similar positions and having similar responsibilities. The Committee does not consider data collected from any source to be prescriptive. Rather, the Committee relies upon this and similar data as reference points around which to make informed decisions about the appropriate level and form of compensation for each NEO. The peer group used by the Committee in evaluating the competitiveness of executive compensation and making 2023 compensation decisions consisted of the companies set forth in the following table.
| | | | | | | | |
| Type of Commitment (1)(2)
| | Start Date |
End Date | | Committed Volumes (MMBtu/d)2023 Compensation Peer Group |
Firm transportation agreement• Centennial Resource Development, Inc. • Civitas Resources, Inc. • CNX Resources Corporation • Comstock Resources, Inc. • Earthstone Energy, Inc. | | October 2023• Kosmos Energy Ltd. • Laredo Petroleum, Inc. • Matador Resources Company • Murphy Oil Corporation | | • Range Resources Corporation • SM Energy Company • Southwestern Energy Company • Talos Energy Inc. September 2033
| | 50,000 |
| Firm transportation agreement | October 2023 | | September 2033 | | 15,000 |
| Firm transportation agreement
| | July 2024 | June 2034 | | 10,000 |
Practices and Policies Related to Compensation
Stock Ownership Guidelines
Consistent with its goal of driving long-term value creation for our shareholders, the Company’s stock ownership guidelines require significant stock ownership by the executive officers and directors. The guidelines require the executive officers and directors to hold the following amounts of our stock:
| | | | | |
Executive Officers/Directors | Required Common Stock Ownership as a Multiple of Annual Base Salary / Annual Retainer |
CEO | 6x |
Directors | 5x |
Other Executive Officers | 2x |
The Committee evaluates compliance with these guidelines on an annual basis. For purposes of the guidelines, shares owned directly and indirectly and any unvested time-based RSUs are included. Pursuant to the policy, shares granted under the Company’s incentive compensation plans are valued at the greater of the then-current trading price or the value on the date of grant.
Each executive officer and director has a transition period of five years from the date the individual becomes subject to the guidelines to attain the required investment position. If an executive officer becomes subject to a greater ownership requirement due to a promotion or an increase in salary, the executive officer will be expected to attain the higher level within three years of the change.
As of December 31, 2023, all participants were in compliance with the stock ownership policy, either through meeting the ownership requirement or by being within the transition period.
Internal Revenue Service Limitations
Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Tax Code”) places a limit of $1.0 million on the amount of compensation that we may deduct in any one year with respect to compensation paid to each covered employee. The Committee considers the deductibility of compensation in its decision making and implements compensation programs that it believes are competitive and in the best interests of the Company and its shareholders.
Insider Trading Policy
The Board maintains a comprehensive insider trading policy (the “Insider Trading Policy”) for employees and directors to promote compliance with federal and state securities laws. The Insider Trading Policy prohibits certain persons who are aware of material non-public information about a company from: (i) trading in securities of that company; or (ii) providing material non-public information to other persons who may trade on the basis of that information. When material non-public information about us may exist and may have an influence on the marketplace, a trading blackout period is placed in effect by management. In addition, the Insider Trading Policy also applies to family members, other members of a person’s household, and entities controlled by a person covered by this Insider Trading Policy. Officers, directors, and designated employees, as well as the family members and controlled entities of such persons, may not engage in any transaction in Company securities without first obtaining pre-clearance of the transaction from our General Counsel.
Under the Insider Trading Policy, directors, executive officers and other employees are prohibited from entering into any hedging or monetization transactions relating to Callon’s securities or otherwise trading in any instrument relating to the securities’ future price. This Insider Trading Policy also prevents directors and executive officers from pledging Callon common stock as collateral for loans or holding Callon securities in a margin account. The Insider Trading Policy is published as Addendum A to our Code of Business Conduct and is available at www.callon.com/about-callon/governance.
Clawback Policy
The Committee has adopted a clawback policy that complies with NYSE’s new clawback rules promulgated under Section 10D of the Exchange Act and the rules promulgated thereunder. In the event the Company is required to prepare an accounting restatement of its financial statements due to the Company’s material noncompliance with any such financial reporting requirement, the clawback policy requires that covered executives must reimburse the Company, or forfeit, any excess incentive-based compensation received by such covered executive during the three completed fiscal years immediately preceding the date on which the Company is required to prepare the restatement. Additionally, the clawback policy contains discretionary recoupment components that are designed to provide the Company with additional remedies for recoupment in the event of a performance metric error, violation of post-employment restrictive covenants, other misconduct, or as otherwise determined in the discretion of the Committee. Executives covered by the clawback policy are current and former executive officers, as determined by the Committee in accordance with Section 10D of the Exchange Act and the NYSE listing standards. Incentive-based compensation subject to the clawback policy includes any cash or equity compensation that is granted, earned or vested based wholly or in part on the attainment of a financial reporting measure. The amount subject to recovery is the excess of the incentive-based compensation received based on the erroneous data over the incentive-based compensation that would have been received had it been based on the restated results. The clawback policy will only apply to incentive-based compensation received on or after October 2, 2023.
Risk Assessment Related to Our Compensation Structure
The Committee believes our compensation plans and policies are appropriately structured to encourage and reward prudent business judgment and avoid excessive risk-taking. The Committee, with the assistance of FW Cook, reviewed the compensation programs maintained by the Company during 2023 to determine whether they encouraged excessive risk taking. Upon evaluation of the assessment, the Committee concluded that our compensation policies and practices for our employees do not present risks that are reasonably likely to have a material adverse effect on the Company. The Committee’s risk review identified the following risk-mitigating features of our compensation programs:
•A balance of short-term and long-term programs to focus management on both elements of Callon’s performance;
•Annual grants of long-term incentives designed to be the largest component of each NEO’s compensation package, with typical vesting periods of three years that are based on the value of our common stock and not on any particular metric that could encourage excessive risk-taking;
•Performance criteria and targets for our annual bonus program designed to encourage performance, but not excessive risk taking, and discretion to decrease payouts if it is believed management exercised excessive risk taking;
•Performance targets measured at the corporate level, rather than at the individual or business unit level;
•A Clawback Policy that grants the Committee authority to recoup compensation due to error, fraud or other misconduct;
•Reasonable change in control severance protections; and
•Significant executive stock ownership requirements.
Role of Annual Say-on-Pay Advisory Vote
We have historically received strong support from our shareholders for our executive compensation practices. In the advisory vote held at the Company’s 2023 Annual Meeting of Shareholders, approximately 89% of the votes cast were in favor of our 2022 executive compensation programs. The Committee acknowledged the support received from our shareholders and viewed the results as an affirmation of our executive compensation policies and programs. The Committee will continue to review shareholder votes and feedback on our executive compensation programs to ensure alignment with shareholder interests.
Compensation Committee Report
The Committee has reviewed and discussed with management the CD&A required by Item 402(b) of Regulation S-K promulgated under the Exchange Act, and based on such review and discussions, the Committee has recommended to the Board that the CD&A be included in this Amendment No. 1.
Respectfully submitted by the Compensation Committee of the Board of Directors,
Anthony J. Nocchiero, Chair
Frances Aldrich Sevilla-Sacasa
Barbara J. Faulkenberry
Matthew R. Bob (non-voting member)
Compensation Committee Interlocks and Insider Participation
Frances Aldrich Sevilla-Sacasa, Matthew R. Bob, Barbara J. Faulkenberry, L. Richard Flury, and Anthony J. Nocchiero served on the Committee at various times during fiscal year 2023. No member of our Committee is presently or has been an officer or employee of the Company. In addition, during the last fiscal year, no executive officer served as a member of the board or the Committee (or other board committee performing similar functions or, in the absence of any such committee, the entire board) of any entity in which a Callon Board member is an executive officer.
Executive Compensation Tables
The compensation paid to the Company’s executive officers generally consists of base salaries, annual cash incentive payments, awards under the 2020 Plan, contributions to the Company’s 401(k) plan and miscellaneous perquisites. The table below sets forth information regarding fiscal years 2023, 2022, and 2021 compensation awarded to, earned by or paid to the Company’s NEOs, in each case for the years in which these individuals constituted NEOs under SEC rules. This includes all individuals who served as the Company’s CEO or CFO during 2023, the three other most highly compensated executive officers serving at the end of the fiscal year, and one additional executive officer who would have been one of the three other most highly compensated executive officers had such executive officer been employed by the Company as of the end of the fiscal year. For a detailed description of the NEOs, please see “Compensation Discussion and Analysis - Executive Pay Program and Decisions - 2023 Named Executive Officers” above. The CD&A above provides a full description of our 2023 executive compensation program design.
Summary Compensation Table
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Name and Principal Position | Year | Salary | Bonus | Stock Awards(a) | Non-Equity Incentive Plan Compensation(b) | All Other Compensation(c) | Total |
Joseph C. Gatto, Jr.(d) President & CEO | 2023 | $ | 940,221 | $ | — | $ | 5,526,064 | | $ | 3,422,318 | $ | 138,584 | $ | 10,027,187 |
2022 | $ | 896,606 | $ | — | $ | 1,828,585 | | $ | 1,441,847 | $ | 29,167 | $ | 4,196,205 |
2021 | $ | 865,000 | $ | — | $ | 2,092,309 | | $ | 2,718,028 | $ | 34,142 | $ | 5,709,479 |
Kevin Haggard(e) Senior Vice President & CFO | 2023 | $ | 539,808 | $ | — | $ | 898,120 | | $ | 1,332,457 | $ | 95,549 | $ | 2,865,934 |
2022 | $ | 475,578 | $ | — | $ | 767,246 | | $ | 554,355 | $ | 37,547 | $ | 1,834,726 |
2021 | $ | 276,923 | $ | — | $ | 1,289,435 | | $ | 708,750 | $ | 18,000 | $ | 2,293,108 |
Russell E. Parker(f) Senior Vice President & Chief Operating Officer | 2023 | $ | 283,269 | $ | — | $ | 1,884,251 | | $ | 484,500 | $ | 66,132 | $ | 2,718,152 |
Michol L. Ecklund(g) Senior Vice President, Chief Sustainability Officer, General Counsel & Corporate Secretary | 2023 | $ | 476,192 | $ | — | $ | 1,383,499 | | $ | 1,126,422 | $ | 104,378 | $ | 3,090,491 |
2022 | $ | 448,269 | $ | — | $ | 575,450 | | $ | 520,065 | $ | 30,407 | $ | 1,574,191 |
2021 | $ | 430,000 | $ | — | $ | 656,241 | | $ | 1,057,414 | $ | 33,773 | $ | 2,177,428 |
Gregory F. Conaway(h) Vice President & Chief Accounting Officer | 2023 | $ | 364,462 | $ | — | $ | 300,752 | | $ | 536,660 | $ | 138,243 | $ | 1,340,117 |
2022 | $ | 320,961 | $ | — | $ | 223,753 | | $ | 309,563 | $ | 37,692 | $ | 891,969 |
2021 | $ | 305,385 | $ | — | $ | 256,065 | | $ | 609,663 | $ | 35,323 | $ | 1,206,436 |
Jeffrey S. Balmer(i)(j) Former Senior Vice President & COO | 2023 | $ | 356,193 | $ | — | $ | 874,595 | (k) | $ | 2,019,500 | $ | 433,145 | $ | 3,683,433 |
2022 | $ | 528,269 | $ | 175,000 | $ | 878,032 | | $ | 645,478 | $ | 36,875 | $ | 2,263,654 |
2021 | $ | 510,000 | $ | 175,000 | $ | 1,041,649 | | $ | 1,323,863 | $ | 27,272 | $ | 3,077,784 |
(a) The amounts reported in the “Stock Awards” column represent the aggregate grant date fair value of RSUs and MSUs computed in accordance with FASB ASC Topic 718, disregarding estimates for forfeitures. The MSUs granted in 2023 are subject to market conditions and have been valued utilizing a Monte Carlo simulation as of the grant date of the awards and the maximum value of the MSU award as of the grant date was $4,683,000; no MSUs were granted in 2021 or 2022.
(b) The amounts reported in the “Non-Equity Incentive Plan Compensation” column represent payouts under the annual performance bonus program for 2021, 2022, and 2023. See “Performance-Based Annual Cash Bonus Incentive” in the CD&A above. The amounts reported for 2021 include certain retention incentive awards for eligible officers as described in “2020 Transition and Retention Awards” in the CD&A in our 2022 proxy statement. The amounts reported for 2023 include the vested values of 2021 cash performance units for eligible officers as described under “Vesting of 2021-2023 Cash Performance Units” in the CD&A above.
(c) See the “Table of All Other Compensation” below and related footnotes for reconciliation.
(d) Mr. Gatto’s salary was increased from $908,250 to $952,000 effective March 2, 2023.
(e) Mr. Haggard’s salary was increased from $485,000 to $560,000 effective March 2, 2022.
(f) Mr. Parker was not an NEO prior to 2023. Mr. Parker joined the Company as Chief Operating Officer on June 28, 2023, with an annual salary of $600,000.
(g) Ms. Ecklund’s salary was increased from $455,000 to $484,000 effective March 2, 2023.
(h) Mr. Conaway’s salary was increased from $325,000 to $379,000 effective March 2, 2023.
(i) Dr. Balmer’s salary was increased from $535,000 to $560,000 effective March 2, 2023.
(j) Dr. Balmer ceased serving as Senior Vice President and Chief Operating Officer for the Company effective June 28, 2023, due to his retirement. In connection with Dr. Balmer’s departure from the Company, the Company entered into a separation agreement with Dr. Balmer dated as of July 5, 2023 (the “Separation Agreement”). Pursuant to the Separation Agreement and the terms and conditions of his 2021 Cash Performance Units, 2022 “Business Sustainability” Cash Performance Units, and 2022 “Returns” Cash Performance Units, Dr. Balmer received payment of $2,019,500 “Qualified Retirement” benefits under the CPU Agreements. See “Employment Agreements, Termination of Employment and Change in Control Arrangements - Separation Agreement.”
(k) The RSUs and CPUs granted to Dr. Balmer on March 2, 2023, as well as the unvested portions of his previously granted RSUs, were forfeited in connection with Dr. Balmer’s retirement from the Company, effective June 28, 2023.
Table of All Other Compensation for 2023
| | | | | | | | | | | | | | | | | | | | | | | |
NEO | Year | Company Contributions to 401(k)(a) | Company Provided Auto(b) | | Other(c) | Total |
Joseph C. Gatto, Jr. | 2023 | $ | 26,400 | | $ | 112,184 | | | $ | — | | $ | 138,584 |
Kevin Haggard | 2023 | $ | 16,511 | | $ | 77,238 | | $ | 1,800 | | $ | 95,549 |
Russell E. Parker | 2023 | $ | 22,281 | | $ | — | | | $ | 43,851 | (d) | $ | 66,132 |
Michol L. Ecklund | 2023 | $ | 26,587 | | $ | 75,691 | | | $ | 2,100 | | $ | 104,378 |
Gregory F. Conaway | 2023 | $ | 26,352 | | $ | 109,741 | | | $ | 2,150 | | $ | 138,243 |
Jeffrey S. Balmer | 2023 | $ | 25,250 | | $ | 98,834 | | (e) | $ | 309,061 | (f) | $ | 433,145 |
(a) Subject to IRS limits, Company contributions to each NEO’s 401(k) account for 2023 consist of a 6% matching contribution plus a 2% profit sharing contribution for 2023.
(b) The imputed value for personal use of a company-provided vehicle represents annual depreciation based on a three-year life, plus insurance, fuel, maintenance and repairs, pursuant to IRS rules. As part of the executive officer vehicle plan termination, the Committee approved supplemental salary payments to the NEOs impacted by the plan termination in the following amounts: Mr. Gatto - $70,000; Mr. Haggard - $30,000; Ms. Ecklund - $60,000; Mr. Conaway - $60,000.
(c) Except as otherwise indicated in footnotes (d), (e) and (f) below, each NEO, other than Dr. Balmer, was reimbursed up to $2,500 for an annual physical.
(d) Mr. Parker received $43,851 for reimbursement for certain reasonable relocation expenses which included transportation expenses, home sale and purchase assistance, shipment of additional household goods, and tax gross-ups on these payments.
(e) In addition to the payment detailed in footnote (b) above, upon Dr. Balmer’s retirement, the Company transferred to Dr. Balmer the title to the company vehicle that was being used by Dr. Balmer, which was valued at $92,131.
(f) Dr. Balmer received a total of $300,000 in monthly consulting fees pursuant to the Consulting Agreement between the Company and Dr. Balmer, dated as of July 5, 2023 (the “Consulting Agreement”). Pursuant to the Consulting Agreement, Dr. Balmer received a monthly fee of $50,000 in exchange for assisting the Company in transitioning the duties of the Chief Operating Officer position. The Consulting Agreement terminated on December 31, 2023. Pursuant to Dr. Balmer’s Separation Agreement, the Company agreed to maintain COBRA continuation coverage for Dr. Balmer and his eligible family members for a period of 18 months. During 2023, the Company paid $9,061 for COBRA continuation coverage. See “Employee Agreements, Termination of Employment and Change in Control Arrangements - Separation Agreement.”
Stock-Based Incentive Compensation Plans
The 2020 Omnibus Incentive Plan (the “2020 Plan”) was approved by shareholders on June 8, 2020. Awards available under the 2020 Plan include grants of stock options, stock appreciation rights or units, restricted stock, RSUs, and performance shares or units. As of December 31, 2023, approximately 1,326,047 shares remain unissued and available for grant in the 2020 Plan.
Grants of Plan-Based Awards During 2023
The following table presents grants of awards under the 2020 Plan during the fiscal year ending December 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Grant Date | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(a) | Estimated Future Payouts Under Equity Incentive Plan Awards(b) | Other Awards (Shares or Units)(c) | | Grant Date Fair Value of Stock Awards(d) |
NEO | Threshold | Target | Maximum | Threshold | Target | Maximum | |
Joseph C. Gatto, Jr. | 1/1/2023 | $ | — | $ | 1,190,000 | | $ | 2,380,000 | | | | | | | |
3/2/2023 | | | | | | | 49,829 | | | $ | 2,021,064 | |
| 3/2/2023 | $ | — | $ | 2,939,400 | | $ | 5,878,800 | | | | | | | |
| 4/26/2023 | | | | — | 100,000 | | 150,000 | | | | $ | 3,505,000 | |
Kevin Haggard | 1/1/2023 | $ | — | $ | 504,000 | | $ | 1,008,000 | | | | | | | |
| 3/2/2023 | | | | | | | 22,143 | | | $ | 898,120 | |
| 3/2/2023 | $ | — | $ | 1,306,200 | | $ | 2,612,400 | | | | | | | |
Russell E. Parker | 6/28/2023 | $ | — | $ | 570,000 | | $ | 1,140,000 | | | | | | | |
| 6/28/2023 | | | | | | | 24,409 | | (e) | $ | 840,402 | |
| 6/28/2023 | | | | | | | 30,318 | | (f) | $ | 1,043,849 | |
| 6/28/2023 | $ | — | $ | 1,440,000 | | $ | 2,880,000 | | | | | | | |
Michol L. Ecklund | 1/1/2023 | $ | — | $ | 435,600 | | $ | 871,200 | | | | | | | |
| 3/2/2023 | | | | | | | 14,820 | | | $ | 601,099 | |
| 3/2/2023 | $ | — | $ | 874,200 | | $ | 1,748,400 | | | | | | | |
| 9/29/2023 | | | | | | | 20,000 | | (g) | $ | 782,400 | |
Gregory F. Conaway | 1/1/2023 | $ | — | $ | 284,250 | | $ | 568,500 | | | | | | | |
3/2/2023 | | | | | | | 7,415 | | | $ | 300,752 | |
| 3/2/2023 | $ | — | $ | 437,400 | | $ | 874,800 | | | | | | | |
Jeffrey S. Balmer(h) | 1/1/2023 | $ | — | $ | 532,000 | | $ | 1,064,000 | | | | | | | |
| 3/2/2023 | | | | | | | 21,563 | | | $ | 874,595 | |
| 3/2/2023 | $ | — | $ | 1,272,000 | | $ | 2,544,000 | | | | | | | |
(a) Amounts represent the threshold, target, and maximum payouts for the 2023 annual performance bonus program and the CPUs granted to the NEOs in 2023. The actual amounts paid under the 2023 annual performance bonus program are included in the “Non-Equity Incentive Compensation” column in the Summary Compensation Table above. The CPUs will be earned at the end of the performance period ending December 31, 2025, based on the Company’s achievement of performance objectives relating to the Company’s adjusted free cash flow, GHG emissions intensity reduction, and return on capital employed. Subject to certain qualifying termination events, the participant is required to be employed on the award settlement date in order to vest in the award.
(b) Amounts represent the threshold, target, and maximum settlement of MSUs granted to Mr. Gatto on April 26, 2023. The actual amounts that will vest at the end of the performance period ending April 30, 2026 is based on the Company’s annualized absolute TSR, subject to the NEO’s continued employment with the Company through such vesting date.
(c) Except as otherwise indicated in footnotes (e), (f) and (g) below, amounts represent RSUs granted to our NEOs on March 2, 2023. The first, second and third tranches are scheduled to vest in equal installments on April 15, 2024, 2025 and 2026, respectively, subject to the NEO’s continued employment with the Company through each such vesting date.
(d) This column shows the grant date fair value of the awards granted to the NEOs on the date indicated computed in accordance with FASB ASC Topic 718. The value ultimately realized by the NEO upon the actual vesting of the awards may be more or less than the grant date fair value.
(e) These RSUs were granted to Mr. Parker on June 28, 2023, and are scheduled to vest in equal installments on April 15, 2024, 2025 and 2026, subject to Mr. Parker’s continued employment with the Company through each such vesting date.
(f) These RSUs were granted to Mr. Parker on June 28, 2023, and are scheduled to cliff vest in full on July 1, 2026, subject to Mr. Parker’s continued employment with the Company through such vesting date.
(g) These RSUs were granted to Ms. Ecklund on September 29, 2023, and are scheduled to cliff vest in full on October 1, 2026, subject to Ms. Ecklund’s continued employment with the Company through such vesting date.
(h) Dr. Balmer ceased serving as Senior Vice President and Chief Operating Officer for the Company effective June 28, 2023, due to his retirement. His 2023 annual performance bonus opportunity as well as the CPUs and RSUs granted to Dr. Balmer on March 2, 2023, were forfeited in connection with Dr. Balmer’s retirement from the Company.
Outstanding Equity Awards at Fiscal Year-End
The following table contains information concerning all outstanding equity awards that were held as of December 31, 2023, by the NEOs:
| | | | | | | | | | | | | | | | | | | | |
| Stock Awards |
NEO | Number of Shares or Units of Stock That Have Not Vested (#) | | Market Value of Shares or Units of Stock That Have Not Vested(a) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested(a) |
Joseph C. Gatto, Jr. | — | | | $ | — | 100,000 | (b) | $ | 3,240,000 |
| 49,829 | | (c) | $ | 1,614,460 | — | | — |
| 20,676 | | (d) | $ | 669,902 | — | | — |
| 17,567 | | (e) | $ | 569,171 | — | | — |
Kevin Haggard | 22,143 | | (c) | $ | 717,433 | — | | — |
| 8,675 | | (d) | $ | 281,070 | — | | — |
| 5,332 | | (f) | $ | 172,757 | — | | — |
| 16,408 | | (g) | $ | 531,619 | — | | — |
Russell E. Parker | 24,409 | | (h) | $ | 790,852 | — | | — |
| 30,318 | | (i) | $ | 982,303 | — | | — |
Michol L. Ecklund | 20,000 | | (j) | $ | 648,000 | — | | — |
| 14,820 | | (c) | $ | 480,168 | — | | — |
| 6,506 | | (d) | $ | 210,794 | — | | — |
| 5,510 | | (e) | $ | 178,524 | — | | — |
Gregory F. Conaway(k) | 7,415 | | (c) | $ | 240,246 | — | | — |
| 2,530 | | (d) | $ | 81,972 | — | | — |
| 2,150 | | (e) | $ | 69,660 | — | | — |
Jeffrey S. Balmer | — | | | $ | — | — | | — |
(a) Amounts calculated using the closing price of $32.40 per share of our common stock on the last trading day of 2023.
(b) Stock settleable MSUs awarded on April 26, 2023, with vesting terms subject to performance criteria related to the annualized absolute TSR of the Company from May 1, 2023 through April 30, 2026. The number of units subject to vest under this award can range from 0% to 150%.
(c) Stock settleable RSUs awarded on March 2, 2023, subject to three-year ratable vesting with one-third vesting each year subsequent to the award year. The first tranche will vest on April 15, 2024. The second tranche will vest on April 15, 2025. The third and final tranche will vest on April 15, 2026.
(d) Stock settleable RSUs awarded on March 9, 2022, subject to three-year ratable vesting with one-third vesting each year subsequent to the award year. The first tranche vested on April 1, 2023. The second tranche will vest on April 1, 2024. The third and final tranche will vest on April 1, 2025.
(e) Stock settleable RSUs awarded on March 12, 2021, subject to three-year ratable vesting with one-third vesting each year subsequent to the award year. The first tranche vested on April 1, 2022. The second tranche vested on April 1, 2023. The third and final tranche will vest on April 1, 2024.
(f) Stock settleable RSUs awarded to Mr. Haggard on May 10, 2021, upon his appointment as an executive officer, subject to three-year ratable vesting with one-third vesting each year subsequent to the award year. The first tranche vested on April 1, 2022. The second tranche vested on April 1, 2023. The third and final tranche will vest on April 1, 2024.
(g) Stock settleable RSUs awarded to Mr. Haggard on May 10, 2021, upon his appointment as an executive officer, subject to cliff vesting in full on June 1, 2024.
(h) Stock settleable RSUs awarded to Mr. Parker on June 28, 2023, upon his appointment as an executive officer, subject to three-year ratable vesting with one-third vesting each year subsequent to the award year. The first tranche will vest on April 15, 2024. The second tranche will vest on April 15, 2025. The third and final tranche will vest on April 15, 2026.
(i) Stock settleable RSUs awarded to Mr. Parker on June 28, 2023, upon his appointment as an executive officer, subject to cliff vesting in full on July 1, 2026.
(j) Stock settleable RSUs awarded to Ms. Ecklund on September 29, 2023, subject to cliff vesting in full on October 1, 2026.
(k) Mr. Conaway held the following outstanding cash-settled stock appreciation right awards as of December 31, 2023: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Option/SAR Awards |
NEO | Number of Securities Underlying Unexercised Options/ SARs (#) Exercisable | | Number of Securities Underlying Unexercised Options/ SARs (#) Unexercisable | Equity Incentive Plan Awards: Number of Securities Underlying Exercised Unearned Options/SARs (#) | Option/ SARs Exercise Price ($) | Option/ SARs Expiration Date |
Gregory F. Conaway | 3,144 | | (1) | — | | — | | | $ | 83.90 | | | 3/17/2025 |
| 4,258 | | (2) | — | | — | | | $ | 62.80 | | | 3/17/2026 |
(1)Cash-settled stock appreciation rights received in connection with the Carrizo Acquisition in exchange for 17,967 Carrizo stock appreciation rights with an exercise price of $14.67 pursuant to the Merger Agreement.
(2) Cash-settled stock appreciation rights received in connection with the Carrizo Acquisition in exchange for 24,336 Carrizo stock appreciation rights with an exercise price of $10.98 pursuant to the Merger Agreement.
Option Exercises and Stock Vested
The following table provides information about the value realized by the NEOs on vesting of RSUs during 2023. No options were awarded, outstanding, or exercised by any NEO in fiscal year 2023.
| | | | | | | | | | | |
| Stock Awards(a) |
NEO | Number of Shares Acquired on Vesting (#) | | Value Realized on Vesting $ |
Joseph C. Gatto, Jr. | 16,266 | | (b) | $ | 543,935 |
| 17,568 | | (c) | $ | 587,474 |
| 10,338 | | (d) | $ | 345,703 |
Kevin Haggard | 5,333 | | (e) | $ | 178,336 |
| 4,338 | | (d) | $ | 145,063 |
Russell E. Parker | — | | | $ | — |
Michol L. Ecklund | 4,839 | | (b) | $ | 161,816 |
| 5,510 | | (c) | $ | 184,254 |
| 3,254 | | (d) | $ | 108,814 |
Gregory F. Conaway | 1,645 | | (f) | $ | 61,013 |
| 1,788 | | (b) | $ | 59,791 |
| 2,150 | | (c) | $ | 71,896 |
| 1,265 | | (d) | $ | 42,302 |
Jeffrey S. Balmer | 7,683 | | (b) | $ | 256,920 |
| 8,746 | | (c) | $ | 292,466 |
| 4,964 | | (d) | $ | 165,996 |
(a) Except as otherwise indicated, represents the aggregate dollar amount realized on the date of vesting, based on the closing market price per share of Company common stock on the vesting date or last business day prior to the vesting date if such date fell on a weekend or holiday, without taking into account any shares withheld to satisfy applicable tax obligations.
(b) Represents RSUs awarded on January 31, 2020, the third tranche of which vested on April 1, 2023.
(c) Represents RSUs awarded on March 12, 2021, the second tranche of which vested on April 1, 2023.
(d) Represents RSUs awarded on March 9, 2022, the first tranche of which vested on April 1, 2023.
(e) Represents RSUs awarded to Mr. Haggard upon his hiring on May 10, 2021, the second tranche of which vested on April 1, 2023.
(f) Represents RSUs awarded to Mr. Conaway upon his appointment as an executive officer on January 1, 2020, the third tranche of which vested on January 1, 2023.
Employment Agreements, Termination of Employment and Change in Control Arrangements
Employment Agreements
We do not have employment agreements with any of our NEOs.
Executive Severance Compensation Plans
The Company has a Severance Pay Plan and the Executive CIC Plan, pursuant to which eligible participants, including each of our NEOs, are eligible to receive certain severance payments and benefits upon an involuntary termination (pursuant to the Severance Pay Plan) or upon an Eligible Termination or Deemed Eligible Termination in connection with a Change in Control (pursuant to the Executive CIC Plan). For additional background information, please see “Change in Control, Severance, and Employment Agreements” in the CD&A above.
Severance Pay Plan
In the event of a NEO’s Involuntary Termination (as defined in the Severance Pay Plan), subject to the NEO’s (1) execution of a release of claims in favor of the Company and (2) continued employment with the Company through the ultimate date established by the Company as the NEO’s termination date, the NEO is entitled to receive: (i) the Accrued Obligations (as defined in the Severance Pay Plan), (ii) an amount equal to the sum of (x) the Applicable Multiple (as defined below) times the sum of the NEO’s (A) annual base salary and (B) target annual bonus, (y) any earned but unpaid annual bonus for the calendar year prior to the year of the Involuntary Termination, based on the Company’s actual performance during such calendar year and (z) an amount equal to a pro rata portion of the NEO’s annual bonus for the calendar year of the Involuntary Termination, with the amount subject to proration to be calculated as follows based on the number of days in the calendar year the NEO remained employed through the date of the Involuntary Termination (as applicable, the “Pro-Rata Bonus”): (1) if the Involuntary Termination occurs prior to July 1st, the NEO’s Target Annual bonus (as defined in the Severance Pay Plan) or (2) if the Involuntary Termination occurs on or after July 1st, the NEO’s actual annual bonus for the year in which the Involuntary Termination occurs, as determined by the Committee (the severance benefits provided in this clause (ii), collectively, the “Severance Pay”) and (iii) continued health and welfare benefits coverage for the NEO and the NEO’s eligible dependents for a period of 12 months after the date of the Involuntary Termination. For purposes of the Severance Pay Plan, “Applicable Multiple” means 2x for Mr. Gatto and 1.5x for each of the commitments shownother NEOs.
Except with respect to the Pro-Rata Bonus for any Involuntary Termination occurring on or after July 1st, the Severance Pay (less all applicable withholdings and deductions) will be paid in a lump sum as soon as practicable following the date the release signed by the NEO has become final and irrevocable. In no event, however, will the Severance Pay be paid later than the last day of the second taxable year following the taxable year in which occurs the NEO’s Involuntary Termination.
As a condition to any NEO’s receipt of severance benefits under the Severance Pay Plan, the NEO must comply with non-competition and non-solicitation covenants that apply for a period of one year after the date of termination, as well as customary non-disparagement, non-disclosure, confidentiality, and ownership covenants.
Executive CIC Plan
The Executive CIC Plan provides for severance payments and benefits in the table above,event that (i) there is a Change in Control (as defined in the committed MMBtus may include volumes producedExecutive CIC Plan), and the NEO’s employment is terminated within two years after the date of such Change in Control either (a) by usthe Company other than for Cause or due to the NEO’s Disability (each as defined in the Executive CIC Plan) or (b) by the NEO for Good Reason (as defined in the Executive CIC Plan), or (ii) there is a Merger of Equals (as defined in the Executive CIC Plan), and the NEO’s employment is terminated by the Company other third-party working, royalty,than for Cause or due to the NEO’s Disability within 12 months following the date of such Merger of Equals (each an “Eligible Termination”). If the NEO’s employment is terminated by the Company for reasons other than Cause or Disability within six months prior to the date on which a Change in Control is effective and overriding royalty interest owners whose volumes we marketit is reasonably demonstrated that such termination: (x) was at the request of a third party who has taken steps reasonably calculated to effectuate such Change in Control or (y) otherwise arose in connection with such Change in Control, then for all purposes of the Executive CIC Plan, such termination will be deemed to have occurred following such Change in Control (for purposes of the Executive CIC Plan, a “Deemed Eligible Termination”).
Upon an Eligible Termination or a Deemed Eligible Termination, and subject to the NEO’s satisfaction of the conditions described below, the NEO would be entitled to receive, subject to the NEO’s execution (without revocation) of a release of claims against the Company: (i) a lump sum cash payment, payable on their behalf. the date that is six months following the date of
the NEO’s termination of employment, equal to the sum of: (x) the Applicable Multiplier (as defined below) times the sum of (A) the NEO’s annual base salary as in effect immediately prior to the Change in Control or Merger of Equals, as applicable, or, if higher, in effect immediately prior to the date of termination and (B) the greatest of (1) the average annual bonus earned with respect to the three most recently completed full fiscal years (provided that if the NEO has not been employed for the entire duration of each of the three most recently completed full fiscal years, the NEO will be deemed to have earned his or her target annual bonus for any year for which he or she was not employed for the entire fiscal year for purposes of calculating the average), (2) the target annual bonus for the fiscal year in which the Change in Control or Merger of Equals, as applicable, occurs or (3) the target annual bonus for the fiscal year in which the date of termination occurs, (y) a Pro-Rata Bonus (as defined in the Executive CIC Plan) and (z) any actual annual bonus for any completed calendar year that has been earned by but not paid to the NEO as of such NEO’s date of termination, (ii) continued health and welfare benefits coverage for the NEO and the NEO’s eligible dependents for a period of 24 months, and (iii) all outstanding Incentive Awards (including RSUs, CPUs, and MSUs, as applicable) shall be immediately 100% percent vested with any performance-based awards earned at the level specified for a Change in Control event in the applicable award agreement. For purposes of the Executive CIC Plan, “Applicable Multiplier” means 3x for Mr. Gatto and 2x for each of the other NEOs.
As a condition to any NEO’s receipt of severance benefits under the Executive CIC Plan, the NEO must comply with non-competition and non-solicitation covenants that apply for a period of one year after the date of termination, as well as customary non-disparagement, non-disclosure, and confidentiality covenants.
If the Total Payments (as defined in the Executive CIC Plan), were to cause the NEO to be subject to the excise tax provisions of Section 4999 of the Internal Revenue Code of 1986, as amended, then the amount of the Total Payments will either be reduced, such that the excise tax would not be applicable, or the NEO will be entitled to retain such NEO’s full Total Payments, whichever results in the better after-tax position to the NEO.
Long-Term Incentive Award Agreements
We expectare party to fulfill these delivery commitmentsRestricted Stock Unit Award Agreements (the “RSU Agreements”) with our existing production or throughNEOs. Pursuant to the purchases of third-party commodities.
(2)Eachterms of the firm transportation agreements shownRSU Agreements, upon termination of the NEO’s employment with the Company as a result of the death or Disability (as defined in the table above grant us accessRSU Agreement) of the NEO, all of the NEO’s RSUs then outstanding under the RSU Agreement will immediately vest.
We are also party to delivery points in several locations alongCash Performance Unit Award Agreements (the “CPU Agreements”) with our NEOs as described under the Gulf Coast. The costs associated with these agreements are recorded to “Gathering, transportation and processing”sub-heading “Cash Performance Units” in the Company’s consolidated statementsCD&A above. Pursuant to the terms of operations.the CPU Agreements, upon termination of the NEO’s employment with the Company as a result of the death or Disability (as defined in the CPU Agreement) of the NEO, all of the NEO’s CPUs then outstanding will immediately vest and payout based on actual results from completed quarters and target results for all other periods, and the Year 3 GHG intensity modifier would not apply.
In the event of a Qualifying Retirement (as defined in the RSU Agreements), at the discretion of the Committee the NEO’s outstanding RSUs could continue to vest according to their original vesting schedule. In the event of a “qualifying retirement” (as defined in the CPU Agreements), at the discretion of the Committee the NEO’s outstanding CPUs would vest on a pro rata basis based on actual results for completed quarters and target results for any “stub” quarters that were not complete as of his or her retirement date, and the Year 3 GHG intensity modifier would not apply. As of December 31, 2023, no NEO was eligible for a “qualifying retirement” based on age and years of service.
Note 19 – Subsequent Events (Unaudited)We are also party to a Market Stock Unit Award Agreement (the “MSU Agreement”) with Mr. Gatto as described in under the sub-heading “Market Stock Units” in the CD&A above. Pursuant to the terms of the MSU Agreement, upon termination of Mr. Gatto’s employment with the Company as a result of death or Disability (as defined in the MSU Agreement), all of the MSUs then outstanding will immediately vest assuming (i) the time vesting requirement has been satisfied as of the date of such termination and (ii) the performance vesting requirements have been satisfied in accordance with the terms of the MSU Agreement assuming the last day of the performance period is the date of such termination.
On January 3, 2024,Separation Agreement
Dr. Balmer ceased serving as Senior Vice President and Chief Operating Officer for the Company effective June 28, 2023. In connection with his departure from the Company, the Company entered into the MergerSeparation Agreement with APA and Merger Sub. See “Note 1 - Description of Business” for further discussion.
Note 20 –Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Estimated Reserves
For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third-party reserve engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
Extrapolation of performance history and material balance estimates were utilized by D&M to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicableDr. Balmer. Pursuant to the subject reservoirs. The projections forSeparation Agreement and the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to non-producing zonesterms and undeveloped locations were projected on the basisconditions of volumetric calculationshis 2021 Cash Performance Units, 2022 “Business Sustainability” Cash Performance Units, and analogy to nearby production and, to2022 “Returns” Cash Performance Units, Dr. Balmer received a small extent, horizontal PDP and PUD categories.
The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
Proved reserves | | 2023 | | 2022 | | 2021 |
Oil (MBbls) | | | | | | |
Beginning of period | | 275,609 | | | 290,296 | | | 289,487 | |
Extensions and discoveries | | 40,684 | | | 41,064 | | | 22,520 | |
Revisions to previous estimates | | (28,278) | | | (31,163) | | | (10,514) | |
Purchase of reserves in place | | 38,731 | | | — | | | 35,045 | |
Sales of reserves in place | | (47,336) | | | (949) | | | (24,019) | |
Removed for five-year rule | | (18,259) | | | — | | | — | |
Production | | (21,891) | | | (23,639) | | | (22,223) | |
End of period | | 239,260 | | | 275,609 | | | 290,296 | |
Natural Gas (MMcf) | | | | | | |
Beginning of period | | 592,843 | | | 577,327 | | | 541,598 | |
Extensions and discoveries | | 75,616 | | | 75,801 | | | 37,896 | |
Revisions to previous estimates | | 24,206 | | | (11,155) | | | (3,389) | |
Purchase of reserves in place | | 42,802 | | | — | | | 73,445 | |
Sale of reserves in place | | (53,317) | | | (7,503) | | | (34,837) | |
Removed for five-year rule | | (74,548) | | | — | | | — | |
Production | | (46,109) | | | (41,627) | | | (37,386) | |
End of period | | 561,493 | | | 592,843 | | | 577,327 | |
NGLs (MBbls) | | | | | | |
Beginning of period | | 105,109 | | | 98,104 | | | 96,126 | |
Extensions and discoveries | | 14,718 | | | 14,264 | | | 7,345 | |
Revisions to previous estimates | | 317 | | | 1,376 | | | (3,103) | |
Purchase of reserves in place | | 9,487 | | | — | | | 10,366 | |
Sale of reserves in place | | (9,537) | | | (1,159) | | | (6,191) | |
Removed for five-year rule | | (11,415) | | | — | | | — | |
Production | | (8,011) | | | (7,476) | | | (6,439) | |
End of period | | 100,668 | | | 105,109 | | | 98,104 | |
Total (MBoe) | | | | | | |
Beginning of period | | 479,525 | | | 484,621 | | | 475,879 | |
Extensions and discoveries | | 68,005 | | | 67,961 | | | 36,180 | |
Revisions to previous estimates | | (23,927) | | | (31,645) | | | (14,181) | |
Purchase of reserves in place | | 55,352 | | | — | | | 57,652 | |
Sale of reserves in place | | (65,759) | | | (3,359) | | | (36,015) | |
Removed for five-year rule | | (42,099) | | | — | | | — | |
Production | | (37,587) | | | (38,053) | | | (34,894) | |
End of period | | 433,510 | | | 479,525 | | | 484,621 | |
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
Proved developed reserves | | 2023 | | 2022 | | 2021 |
Oil (MBbls) | | | | | | |
Beginning of period | | 170,866 | | | 162,886 | | | 128,923 | |
End of period | | 149,898 | | | 170,866 | | | 162,886 | |
Natural gas (MMcf) | | | | | | |
Beginning of period | | 351,278 | | | 332,266 | | | 238,119 | |
End of period | | 376,070 | | | 351,278 | | | 332,266 | |
NGLs (MBbls) | | | | | | |
Beginning of period | | 63,788 | | | 55,720 | | | 43,315 | |
End of period | | 65,891 | | | 63,788 | | | 55,720 | |
Total proved developed reserves (MBoe) | | | | | | |
Beginning of period | | 293,200 | | | 273,983 | | | 211,925 | |
End of period | | 278,467 | | | 293,200 | | | 273,983 | |
Proved undeveloped reserves | | | | | | |
Oil (MBbls) | | | | | | |
Beginning of period | | 104,743 | | | 127,410 | | | 160,564 | |
End of period | | 89,362 | | | 104,743 | | | 127,410 | |
Natural gas (MMcf) | | | | | | |
Beginning of period | | 241,565 | | | 245,061 | | | 303,479 | |
End of period | | 185,423 | | | 241,565 | | | 245,061 | |
NGLs (MBbls) | | | | | | |
Beginning of period | | 41,321 | | | 42,384 | | | 52,811 | |
End of period | | 34,777 | | | 41,321 | | | 42,384 | |
Total proved undeveloped reserves (MBoe) | | | | | | |
Beginning of period | | 186,325 | | | 210,638 | | | 263,954 | |
End of period | | 155,043 | | | 186,325 | | | 210,638 | |
Total proved reserves | | | | | | |
Oil (MBbls) | | | | | | |
Beginning of period | | 275,609 | | | 290,296 | | | 289,487 | |
End of period | | 239,260 | | | 275,609 | | | 290,296 | |
Natural gas (MMcf) | | | | | | |
Beginning of period | | 592,843 | | | 577,327 | | | 541,598 | |
End of period | | 561,493 | | | 592,843 | | | 577,327 | |
NGLs (MBbls) | | | | | | |
Beginning of period | | 105,109 | | | 98,104 | | | 96,126 | |
End of period | | 100,668 | | | 105,109 | | | 98,104 | |
Total proved reserves (MBoe) | | | | | | |
Beginning of period | | 479,525 | | | 484,621 | | | 475,879 | |
End of period | | 433,510 | | | 479,525 | | | 484,621 | |
Total Proved Reserves
Forpayment of $2,019,500 for “Qualified Retirement” under his 2021 and 2022 CPUs. All of Dr. Balmer’s unvested RSUs and his 2023 CPUs were forfeited upon his retirement. The Company also transferred to Dr. Balmer the title to the company vehicle that was being used by Dr. Balmer, which was valued at $92,131. The Company also agreed to maintain COBRA continuation coverage for Dr. Balmer and his eligible family members for a period of eighteen (18) months after the Resignation Date (as defined in the Separation Agreement), for medical, dental, and vision insurance coverage. During 2023, the Company paid $9,061 for COBRA continuation coverage and will pay $19,548 for the remaining coverage period in 2024. In exchange for the foregoing, Dr. Balmer agreed to certain waivers and releases for the Company’s benefit. Dr. Balmer has also agreed that for a period of one year endedfollowing the Resignation Date, he will not, directly or indirectly, compete or provide services to any oil and gas E&P company in the Permian Basin, and that for a period of one year following the Resignation Date, he will not, directly or indirectly, hire, solicit, or influence any employee of the Company or its subsidiaries to leave the employment of the Company or its subsidiaries. The Company also entered into the Consulting Agreement with Dr. Balmer. Pursuant to the Consulting Agreement, Dr. Balmer received a monthly fee of $50,000 in exchange for assisting the Company in transitioning the duties of the Chief Operating Officer position. The Consulting Agreement terminated on December 31, 2023, the Company’s net decrease2023.
Potential Payments upon Termination or Change in proved reserves of 46.0 MMBoe was primarily due to the following:
•Increase of 68.0 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 2.5 MMBoe were proved developed reserves;
•Decrease of 23.9 MMBoe for revisions of previous estimates that were primarily comprised of:
◦10.8 MMBoe reduction from the removal of PUD locations due to revised development spacing and changes in lateral lengths, primarily in the Company’s Delaware West operating area, as it focuses on the ongoing optimization of the value of the reservoir system through co-development of multiple target zones within the system utilizing larger scale projects and extended lateral lengths;
◦10.7 MMBoe reduction primarily due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 18% as compared to December 31, 2022; and
◦2.4 MMBoe reduction primarily due to higher operating costs as well as lower than expected recoveries from wells turned to production primarily in the western portion of our Permian acreage during 2023.
•Increase of 55.4 MMBoe for purchase of reserves in place associated with the Percussion Acquisition;
•Decrease of 65.8 MMBoe for sales of reserves in place primarily associated with the Eagle Ford Divestiture;
•Decrease of 42.1 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories as the Company adjusted its future Permian Basin development and capital allocation plans following the Eagle Ford Divestiture and the concurrent Percussion Acquisition, resulting in previously scheduled PUDs, primarily in the Delaware West operating area that is more weighted to natural gas volumes, now forecast to be developed outside of the five-year period from initial booking; and
•Decrease of 37.6 MMBoe for production.
For the year ended December 31, 2022, the Company’s net decrease in proved reserves of 5.1 MMBoe was primarily due to the following:
•Increase of 68.0 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 8.7 MMBoe were proved developed reserves;
•Decrease of 31.6 MMBoe for revisions of previous estimates that were primarily comprised of:
◦44.4 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories, all of which were in the Permian. Certain PUDs were moved outside of their five-year development window as we continue to refine our future development plans for the Permian, including increased application of our “Life of Field” co-development model. This development model focuses on optimization of the value of a reservoir system through concurrent, co-development of multiple target zones within the system utilizing larger scale projects. As a result, we believe the model contributes to more consistent capital efficiency of our well inventory over time and our broader Permian development program is now being targeted for larger project sizes, accompanied by longer associated cycle times, based on our testing and delineation efforts during 2022;
◦13.1 MMBoe reduction primarily due to higher operating costs; offset by
◦13.7 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 45% as compared to December 31, 2021;
◦12.2 MMBoe increase primarily due to better results than previously forecasted on certain wells turned to production during 2022 in both the Permian and Eagle Ford.
•Decrease of 3.4 MMBoe for sales of reserves in place primarily associated with the divestitures of non-core assets primarily in the Western Delaware Basin; and
•Decrease of 38.1 MMBoe for production.
For the year ended December 31, 2021, the Company’s net increase in proved reserves of 8.7 MMBoe was primarily due to the following:
•Increase of 36.2 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 10.1 MMBoe were proved developed reserves;
•Decrease of 14.2 MMBoe for revisions of previous estimates that were primarily comprised of:
◦27.9 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 75% as compared to December 31, 2020; offset by
◦29.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation as well as changes in its development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window;
◦13.1 MMBoe reduction due to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts.
•Increase of 57.7 MMBoe for purchase of reserves in place associated with the Primexx Acquisition;
•Decrease of 36.0 MMBoe for sales of reserves in place associated with the Western Delaware Basin, Eagle Ford, and Midland non-core asset sales; and
•Decrease of 34.9 MMBoe for production.
Capitalized Costs
Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2023 | | 2022 |
Oil and natural gas properties: | | (In thousands) |
Proved properties | | $9,657,105 | | | $9,268,135 | |
Unproved properties | | 1,063,033 | | | 1,225,768 | |
Total oil and natural gas properties | | 10,720,138 | | | 10,493,903 | |
Accumulated depreciation, depletion, amortization and impairment | | (4,570,132) | | | (4,416,606) | |
Total oil and natural gas properties capitalized | | $6,150,006 | | | $6,077,297 | |
Costs Incurred
Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022 | | 2021 |
Acquisition costs: | | (In thousands) |
Proved properties | | $503,433 | | | $— | | | $677,250 | |
Unproved properties | | 78,144 | | | 32,548 | | | 301,404 | |
Development costs | | 872,808 | | | 742,991 | | | 396,181 | |
Exploration costs | | 113,782 | | | 133,080 | | | 137,989 | |
Total costs incurred | | $1,568,167 | | | $908,619 | | | $1,512,824 | |
Standardized MeasureControl
The following tables presenttable shows the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, includinggross taxable compensation payable upon a reductionqualifying termination following a change in control (“CIC”) or upon death, disability, involuntary termination without cause, or retirement. No amounts would be payable upon termination for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2023. You should not assumeother causes. The information assumes, in each case, that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows.
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2023 | | 2022 | | 2021 |
Oil ($/Bbl) | | $78.17 | | | $95.02 | | | $65.44 | |
Natural gas ($/Mcf) | | $1.53 | | | $5.75 | | | $3.31 | |
NGLs ($/Bbl) | | $22.27 | | | $36.40 | | | $29.19 | |
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
| | | | | | | | | | | | | | | | | | | | |
| | Standardized Measure |
| | For the Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| | (In thousands) |
Future cash inflows | | $21,804,152 | | | $33,424,190 | | | $23,775,358 | |
Future costs | | | | | | |
Production | | (8,850,777) | | | (10,702,897) | | | (8,038,362) | |
Development and net abandonment | | (1,943,594) | | | (2,326,789) | | | (1,927,789) | |
Future net inflows before income taxes | | 11,009,781 | | | 20,394,504 | | | 13,809,207 | |
Future income taxes | | (936,057) | | | (3,000,300) | | | (1,481,005) | |
Future net cash flows | | 10,073,724 | | | 17,394,204 | | | 12,328,202 | |
10% discount factor | | (4,639,540) | | | (8,390,068) | | | (6,077,447) | |
Standardized measure of discounted future net cash flows | | $5,434,184 | | | $9,004,136 | | | $6,250,755 | |
| | | | | | | | | | | | | | | | | | | | |
| | Changes in Standardized Measure |
| | For the Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| | (In thousands) |
Standardized measure at the beginning of the period | | $9,004,136 | | | $6,250,755 | | | $2,310,390 | |
Sales and transfers, net of production costs | | (1,428,805) | | | (2,208,492) | | | (1,466,413) | |
Net change in sales and transfer prices, net of production costs | | (3,387,434) | | | 4,168,425 | | | 4,336,078 | |
Net change due to purchases of in place reserves | | 868,016 | | | — | | | 797,327 | |
Net change due to sales of in place reserves | | (1,724,612) | | | (36,389) | | | (105,376) | |
Extensions, discoveries, and improved recovery, net of future production and development costs incurred | | 702,960 | | | 1,338,286 | | | 583,976 | |
Changes in future development cost | | 21,705 | | | (257,344) | | | (81,480) | |
Previously estimated development costs incurred | | 570,765 | | | 289,207 | | | 209,078 | |
Revisions of quantity estimates | | (1,217,925) | | | (215,828) | | | (104,572) | |
Accretion of discount | | 1,053,483 | | | 705,127 | | | 234,495 | |
Net change in income taxes | | 1,075,309 | | | (730,185) | | | (765,956) | |
Changes in production rates, timing and other | | (103,414) | | | (299,426) | | | 303,208 | |
Aggregate change | | (3,569,952) | | | 2,753,381 | | | 3,940,365 | |
Standardized measure at the end of period | | $5,434,184 | | | $9,004,136 | | | $6,250,755 | |
ITEM 9. Changes In and Disagreementswith Accountants on Accounting and Financial Disclosure
None.
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2023.
Changes in Internal Control Over Financial Reporting. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. GAAP. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an
evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2023 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reportingNEO’s termination was effective as of December 31, 2023.
Because In presenting this disclosure, we describe amounts earned through December 31, 2023, and, in those cases where the actual amounts to be paid out can only be determined at the time of its inherent limitations, internal control over financial reporting can provide only reasonable assurance thatsuch executive’s separation from us, the objectivesestimates are of the control system are metamounts which would be paid out to the executives upon their termination.
| | | | | | | | | | | | | | | | | |
NEO / Reason for Termination | Base Salary(a) | Cash Bonus(a) | Accelerated Cash Incentive and Stock Award Vesting(b)(c) | Continued Employee Benefits(d) | Total |
Joseph C. Gatto, Jr. | | | | | |
Change in Control | $ | — | $ | — | $ | — | $ | — | $ | — |
Change in Control Termination(e) | $ | 2,856,000 | $ | 5,205,659 | $ | 11,798,948 | $ | 45,789 | $ | 19,906,396 |
Death or Disability(f) | $ | — | $ | — | $ | 11,798,948 | $ | — | $ | 11,798,948 |
Retirement(g) | $ | — | $ | — | $ | — | $ | — | $ | — |
Involuntary Termination Without Cause(h) | $ | 1,904,000 | $ | 3,391,500 | $ | — | $ | 22,895 | $ | 5,318,395 |
Kevin Haggard | | | | | |
Change in Control | $ | — | $ | — | $ | — | $ | — | $ | — |
Change in Control Termination(e) | $ | 1,120,000 | $ | 1,556,070 | $ | 4,459,235 | $ | 46,126 | $ | 7,181,431 |
Death or Disability(f) | $ | — | $ | — | $ | 4,459,235 | $ | — | $ | 4,459,235 |
Retirement(g) | $ | — | $ | — | $ | — | $ | — | $ | — |
Involuntary Termination Without Cause(h) | $ | 840,000 | $ | 1,184,400 | $ | — | $ | 23,063 | $ | 2,047,463 |
Russell E. Parker | | | | | |
Change in Control | $ | — | $ | — | $ | — | $ | — | $ | — |
Change in Control Termination(e) | $ | 1,200,000 | $ | 1,624,500 | $ | 2,877,155 | $ | 45,917 | $ | 5,747,572 |
Death or Disability(f) | $ | — | $ | — | $ | 2,877,155 | $ | — | $ | 2,877,155 |
Retirement(g) | $ | — | $ | — | $ | — | $ | — | $ | — |
Involuntary Termination Without Cause(h) | $ | 900,000 | $ | 1,339,500 | $ | — | $ | 22,959 | $ | 2,262,459 |
Michol L. Ecklund | | | | | |
Change in Control | $ | — | $ | — | $ | — | $ | — | $ | — |
Change in Control Termination(e) | $ | 968,000 | $ | 1,415,310 | $ | 3,582,028 | $ | 45,646 | $ | 6,010,984 |
Death or Disability(f) | $ | — | $ | — | $ | 3,582,028 | $ | — | $ | 3,582,028 |
Retirement(g) | $ | — | $ | — | $ | — | $ | — | $ | — |
Involuntary Termination Without Cause(h) | $ | 726,000 | $ | 1,023,660 | $ | — | $ | 22,823 | $ | 1,772,483 |
Gregory F. Conaway | | | | | |
Change in Control | $ | — | $ | — | $ | — | $ | — | $ | — |
Change in Control Termination(e) | $ | 758,000 | $ | 880,313 | $ | 1,270,438 | $ | 46,234 | $ | 2,954,985 |
Death or Disability(f) | $ | — | $ | — | $ | 1,270,438 | $ | — | $ | 1,270,438 |
Retirement(g) | $ | — | $ | — | $ | — | $ | — | $ | — |
Involuntary Termination Without Cause(h) | $ | 568,500 | $ | 667,988 | $ | — | $ | 23,117 | $ | 1,259,605 |
Jeffrey S. Balmer(i) | | | | | |
Change in Control | $ | — | $ | — | $ | — | $ | — | $ | — |
Change in Control Termination(e) | $ | — | $ | — | $ | — | $ | — | $ | — |
Death or Disability(f) | $ | — | $ | — | $ | — | $ | — | $ | — |
Retirement(g) | $ | — | $ | — | $ | — | $ | — | $ | — |
Involuntary Termination Without Cause(h) | $ | — | $ | — | $ | — | $ | — | $ | — |
(a)In accordance with the Executive CIC Plan, the computation uses a 3x multiple with respect to the severance amount relating to salary and may not prevent or detect misstatements. In addition, any evaluationtarget bonus for Mr. Gatto, and a 2x multiple for each of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of complianceother NEOs. In accordance with the policies or procedures may deteriorate.
The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessmentSeverance Pay Plan, the computation uses a 2x multiple with respect to the severance amount relating to salary and target bonus for Mr. Gatto, and a 1.5x multiple for each of the Company’s internal control over financial reportingother NEOs. See “Employment Agreements, Termination of Employment and Change in Control Arrangements - Executive Severance Compensation Plans.”
(b)The amounts include the value of unvested CPUs as of December 31, 2023, presented precedingreflecting actual results through 2023 and target amounts for the Company’s financial statements includedremaining years of the performance period for termination due to change in Part II, Item 8control or death or disability. The value of this 2023 Annual Report on Form 10-K.
ITEM 9B.Other Information
None.
ITEM 9C.Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III.
ITEM 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by referenceunvested CPUs due to termination due to retirement are pro-rated for the definitive proxy statement (the “2024 Proxy Statement”) for our 2024 annual meeting of shareholders. Intime the event the 2024 Proxy Statement is not filedretirement eligible employee was employed with the SEC inCompany.
(c)The amounts include the 120-day period aftervalue of unvested stock awards as of December 31, 2023, using the information requiredclosing price of $32.40 per share of our common stock on the last trading day of 2023. The table above assumes that MSUs vest based on actual performance as of December 31, 2023. Actual vesting of MSUs would be determined based on the performance at the time of such NEO’s separation. Unvested stock awards are forfeited at the date of termination due to retirement.
(d)Benefits consist of 24 and 12 months of employer-provided family medical, dental and vision insurance for the NEOs in the table for termination due to change in control and involuntary termination, respectively.
(e)Each of the NEOs listed in the table above are eligible to receive benefits pursuant to the Executive CIC Plan. See “Employment Agreements, Termination of Employment and Change in Control Arrangements - Executive Severance Compensation Plans.”
(f)“Disability,” for purposes of the incentive awards is generally defined as the employee’s inability to carry out the normal and usual duties of the employee’s employment on a full-time basis for an entire period of six continuous months together with the reasonable likelihood, as determined by this itemthe Board after consultation of a qualified physician, the employee will be includedunable to carry out the employee’s normal and usual duties of employment.
(g)For purposes of the RSUs and CPUs, “Qualified Retirement” means the termination of employment with the Company, other than (x) for Cause or (y) due to death or Disability (each as defined in an amendmentthe applicable award agreements), on a date that is more than six months following the effective date, provided that, as of the date of such termination, the grantee (A) has attained a minimum of five years (RSUs) or three years (CPUs) of employment with the Company, (B) has attained the age of 60 (RSUs) or 55 (CPUs) and the sum of the grantee’s years of employment and the grantee’s age totals at least 65 (RSUs) or 60 (CPUs), (C) has provided the Company with notice of such intent to this 2023 Annual Report on Form 10-K that will be filedterminate at least six months prior to the termination date and satisfactorily completed the duties of his position up to the termination date, including any transition services reasonably requested by the Company, (D) enters into an agreement not laterto compete with, and not directly or indirectly induce any employee to leave the employment of, the Company, any subsidiary or affiliate for a period of at least one year following the grantee’s termination of employment, which agreement, in both form and substance, is provided by the Committee or is otherwise satisfactory to the Committee, and (E) timely executes (and does not revoke in any time provided to do so) a release of claims in favor of the Company in a form reasonably acceptable to the Committee. The retirement provisions in the CPU agreements are described above under “Employment Agreements, Termination of Employment and Change in Control Arrangements - Long-Term Incentive Award Agreements.” As of December 31, 2023, none of the NEOs were retirement eligible under this general definition.
(h)In accordance with the Severance Pay Plan, the computation uses a 2x multiple with respect to the severance amount relating to salary and target bonus for Mr. Gatto and a 1.5x multiple for the other NEOs. See “Employment Agreements, Termination of Employment and Change in Control Arrangements - Executive Severance Compensation Plans.”
(i)Actual amounts paid in connection with Dr. Balmer’s retirement are based above under the heading “Employment Agreements, Termination of Employment and Change in Control Arrangements - Separation Agreement.” Dr. Balmer is not eligible for any payments as a result of a Change in Control.
Pension and Non-Qualified Deferred Compensation Plans
We sponsor a 401(k) plan for all eligible employees, including the NEOs, as described above under the heading “Perquisites and Other Benefits.” We do not sponsor any qualified or non-qualified defined benefit plans, or any non-qualified defined contribution plan for NEOs or other employees. The Board or Committee may elect to adopt qualified or non-qualified defined benefit plans or non-qualified defined contribution plans in the future if it determines that doing so is in the Company’s best interest.
CEO Pay Ratio
Pursuant to a mandate of the Dodd-Frank Wall Street Reform and Consumer Protection Act, we are disclosing here that the ratio of our median employee’s compensation to the compensation of our CEO is 44:1.
We identified our median employee from the employee population as of December 31, 2023, by comparing the sum of the base salary, bonus, and any overtime paid to each employee that was employed by the Company on December 31, 2023. For any employees who were not employed the entire 2023 calendar year (excluding temporary and seasonal employees), we annualized the base salary, bonus, and any overtime.
In accordance with SEC rules, we determined the annual total compensation of our median employee for 2023 was $203,800. This amount represents the total compensation that would have been reported in the Summary Compensation Table in accordance with the requirements of Item 402(c)(x) of Regulation S-K for the median employee if the employee had been a NEO for fiscal year 2023. For purposes of calculating the ratio, an additional value of $23,900 was included in the annual compensation for non-discriminatory benefits bringing the annual total compensation to $227,701.
We determined the amount of the CEO’s annual total compensation was $10,027,187, which represents the amount reported for the CEO in the “Total” column of our 2023 Summary Compensation Table. For purposes of the ratio, an additional value of $24,729 was included in the annual total compensation for non-discriminatory benefits to bring the value to $10,051,916.
Based on the foregoing, for 2023, the ratio of the median of the annual total compensation of all employees to the annual total compensation of our CEO (the “CEO Pay Ratio”) is 44:1. This ratio demonstrates a higher pay ratio for 2023 than the end2022, largely due to Mr. Gatto’s one-time grant of such 120-day period.MSUs in April 2023.
The Company has adoptedCEO Pay Ratio is a code of ethics that applies to the Company’s officers, directors, employees, agentsreasonable estimate calculated in a manner consistent with SEC rules based on our payroll and representatives and includes a code of ethics for senior financial officers that applies to the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com.employment records.
Director Compensation
The information requiredcompensation of our non-employee directors is reviewed by this itemthe Committee and is incorporated hereinapproved by referencethe Board. We use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on the Board. In determining director compensation, we consider the responsibilities of our directors, the significant amount of time the directors spend fulfilling their duties, and the competitive market for skilled directors.
Annually, the Committee directly engages an independent compensation consultant to conduct an analysis of director compensation and recommend any adjustments to the 2024 Proxy Statement. Intotal annual compensation of the eventnon-employee directors. The consultant evaluates competitive market data, utilizing the 2024 Proxy Statement is not filedsame industry peer group used for executive compensation market data (see “Role of Independent Compensation Consultant” above).
For 2023, the Committee, with input from its compensation consultant FW Cook, recommended an increase to the cash retainer, the RSU grant value, and the chair fees for the non-executive chair and Audit Committee chair, all to align with the SECindustry peer group. The Committee recommended that all other chair fees remain consistent with the fees established in 2022.
Upon recommendation from the 120-day period afterCommittee, for 2023, the Board approved an increase to the cash retainer, the RSU grant value, and the chair fees for the non-executive chair and Audit Committee chair, while retaining the other chair fees consistent with 2022 amounts:
| | | | | | | | | | | | | | | | | | | | |
Fee Type | 2022 Compensation | 2023 Compensation |
Board Member Cash Retainer | | $ | 95,000 | | | | $ | 100,000 | | |
Restricted Stock Unit (“RSU”) Grant Value | | $ | 150,000 | | | | $ | 165,000 | | |
Total Director Compensation | | $ | 245,000 | | | | $ | 265,000 | | |
Chairmen Fees | | | | | | |
Non-Executive Chair | | $ | 120,000 | | | | $ | 130,000 | | |
Audit Committee Chair | | $ | 20,000 | | | | $ | 25,000 | | |
Compensation Committee Chair | | $ | 20,000 | | | | $ | 20,000 | | |
N&ESG Committee Chair | | $ | 20,000 | | | | $ | 20,000 | | |
Operations & Reserves Committee Chair | | $ | 20,000 | | | | $ | 20,000 | | |
Our director compensation program generally consists of cash retainers and an annual grant of RSUs awarded under the 2020 Plan. The RSU grants are awarded to match competitive practices and encourage long-term alignment with shareholders. Grants are made using the 20-day average closing stock price of Callon’s stock. The RSUs vest on the first anniversary following the grant date, or on the date of the Company’s subsequent Annual Meeting, whichever occurs first.
Each non-employee director is reimbursed for reasonable out-of-pocket costs incurred to attend Board and committee meetings and for director education. If a member of the Board is an officer or other employee of the Company, he or she does not receive compensation for his or her service as a director.
Non-employee directors have the opportunity to make an annual election to defer some or all of their cash retainer or annual stock award pursuant to the terms of a deferred compensation plan for non-employee directors (the “Deferred Compensation Plan”) until separation from service as a director. All deferrals under the plan are credited as phantom stock units of Callon common stock.
Callon’s non-employee directors are subject to stock ownership guidelines of five times the annual cash retainer of $100,000. As of December 31, 2023, all non-employee directors were in compliance with the stock ownership policy, either through meeting the ownership requirement or by being within the transition period. For more information required by this item will be includedon the stock ownership guidelines, see “Practices and Policies Related to Compensation - Stock Ownership Guidelines” above.
The table below indicates the total compensation earned during 2023 for each non-employee director. In addition to his role as a director, Mr. Gatto also serves as the Company’s President and CEO. His compensation is disclosed in the Summary Compensation Table.
Non-Employee Director Compensation for 2023
| | | | | | | | | | | | | | | | | | | | |
Director | Fees Earned or Paid in Cash(a) | | Stock Awards(b) | | | Total |
Frances Aldrich Sevilla-Sacasa | $ | 125,000 | (c) | $ | 145,673 | (d) | | $ | 270,673 |
Matthew R. Bob | $ | 230,000 | (e) | $ | 145,673 |
| | $ | 375,673 |
James E. Craddock | $ | 100,000 | (f) | $ | 145,673 | (d) | | $ | 245,673 |
Barbara J. Faulkenberry | $ | 120,000 | (g) | $ | 145,673 | | | $ | 265,673 |
L. Richard Flury(h) | $ | — | | $ | — | | | $ | — |
Anthony J. Nocchiero | $ | 120,000 | (i) | $ | 145,673 | | | $ | 265,673 |
Mary Shafer-Malicki | $ | 120,000 | (j) | $ | 145,673 | (d) | | $ | 265,673 |
James M. Trimble(h) | $ | — | | $ | — | | | $ | — |
Steven A. Webster | $ | 100,000 | (f)(k) | $ | 145,673 | (d) | | $ | 245,673 |
(a)Does not include reimbursement of expenses associated with attending Board and committee meetings and for board education.
(b)Amounts calculated utilizing the provisions of FASB ASC Topic 718. These amounts utilize a grant date fair value of $31.22 per share for the awards. The aggregate number of RSU awards outstanding as of December 31, 2023, for each director is 4,666, which RSUs are scheduled to vest on the earlier of either (i) April 26, 2024, or (ii) the date of the Company’s 2024 Annual Meeting of Shareholders.
(c)Represents annual retainer of $100,000 and an amendmentadditional $25,000 for acting as Chair of the Audit Committee.
(d)Director elected to thishave his/her equity award deferred pursuant to the terms of the Deferred Compensation Plan.
(e)Represents annual retainer of $100,000 and an additional $130,000 for acting as the non-executive Chair of the Board.
(f)Represents annual retainer of $100,000.
(g)Represents annual retainer of $100,000 and an additional $20,000 for acting as Chair of the N&ESG Committee.
(h)Messrs. Flury and Trimble retired from the Board effective as of the date of the 2023 Annual Report on Form 10-K that will be filed byMeeting.
(i)Represents annual retainer of $100,000 and an additional $20,000 for acting as Chair of the Company not later thanCompensation Committee.
(j)Represents annual retainer of $100,000, and an additional $20,000 for acting as Chair of the endOperations & Reserves Committee.
(k)Director elected to have his annual retainer deferred pursuant to the terms of such 120-day period.the Deferred Compensation Plan.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth beneficial ownership information requiredwith respect to our common stock as of March 15, 2024 for (i) each person known by this item is incorporated herein by referenceus to beneficially own 5% or more of our outstanding common stock; (ii) each of our NEOs, (iii) each of our directors, and (iv) all of our directors and current executive officers as of March 15, 2024, as a group. Unless otherwise noted, each person listed below has sole voting and investment power with respect to the 2024 Proxy Statement. Inshares of our common stock listed below as beneficially owned by the eventperson. Information set forth in the 2024 Proxy Statement is not filedtable with respect to beneficial ownership of common stock has been obtained from filings made by the named beneficial owners with the SEC as of March 15, 2024, or, in the 120-day period aftercase of our current executive officers and directors, has been provided to us by such individuals. As of March 15, 2024, the Company had 66,508,277 shares outstanding.
None of the shares beneficially owned by our executive officers or directors has been pledged as security for an obligation. Our Insider Trading Policy prohibits our executive officers and directors from holding Callon securities in a margin account or pledging Callon securities as collateral for a loan.
| | | | | | | | |
| Beneficial Ownership(1) |
Name of Beneficial Owner | Shares (#) | Percent of Class |
Holders of More Than 5%: | | |
BlackRock, Inc.(2) | 9,006,736 | | 13.5 | % |
The Vanguard Group, Inc.(3) | 6,766,114 | | 10.2 | % |
Blackstone Inc.(4) | 5,832,824 | | 8.8 | % |
State Street Corporation(5) | 4,864,678 | | 7.3 | % |
Dimensional Fund Advisors LP(6) | 3,414,233 | | 5.1 | % |
Named Executive Officers: | | |
Joseph C. Gatto, Jr.(7) | 178,838 | | * |
Kevin Haggard(8) | 28,385 | | * |
Russell E. Parker(9) | 16,646 | | * |
Michol L. Ecklund(10) | 40,746 | | * |
Gregory F. Conaway(11) | 49,080 | | * |
Jeffrey S. Balmer(12) | 28,734 | | * |
Directors: | | |
Frances Aldrich Sevilla-Sacasa(13) | 15,345 | | * |
Matthew R. Bob(14) | 23,197 | | * |
James E. Craddock(15) | 4,666 | | * |
Barbara J. Faulkenberry(16) | 20,009 | | * |
Anthony J. Nocchiero(17) | 28,982 | | * |
Mary Shafer-Malicki(18) | 8,944 | | * |
Steven A. Webster(19) | 844,929 | | 1.3 | % |
All Current Executive Officers and Directors as a Group (consisting of 12 persons)(20) | 1,259,767 | | 1.9 | % |
* Less than 1%
(1)The amounts shown for our directors and NEOs include, as of the March 15, 2024, (a) shares of common stock owned outright by the individual; and (b) shares of common stock that may be acquired within 60 days through the vesting or settlement of certain RSUs, if any. Until RSUs vest, these individuals have neither voting nor investment power over the underlying shares of common stock, and share amounts are represented on a pre-tax basis. As of the March 15, 2024, none of the directors or executive officers held any stock options to purchase shares of Company stock.
(2)BlackRock, Inc. (“BlackRock”), in its capacity as a parent holding company or control person for various subsidiaries (none of which individually owns more than 5% of our outstanding common stock), may be deemed to beneficially own the indicated shares. BlackRock has sole voting power of 8,890,992 shares and sole dispositive power of 9,006,736 shares. BlackRock does not have shared voting power or shared dispositive power over any shares. BlackRock’s address is 50 Hudson Yards, New York, NY 10001. This information is based on BlackRock’s most recent Statement on Schedule 13G, which was filed on January 23, 2024.
(3)The Vanguard Group, Inc. (“Vanguard”), in its capacity as an investment adviser, may be deemed to beneficially own the indicated shares, along with certain of its wholly-owned subsidiaries that serve as investment managers. Vanguard does not have sole voting power over any shares, but has shared voting power over 38,022 shares, sole dispositive power over 6,676,478 shares and shared dispositive power over 89,636 shares. Vanguard’s address is 100 Vanguard Blvd., Malvern, PA 19355. This information is based on Vanguard’s most recent Statement on Schedule 13G filed on March 11, 2024.
(4)Represents 5,832,824 shares held directly by BPP HoldCo LLC. BPP HoldCo LLC maintains sole voting and sole dispositive power of 5,832,824 shares.
BX Primexx Topco LLC is the sole member of BPP HoldCo LLC. BCP VII/BEP II Holdings Manager L.L.C. is the managing member of BX Primexx Topco LLC. Blackstone Energy Management Associates II L.L.C. and Blackstone Management Associates VII L.L.C. are the managing members of BCP VII/BEP II Holdings Manager L.L.C. Blackstone EMA II L.L.C. is the sole member of Blackstone Energy Management Associates II L.L.C. BMA VII L.L.C. is the sole member of Blackstone Management Associates VII L.L.C. Blackstone Holdings III L.P. is the managing member of each of BMA VII L.L.C. and Blackstone EMA II L.L.C. Blackstone Holdings III GP L.P. is the general partner of Blackstone Holdings III L.P. Blackstone Holdings III GP Management L.L.C. is the general partner of Blackstone Holdings III GP L.P. Blackstone Inc. is the sole member of Blackstone Holdings III GP Management L.L.C. The sole holder of the Series II preferred stock of Blackstone Inc. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. The address of the principal business office of Blackstone Inc. is 345 Park Avenue, New York, NY 10154. The above information is based on the most recent Statement on Schedule 13D of Blackstone Inc. and the other entities referred to above, which was filed on January 25, 2023.
(5)State Street Corp. (“State Street”), in its capacity as a parent holding company or control person for various subsidiaries, may be deemed to beneficially own the indicated shares, along with certain of its wholly-owned subsidiaries that serve as investment managers. State Street has shared voting power over 4,813,023 shares and shared dispositive power over 4,864,678 shares. State Street’s subsidiary, SSGA Funds Management, Inc. (“SSGA”), has shared voting power over 3,703,926 shares and shared dispositive power over 3,715,026 shares. Neither State Street nor SSGA has sole voting or sole dispositive power over any shares. State Street’s principal business address is State Street Financial Center, One Congress St., Suite 1, Boston, MA 02114. This information is based on State Street’s most recent Statement on Schedule 13G, which was filed on January 25, 2024.
(6)Dimensional Fund Advisors LP (“Dimensional”), in its capacity as an investment adviser, may be deemed to beneficially own the indicated shares, along with certain of its wholly-owned subsidiaries that serve as investment managers. Dimensional has sole voting power over 3,396,029 shares and sole dispositive power over 3,414,233 shares. Dimensional does not have shared voting or shared dispositive power over any shares. Dimensional’s address is 6300 Bee Cave Road, Building One, Austin, TX 78746. This information is based on Dimensional’s most recent Statement on Schedule 13G filed on February 9,2024.
(7)Comprised of 134,323 shares held directly by Mr. Gatto and 44,515 unvested RSUs payable in stock that will vest within 60 days of March 15, 2024. Does not include 214,565 unvested RSUs (consisting of 129,061 payable in stock and 85,504 payable in cash) and 100,000 unvested Market Stock Units payable in stock.
(8)Comprised of 11,334 shares held directly by Mr. Haggard and 17,051 unvested RSUs payable in stock that will vest within 60 days of March 15, 2024. Does not include 111,499 unvested RSUs (consisting of 73,503 payable in stock and 37,996 payable in cash).
(9)Comprised of 8,509 shares held directly by Mr. Parker and 8,137 unvested RSUs payable in stock that will vest within 60 days of March 15, 2024. Does not include 130,366 unvested RSUs (consisting of 88,478 payable in stock and 41,888 payable in cash).
(10)Comprised of 27,043 shares held directly by Ms. Ecklund and 13,703 unvested RSUs payable in stock that will vest within 60 days of March 15, 2024. Does not include 83,992 unvested RSUs (consisting of 58,563 payable in stock and 25,429 payable in cash).
(11)Comprised of 43,193 shares held directly by Mr. Conaway and 5,887 unvested RSUs payable in stock that will vest within 60 days of March 15, 2024. Does not include 31,655 unvested RSUs (consisting of 18,932 payable in stock and 12,723 payable in cash).
(12)Comprised of 28,734 shares held directly by Dr. Balmer.
(13)Comprised of 10,679 shares held directly by Ms. Aldrich Sevilla-Sacasa, which includes 8,332 vested deferred RSUs, pursuant to Ms. Aldrich Sevilla-Sacasa’s election under the Deferred Compensation Plan, which are payable in cash upon her separation of service as a director, and 4,666 unvested deferred RSUs, pursuant to Ms. Aldrich Sevilla-Sacasa’s election under the Deferred Compensation Plan, which are payable in cash upon her separation of service as a director and that will vest within 60 days of March 15, 2024. Does not include 5,230 unvested RSUs payable in stock.
(14)Comprised of 18,531 shares held directly by Mr. Bob and 4,666 unvested RSUs payable in stock that will vest within 60 days of March 15, 2024. Does not include 5,230 unvested RSUs payable in stock.
(15)Comprised of 4,666 unvested deferred RSUs, pursuant to Mr. Craddock’s election under the Deferred Compensation Plan, which are payable in cash upon his separation of service as a director and that will vest within 60 days of March 15, 2024. Does not include 5,230 unvested deferred RSUs, pursuant to Mr. Craddock’s election under the Deferred Compensation Plan, which are payable in cash upon his separation of service as a director.
(16)Comprised of 15,343 shares held directly by Ms. Faulkenberry and 4,666 unvested RSUs payable in stock that will vest within 60 days of March 15, 2024. Does not include 5,230 unvested RSUs payable in stock.
(17)Comprised of 24,316 shares held directly by Mr. Nocchiero and 4,666 unvested RSUs payable in stock that will vest within 60 days of March 15, 2024. Does not include 5,230 unvested RSUs payable in stock.
(18)Comprised of 4,278 vested deferred RSUs, pursuant to Ms. Shafer-Malicki’s election under the Deferred Compensation Plan, which are payable in cash upon her separation of service as a director, and 4,666 unvested deferred RSUs, pursuant to Ms. Shafer-Malicki’s election under the Deferred Compensation Plan, which are payable in cash upon her separation of service as a director and that will vest within 60 days of March 15, 2024. Does not include 5,230 unvested deferred RSUs, pursuant to Ms. Shafer-Malicki’s election under the Deferred Compensation Plan, which are payable in cash upon her separation of service as a director.
(19) Comprised of 626,388 shares held directly by Mr. Webster, which includes 16,180 vested deferred RSUs, pursuant to Mr. Webster’s election under the Deferred Compensation Plan, which are payable in cash upon his separation of service as a director, 64,500 shares held indirectly with his spouse, 149,375 shares held indirectly through San Felipe Resources Company, and 4,666 unvested deferred RSUs, pursuant to Mr. Webster’s election under the Deferred Compensation Plan, which are payable in cash upon his separation of service as a director and that will vest within 60 days of March 15, 2024. Does not include 5,230 unvested RSUs payable in stock.
(20) Comprised of 923,937 shares held directly by the Company’s current executive officers and directors, 64,500 shares held indirectly by a spouse, 149,375 shares held indirectly by San Felipe Resources Company, and 121,955 unvested RSUs payable in stock that will vest within 60 days of March 15, 2024.
Equity Compensation Plan Information
The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2023,2023.
| | | | | | | | | | | | | | | | | |
Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)(1) | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in column (a)) (c)(2) |
Equity compensation plans approved by security holders | 854,964 | | | $ | — | | 1,326,047 | |
Equity compensation plans not approved by security holders | — | | $ | — | | — |
Total | 854,964 | | | $ | — | | 1,326,047 | |
(1) The weighted-average exercise prices of outstanding options is omitted because no options or equity-based stock appreciation rights were outstanding as of December 31, 2023.
(2) Relates to remaining shares available for issuance under our stock-based compensation plans for our executives, employees and non-employee directors.
Change in Control
Other than the information required by this itemproposed Merger, pursuant to which APA Corporation will be included in an amendment to this 2023 Annual Report on Form 10-K that will be filed byacquire the Company, not later thanthere are no arrangements, including any pledge by any person of securities of the endCompany, the operation of such 120-day period.which may at a subsequent date result in a change in control of the Company. More information regarding the proposed Merger is contained in Part 2, Item 7 of the Original Report under the caption “Management’s Discussion And Analysis Of Financial Condition And Results Of Operations-Recent Developments.”
ITEM 13. Certain Relationships and Related Transactions and Director Independence
Certain Relationships and Related Party Transactions
The informationAudit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required by this itemto be disclosed under Item 404 of Regulation S-K. In addition, our Code provides that an officer’s or a director’s conflict of interest with Callon may only be waived if the Audit Committee approves the waiver and the full Board ratifies the waiver.
We are not aware of any related party transactions that require disclosure under Item 404 of Regulation S-K.
Director Independence
To minimize potential conflicts, it is incorporated herein by reference toa policy of the 2024 Proxy Statement.Board that a majority of the Board be independent. In the event the 2024 Proxy Statement is not filedaccordance with the SEC instandards for companies listed on the 120-day period after December 31, 2023,NYSE and the information required by this item will be included in an amendment to this 2023 Annual Report on Form 10-K that will be filedrules and regulations promulgated by the SEC, as well as our Corporate Governance Guidelines, the Board considers a director to be independent if it has affirmatively determined that the director has no material relationship with the Company not laterthat could compromise his or her ability to exercise independent judgment in carrying out his or her responsibilities. The Board revisits the independence of each director on an annual basis and makes independence determinations when a newly appointed director joins the Board between annual meetings. The Board reviewed the independence of its directors in accordance with the standards described above and affirmatively determined that each of the directors (other than the end of such 120-day period.Mr. Gatto) is independent.
ITEM 14. Principal Accountant Fees and Services
Fees
The informationfollowing table sets forth the fees incurred by us for services performed by Grant Thornton LLP in the fiscal years 2022 and 2023:
| | | | | | | | |
Fee Category | 2022 | 2023 |
Audit fees(a) | $ | 1,315,000 | | $ | 1,465,000 | |
Audit-related fees(b) | $ | 125,000 | | $ | — | |
Tax fees(c) | $ | — | | $ | — | |
All other fees(d) | $ | — | | $ | — | |
Total | $ | 1,440,000 | | $ | 1,465,000 | |
(a)Audit fees consist of the aggregate fees billed for professional services related to the audit and quarterly reviews of our financial statements and for services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements.
(b)Audit-related fees consist of the aggregate fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements that are not reported above under “Audit fees.”
(c)Tax fees consist of the aggregate fees billed for professional services rendered for tax compliance (including filing state and federal tax returns), tax advice and tax planning. Tax fees do not include fees for services rendered in connection with the audit.
(d)Other fees consist of the aggregate fees billed for professional services other than the services reported above.
Pre-approval Policy
The Audit Committee pre-approves all audit and permissible non-audit services (including the fees and terms thereof) exceeding $25,000 to be performed on behalf of the Company by our independent registered public accounting firm, as required by this item is incorporated herein by referenceapplicable law or listing standards and subject to the 2024 Proxy Statement. Interms of the event the 2024 Proxy Statement is not filedaudit and non-audit services pre-approval policy in accordance with the SEC inAudit Committee charter. The Committee may delegate authority to one or more of its members when appropriate, including the 120-day period after December 31, 2023,authority to grant pre-approvals of audit and permitted non-audit services, provided that any decisions to grant pre-approvals are consistent with the information required by this item will be included in an amendmentterms of the delegation and the Audit Committee charter and are presented to this 2023 Annual Report on Form 10-K that will be filed by the Company not later than the end of such 120-day period.full Audit Committee at its next scheduled meeting.
PART IV.IV
ITEM15. Exhibits and Financial Statement Schedules
(a) Documents filed as part of this 2023 Annual Report on Form 10-K:Amendment No. 1:
(1) Financial Statements
See index to Financial Statements and Supplementary Data on page 61. of the Original Report. (2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.thereto, which are contained in the Original Report.
(3) Exhibits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Incorporated by reference (File No. 001-14039, unless otherwise indicated) |
Exhibit Number | | Description | | Form | | Exhibit | | Filing Date |
2.1 | (d) | | | | 8-K | | 2.1 | | 07/15/2019 |
2.2 | | | | | 10-Q | | 2.2 | | 11/05/2019 |
2.3 | | | | | 8-K | | 2.1 | | 11/14/2019 |
2.4 | (d) | | | | 8-K | | 10.1 | | 05/08/2023 |
2.5 | (d) | | | | 8-K | | 10.2 | | 05/08/2023 |
2.6 | (d) | | | | 8-K | | 2.1 | | 01/04/2024 |
3.1 | | | | | 10-Q | | 3.1 | | 11/03/2016 |
3.2 | | | | | 8-K | | 3.1 | | 12/20/2019 |
3.3 | | | | | 8-K | | 3.1 | | 08/07/2020 |
3.4 | | | | | 8-K | | 3.1 | | 05/14/2021 |
3.5 | | | | | 8-K | | 3.1 | | 05/25/2022 |
3.6 | | | | | 10-K | | 3.2 | | 02/27/2019 |
4.1 | | | | | 10-K | | 4.1 | | 02/28/2018 |
4.2 | (a) | | | | | | | | |
4.3 | | | | | 8-K | | 4.1 | | 06/07/2018 |
4.4 | | | | | 8-K | | 4.4 | | 12/20/2019 |
4.5 | | | | | 8-K | | 4.2 | | 06/07/2018 |
4.6 | | | | | 8-K | | 4.5 | | 12/20/2019 |
4.7 | | | Indenture, dated as of July 6, 2021, by and among the Company, Callon Petroleum Operating Company, Callon (Eagle Ford) LLC, Callon (Niobrara) LLC, Callon (Permian) LLC, Callon (Permian) Minerals LLC, Callon (Utica) LLC, Callon Marcellus Holding, Inc. and U.S. Bank National Association, as trustee | | 8-K | | 4.1 | | 07/07/2021 |
4.8 | | | | | 10-K | | 4.17 | | 02/24/2022 |
4.9 | | | | | 10-K | | 4.18 | | 02/24/2022 |
4.10 | | | | | 8-K | | 4.1 | | 11/08/2021 |
4.11 | | | Indenture, dated as of June 24, 2022, by and among Callon Petroleum Company, Callon Petroleum Operating Company, Callon (Permian) LLC, Callon (Eagle Ford) LLC, Callon (Permian) Minerals LLC, Callon (Niobrara) LLC, Callon (Utica) LLC and Callon Marcellus Holding, Inc. and U.S. Bank Trust Company, National Association, as trustee | | 8-K | | 4.1 | | 06/24/2022 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Incorporated by reference (File No. 001-14039, unless otherwise indicated) |
Exhibit Number | | Description | | Form | | Exhibit | | Filing Date |
2.1 | (e) | | | | 8-K | | 2.1 | | 07/15/2019 |
2.2 | | | | | 10-Q | | 2.2 | | 11/05/2019 |
2.3 | | | | | 8-K | | 2.1 | | 11/14/2019 |
2.4 | (e) | | | | 8-K | | 10.1 | | 05/08/2023 |
2.5 | (e) | | | | 8-K | | 10.2 | | 05/08/2023 |
2.6 | (e) | | | | 8-K | | 2.1 | | 01/04/2024 |
3.1 | | | | | 10-Q | | 3.1 | | 11/03/2016 |
3.2 | | | | | 8-K | | 3.1 | | 12/20/2019 |
3.3 | | | | | 8-K | | 3.1 | | 08/07/2020 |
3.4 | | | | | 8-K | | 3.1 | | 05/14/2021 |
3.5 | | | | | 8-K | | 3.1 | | 05/25/2022 |
3.6 | | | | | 10-K | | 3.2 | | 02/27/2019 |
4.1 | | | | | 10-K | | 4.1 | | 02/28/2018 |
4.2 | | | | | 10-K | | 4.2 | | 02/25/2021 |
4.3 | | | | | 8-K | | 4.1 | | 06/07/2018 |
4.4 | | | | | 8-K | | 4.4 | | 12/20/2019 |
4.5 | | | | | 8-K | | 4.2 | | 06/07/2018 |
4.6 | | | | | 8-K | | 4.5 | | 12/20/2019 |
|
4.7 | | | Indenture, dated as of July 6, 2021, by and among the Company, Callon Petroleum Operating Company, Callon (Eagle Ford) LLC, Callon (Niobrara) LLC, Callon (Permian) LLC, Callon (Permian) Minerals LLC, Callon (Utica) LLC, Callon Marcellus Holding, Inc. and U.S. Bank National Association, as trustee | | 8-K | | 4.1 | | 07/07/2021 |
4.8 | | | | | 10-K | | 4.17 | | 02/24/2022 |
4.9 | | | | | 10-K | | 4.18 | | 02/24/2022 |
4.10 | | | | | 8-K | | 4.1 | | 11/08/2021 |
4.11 | | | Indenture, dated as of June 24, 2022, by and among Callon Petroleum Company, Callon Petroleum Operating Company, Callon (Permian) LLC, Callon (Eagle Ford) LLC, Callon (Permian) Minerals LLC, Callon (Niobrara) LLC, Callon (Utica) LLC and Callon Marcellus Holding, Inc. and U.S. Bank Trust Company, National Association, as trustee | | 8-K | | 4.1 | | 06/24/2022 |
4.12 | 4.12 | | | | | 8-K | | 4.1 | | 07/07/2023 | 4.12 | | | | | 8-K | | 4.1 | | 07/07/2023 |
4.13 | 4.13 | | | | | 10-Q | | 4.2 | | 08/02/2023 | 4.13 | | | | | 10-Q | | 4.2 | | 08/02/2023 |
4.14 | 4.14 | | | | | 10-Q | | 4.3 | | 08/02/2023 | 4.14 | | | | | 10-Q | | 4.3 | | 08/02/2023 |
4.15 | 4.15 | | | | | 10-Q | | 4.4 | | 08/02/2023 | 4.15 | | | | | 10-Q | | 4.4 | | 08/02/2023 |
10.1 | 10.1 | (d) | | | | 8-K | | 10.1 | | 10/24/2022 | 10.1 | (e) | | | | 8-K | | 10.1 | | 10/24/2022 |
10.2 | 10.2 | (b) | | | | 10-K | | 10.11 | | 02/28/2018 | 10.2 | (d) | | | | 10-K | | 10.11 | | 02/28/2018 |
10.3 | 10.3 | (b) | | | | 10-K | | 10.7 | | 02/27/2020 | 10.3 | (d) | | | | 10-K | | 10.7 | | 02/27/2020 |
10.4 | 10.4 | (b) | | | | 10-K | | 10.23 | | 02/27/2019 | 10.4 | (d) | | | | 10-K | | 10.23 | | 02/27/2019 |
10.5 | 10.5 | (b) | | | | 10-K | | 10.23 | | 02/27/2020 | 10.5 | (d) | | | | 10-K | | 10.23 | | 02/27/2020 |
10.6 | 10.6 | (b) | | | | 10-K | | 10.24 | | 02/27/2020 | 10.6 | (d) | | | | 10-K | | 10.24 | | 02/27/2020 |
10.7 | 10.7 | (b) | | | | 10-K | | 10.25 | | 02/27/2020 | 10.7 | (d) | | | | 10-K | | 10.25 | | 02/27/2020 |
10.8 | 10.8 | (b) | | | | DEF 14A | | B | | 04/28/2020 | 10.8 | (d) | | | | DEF 14A | | B | | 04/28/2020 |
10.9 | 10.9 | (b) | | | | 8-K | | 10.5 | | 04/16/2021 | 10.9 | (d) | | | | 8-K | | 10.5 | | 04/16/2021 |
10.10 | 10.10 | (b) | | | | 10-Q | | 10.3 | | 08/05/2020 | 10.10 | (d) | | | | 10-Q | | 10.3 | | 08/05/2020 |
10.11 | 10.11 | (b) | | | | 10-Q | | 10.4 | | 08/05/2020 | 10.11 | (d) | | | | 10-Q | | 10.4 | | 08/05/2020 |
10.12 | 10.12 | (b) | | | | 10-Q | | 10.4 | | 11/03/2020 | 10.12 | (d) | | | | 10-Q | | 10.4 | | 11/03/2020 |
10.13 | 10.13 | (b) | | | | 10-Q | | 10.5 | | 11/03/2020 | 10.13 | (d) | | | | 10-Q | | 10.5 | | 11/03/2020 |
10.14 | 10.14 | (b) | | | | 10-K | | 10.29 | | 02/25/2021 | 10.14 | (d) | | | | 10-K | | 10.29 | | 02/25/2021 |
10.15 | 10.15 | (b) | | | | 8-K | | 10.1 | | 04/16/2021 | 10.15 | (d) | | | | 8-K | | 10.1 | | 04/16/2021 |
10.16 | 10.16 | (b) | | | | 8-K | | 10.2 | | 04/16/2021 | 10.16 | (d) | | | | 8-K | | 10.2 | | 04/16/2021 |
10.17 | 10.17 | (b) | | | | 10-Q | | 10.3 | | 11/03/2022 | 10.17 | (d) | | | | 10-Q | | 10.3 | | 11/03/2022 |
10.18 | (b) | | | | 10-Q | | 10.1 | | 05/05/2022 |
10.19 | (b) | | | | 10-Q | | 10.4 | | 11/03/2022 |
10.20 | (b) | | | | 10-Q | | 10.2 | | 05/05/2022 |
10.21 | (b) | | | | 10-Q | | 10.5 | | 11/03/2022 |
10.22 | (b) | | | | 10-Q | | 10.1 | | 08/02/2023 |
10.23 | (b) | | | | 10-Q | | 10.1 | | 11/03/2022 |
10.24 | (b) | | | | 10-Q | | 10.2 | | 11/03/2022 |
10.25 | (b) | | | | 10-Q | | 10.1 | | 11/01/2023 |
10.26 | (b) | | | | 10-Q | | 10.2 | | 11/01/2023 |
21.1 |
22.1 |
22.1 |
22.1 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
23.1 | (a) | | | | | | | | |
23.2 | (a) | | | | | | | | |
31.1 | (a) | | | | | | | | |
31.2 | (a) | | | | | | | | |
32.1 | (c) | | | | | | | | |
97.1 | (a) | | | | | | | | |
99.1 | (a) | | | | | | | | |
101.INS | (a) | | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
101.SCH | (a) | | Inline XBRL Taxonomy Extension Schema Document | | | | | | |
101.CAL | (a) | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | | | | | | |
101.DEF | (a) | | Inline XBRL Taxonomy Extension Definition Linkbase Document. | | | | | | |
101.LAB | (a) | | Inline XBRL Taxonomy Extension Label Linkbase Document. | | | | | | |
101.PRE | (a) | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | | | | | | |
104 | (a) | | Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
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10.18 | (d) | | | | 10-Q | | 10.1 | | 05/05/2022 |
10.19 | (d) | | | | 10-Q | | 10.4 | | 11/03/2022 |
10.20 | (d) | | | | 10-Q | | 10.2 | | 05/05/2022 |
10.21 | (d) | | | | 10-Q | | 10.5 | | 11/03/2022 |
10.22 | (d) | | | | 10-Q | | 10.1 | | 08/02/2023 |
10.23 | (d) | | | | 10-Q | | 10.1 | | 11/03/2022 |
10.24 | (d) | | | | 10-Q | | 10.2 | | 11/03/2022 |
10.25 | (d) | | | | 10-Q | | 10.1 | | 11/01/2023 |
10.26 | (d) | | | | 10-Q | | 10.2 | | 11/01/2023 |
21.1 | (b) | | | | | | | | |
22.1 | (b) | | | | | | | | |
23.1 | (b) | | | | | | | | |
23.2 | (b) | | | | | | | | |
31.1 | (a) | | | | | | | | |
31.2 | (a) | | | | | | | | |
32.1 | (c) | | | | | | | | |
97.1 | (b) | | | | | | | | |
99.1 | (b) | | | | | | | | |
101.INS | (b) | | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
101.SCH | (b) | | Inline XBRL Taxonomy Extension Schema Document | | | | | | |
101.CAL | (b) | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | | | | | | |
101.DEF | (b) | | Inline XBRL Taxonomy Extension Definition Linkbase Document. | | | | | | |
101.LAB | (b) | | Inline XBRL Taxonomy Extension Label Linkbase Document. | | | | | | |
101.PRE | (b) | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | | | | | | |
104 | (a) | | Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
(a)Filed herewith.
(b)Indicates management compensatory plan, contract, or arrangement.Previously filed with the Original Report.
(c)Furnished herewith.Previously furnished with the Original Report. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.
(d) Indicates management compensatory plan, contract, or arrangement.
(e) Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Callon agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request.
ITEM 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
| | | | | | | | | | | | | | | | | | | | | | | |
| Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | Callon Petroleum Company | | | | | |
| | | | | | | |
| | | | | | | |
| | /s/ Kevin Haggard | | Date: | | February 26,March 29, 2024 | |
| | By: Kevin Haggard | | | | | |
| | Chief Financial Officer (principal financial officer) | | | | | |
APPENDIX A
| | | | | | | |
PursuantNON-GAAP RECONCILIATIONS | | | |
Adjusted EBITDAX (in thousands): | | | 2023 |
Net income | | | $ | 401,201 | |
Adjustments: | | | |
Gain on derivatives contracts | | | $ | (18,898) | |
Gain on commodity derivative settlements, net | | | $ | 11,841 | |
Non-cash expense related to the requirementsshare-based awards | | | $ | 11,413 | |
Impairment of the Securities Exchange Actoil and gas properties | | | $ | 406,898 | |
Gain on sale of 1934, this report has been signed belowoil and gas properties | | | $ | (23,476) | |
Merger, integration, and transaction | | | $ | 11,198 | |
Other income | | | $ | (6,684) | |
Income tax benefit | | | $ | (189,808) | |
Interest expense | | | $ | 179,305 | |
Depreciation, depletion and amortization | | | $ | 535,661 | |
Exploration | | | $ | 9,143 | |
Gain on extinguishment of debt | | | $ | (1,238) | |
Adjusted EBITDAX | | | $ | 1,326,556 | |
| | | | | | | | |
Adjusted Free Cash Flow (in thousands): | | | | 2023 |
Net cash provided by the following persons on behalf of the registrantoperating activities | | | | $ | 1,092,529 | |
Changes in working capital and other | | | | $ | 40,146 | |
Change in the capacitiesaccrued hedge settlements | | | | $ | 8,919 | |
Merger, integration and on the dates indicated.transaction | | | | $ | 11,198 | |
Cash flow from operations before net change in working capital | | | | $ | 1,152,792 | |
| | | | |
Capital expenditures | | | | $ | 968,982 | |
Decrease in accrued capital expenditures | | | | $ | (4,251) | |
Capital expenditures before accruals | | | | $ | 964,731 | |
| | | | |
Adjusted Free Cash Flow | | | | $ | 188,061 | |
| | | | | | | |
Net Debt (in thousands) | | | /s/ Joseph C. Gatto, Jr.2023 |
Total debt | | | Date:$ | | February 26, 20241,918,655 | |
| | Joseph C. Gatto, Jr. (principal executive officer)Unamortized premiums, discount, and deferred loan costs, net | | | $ | 17,128 | |
Adjusted total debt | | | $ | 1,935,783 | |
Less: Cash and cash equivalents | | | $ | 3,325 | |
Net Debt | | | $ | 1,932,458 | |
| | | | | | | |
Total Operating Cash Margin (in thousands, except per Boe data): | | | /s/ Kevin Haggard2023 |
Total operating revenues | | | Date:$ | | February 26, 20241,953,901 | |
| | Kevin Haggard (principal financial officer)Less: | | | | | |
| | | | | | | |
Lease operating expense | | /s/ Gregory F. Conaway$ | | Date: | | February 26, 2024303,363 | |
| | Gregory F. Conaway (principal accounting officer) Production and ad valorem taxes | | | | | |
| | | | | | | |
| | /s/ Matthew R. Bob$ | | Date: | | February 26, 2024113,512 | |
| | Matthew R. Bob (chairman of the board of directors) Gathering, transportation and processing | | | | | |
| | | | | | | |
| | /s/ Frances Aldrich Sevilla-Sacasa$ | | Date: | | February 26, 2024108,221 | |
| | Frances Aldrich Sevilla-Sacasa (director)Total | | | | | |
| | | | | | | |
| | /s/ James E. Craddock | | Date:$ | | February 26, 20241,428,805 | |
| | James E. Craddock (director)Total production in barrels of oil equivalent | | | | | |
| | | | | | | |
| | /s/ Barbara J. Faulkenberry | | Date: | | February 26, 202437,587 | |
| | Barbara J. Faulkenberry (director)Total Operating Cash Margin per Boe | | | | | |
| | | | | | | |
| | /s/ Anthony J. Nocchiero$ | | Date:38.01 | | February 26, 2024 | |
| | Anthony J. Nocchiero (director) | | | | | |
| | | | | | | |
| | /s/ Mary Shafer-Malicki | | Date: | | February 26, 2024 | |
| | Mary Shafer-Malicki (director) | | | | | |
| | | | | | | |
| | /s/ Steven A. Webster | | Date: | | February 26, 2024 | |
| | Steven A. Webster (director) | | | | | |