Table of ~~fluid waste. In December 2021, the Texas Railroad Commission suspended the deep injection of wastewater in the Gardendale Seismic Response Area.~~cont ents

Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves.

Commodity prices are volatile. Significant and rapid declines in prices have occurred in the past and may occur in the future. Low commodity prices could result in, among other things, significant impairment charges in the future. For example, we incurred impairment charges in a number of recent periods, including charges of $882.4 million ~~and $38.5 million~~ in 2020, ~~and 2019, respectively,~~ to write down assets. Similarly, the significant decline in commodity pricing ~~during~~that occurred in 2020 resulted in a reduced year-end proved reserve NYMEX price of $39.57 per barrel of crude and $1.99 per MMBtu of natural gas, a decrease of 29% and 23% respectively, from 2019. The decline in pricing resulted in a downward revision of 28.2 MMBoe to our reserves for year-end 2020 when compared to year-end 2019. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, the outlook for forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date the estimate of future cash flows is made for each producing basin. A significant decrease in long-term forward prices could result in a significant impairment for our properties.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. In determining the estimates of reserve and economic evaluations, management utilizes independent petroleum engineers. The reserve estimates are based on assumptions regarding commodity prices, production levels and operating and development costs that may prove to be incorrect. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate and revisions in existing reserve estimates occur.

Reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates, in part because they will not be produced under the same economic conditions as are used for the reserve calculations.

You should not assume that the present value of the estimated future net cash flows from our proved reserves is the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, are based on the average of the previous 12-months’ first day of the month prices and costs as of the date of the estimate. Actual future prices and costs may be materially different. 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. Significant variances could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K and cause potential impairment charges. Sensitivity of our proved reserves as of December 31, 2022, assuming specified decreases in crude oil prices, are disclosed in Oil and Gas Production and Operations section in Item 1 and 2. Business and Properties, included elsewhere in this report. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows (the rate required by the SEC) may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general.

Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned.

Producing crude oil, natural gas and NGL reservoirs are generally characterized by declining production rates that may vary over time and exceed our estimates depending upon reservoir characteristics and other factors. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations.

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We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including:

•crude oil, natural gas and NGL prices;

•the availability and cost of capital;

•drilling and production costs;

•availability and cost of drilling rigs, and equipment, supplies, chemicals, personnel and oilfield services;

•drilling results;

•lease expirations or limitations as to depth;

•midstream constraints;

•access to and availability of water sourcing and distribution systems;

•regulatory approvals; and

•other factors.

Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Conversely, a decrease in well density could result in fewer locations in an area but possibly increased production performance on a per-well basis. For example, after examining well performance and other factors, we ~~recently~~ determined in 2021 that our ~~current~~ Delaware Basin position ~~supports~~supported fewer wells per unit than previously assumed. Accordingly, ~~as of December 31, 2021,~~ our estimated well locations for our ~~current~~ Delaware Basin position decreased from 135 to ~~65.~~65 in 2021.

Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances to facilitate exploration, though Colorado now requires applicants to own or secure consent from the owners of more than 45 percent of the minerals to be pooled. Other states, notably Texas, restrict involuntary pooling to a much narrower set of circumstances that generally do not apply to our leases and consequently these states rely primarily on voluntary pooling of lands and leases. In states such as Texas where pooling is accomplished primarily on a voluntary basis, or in states such as Colorado if we cannot meet the minimum requirement for ownership and consent, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than all (or cannot secure the ownership or consent of the required minimum amount) of the leasehold in the proposed units or one or more of our leases in the proposed units does not provide the necessary pooling

authority. If third parties in the proposed units are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, which would limit the total horizontal wells we can drill. Further, the number of available locations will depend in part on the expected lateral lengths of the horizontal wells we drill. Because the intended lateral length of a horizontal well is subject to change for a variety of reasons, our estimated drilling locations will change over time. For this and numerous other reasons, our actual drilling activities may materially differ from those presently identified.

Our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally continued a steady pace of development in the Wattenberg Field over the past several years, and while ~~the SRC Acquisition~~ our business acquisitions haveincreased our inventory, continued development has reduced our inventory of drilling locations. We also anticipate that our remaining locations in the field will not, on average, be as productive or as economic as many of those we have drilled in recent years, due to lower anticipated overall production or higher gas-to-oil ratios.In the Delaware Basin, our inventory is subject to, among other things, potential lease expirations (as to acreage and/or depths) and our continued analysis of geologic challenges in certain areas. For example, as noted above, in 2021, we ~~recently~~ reduced our estimated number of locations in the Delaware Basin due to geological issues.

The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities and productive wells may be less successful than we expect.

A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists

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cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to the quantity of the hydrocarbons in those structures. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and plugged and abandoned in accordance with applicable regulations. For example, in 2022, our drilling activity in the third Bone Spring formation resulted in an exploratory dry hole. This generally results in the loss of the entire cost of drilling and completion to that point. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. For example, the data we use to model anticipated results from wells in a particular area may prove to be not representative of actual results from typical wells in the area, and this could result in production that falls short of estimates reflected in our internal business plans and/or guidance, “type curve” or other disclosures we make to the public. This risk is higher for us in certain areas in the Delaware Basin that have relatively complex geological characteristics and correspondingly greater variability in well results. In addition, initial results from a well are not necessarily indicative of its performance over a longer period.

Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including:

•pressures or irregularities in geological formations;

•fires;

•floods, winter storms and other natural disasters and adverse weather conditions;

•loss of well control;

•loss of drilling fluid circulation and other facility or equipment malfunctions;

•title problems;

•facility or equipment malfunctions;

•unexpected operational events;

•shortages or delays in the delivery of equipment and services;

•inflation in exploration, drilling, completion and production costs;

•unanticipated environmental liabilities; and

•compliance with environmental and other governmental requirements.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, loss of wells, pollution, environmental contamination and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. In addition, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for which we have no effective insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third-party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites.

In addition, certain technical risks relating to the drilling of horizontal wells - including those relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - have increased in recent years because we have increased the average lateral length of the horizontal wells we drill. Longer-lateral wells are also typically more expensive and require more time for preparation. In addition, we use multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence

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simultaneously. While we believe that we will be better served by using multi-well pads with longer lateral wells, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program.

~~The inability of one~~Our customers, counterparties and lenders may be unable to satisfy their contractual or ~~more of our customers or other counterparties to meet their obligations may adversely affect our financial results.~~legal obligations.

~~Substantially all~~We are exposed to certain risks associated with our customers, contractual counterparties and lenders. These risks include credit risks associated with (i) customers who purchase our oil, NGLs and natural gas production, (ii) the collection of receivables from our joint interest partners for their proportionate share of expenditures made on projects we operate, and (iii) counterparties to our derivative financial contracts. We are also subject to performance risks associated with the non-delivery, or delayed delivery, of contracted products or services, including the transportation and processing of our ~~accounts receivable result from our crude~~ oil, NGLs and natural gas production and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives expose us to creditliquidity risk in the event ~~of nonperformance by counterparties. Nonperformance by our customers~~one or ~~derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the~~more lenders under our ~~revolving~~existing credit facility ~~and the providers of our insurance coverage.~~

~~We participate in oil and gas operations with third parties who may not be able~~are unable to ~~fulfill~~perform their ~~commitments to our projects.~~

We frequently own less than all of the working interest in the oil and gas leases and/or wells on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities, arising from the actions of the other owners. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy.funding obligations. In the event ~~any of our project partners does not pay its share of such costs, we would likely have~~a customer, contractual counterparty or lender fails to ~~pay those costs, and we may be unsuccessful in any efforts to recover the costs from the partner. This could materially adversely affect our financial position.~~

~~We may not be able to keep pace with technological developments in our industry.~~

Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and 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 or if we were unable to use the most advanced technology,satisfy their obligations, our business, financial condition and results of operations could be materially and adversely affected.

Competition in our industry is intense, which may adversely affect our ability to succeed.

Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects, or evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. Additionally, larger competitors may have greater financial, technical and personnel resources that may provide technological advantages and may in the future allow them to implement new technologies before we can. These factors could adversely affect our operations and our profitability.

Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.

Further, our operations require laborers, including contractors, skilled in multiple disciplines, such as heavy equipment operators, mechanics and engineers, among others. A ~~failure~~shortage in skilled labor can increase the risk of safety issues, decrease our overall productivity and business results and increase the labor, health care and benefits costs we incur to ~~complete successful acquisitions would limit our ability to replace our reserves~~attract and ~~impact our financial condition.~~

Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete asset exchanges and other acquisitions that allow us to increase our working interests in particular properties. We may not be able to identify attractive acquisition opportunities, and if we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable termsretain high quality employees with the ~~seller, finance~~right skill sets to meet our needs. For example, in 2022 we experienced an increase in contractor injuries at our worksites, many attributable to the ~~acquisition or obtain~~labor conditions in the necessary regulatory approvals. If we are unable to complete suitable acquisitions on acceptable terms, it will be more difficult to replace our reserves, and an inability to replace our reserves would haveoilfield, including a ~~material adverse effect on our financial condition and results~~greater number of ~~operations.~~short-service contractor employees.

Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential ~~liabilities, including~~ environmental ~~uncertainties.~~and other liabilities.

Acquisitions of producing and undeveloped properties have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological and geophysical reviews of the acquired properties that we believe are generally consistent with customary industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess

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their deficiencies and capabilities. We do not typically inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise after the acquisition. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor.

When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities,

including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire.

Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price and any related increase in interest expense or other related charges.

Some of our acquisitions are structured as asset trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange or overvalue the properties we receive. Such an undervaluation or overvaluation would result in the transaction being less favorable to us than we expected.

We operate in a litigious environment. The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, employment litigation, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. For example, in January 2021, a purported class action lawsuit was filed against us by a royalty owner alleging we have been improperly deducting certain post-production costs from the owner’s oil royalty payments. While we intend to vigorously defend this suit,the outcome of legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management attention and other factors. In addition, the resolution of any such legal or other proceedings could result in penalties or sanctions, settlement costs and/or judgments, consent decrees or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. Information regarding legal proceedings can be found in Item 3. Legal Proceedings included elsewhere in this report.

Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions.

We face various security threats, including attempts by third parties to gain unauthorized access to, or control of, competitive information or to render data or systems corrupted or unusable; threats to the safety of our employees; threats to the security of our infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient to prevent them from materializing.

Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to store, transmit, process and record sensitive information (including but not limited to trade secrets, employee information and financial and operating data), communicate with our employees and business partners, and for many other activities related to our business. In addition, computer systems control

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the oil and gas production and processing equipment that are necessary to deliver our production to market. Critical infrastructure targets, such as energy-related assets and transportation assets, may be at greater risk of future cyber-attacks than other targets. A disruption or failure of these systems, or of the networks and infrastructure on which they rely, may cause damage to critical production, distribution and/or storage assets, delay or prevent delivery to markets, or make it difficult to accurately account for production and settle transactions. The various procedures, facilities, infrastructure and controls we utilize to monitor these threats and mitigate our exposure to such threats are costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. The continuing and evolving threat of cybersecurity attacks has resulted in increased regulatory focus on prevention, which could potentially elevate costs, and failure to comply with these regulations could result in penalties and potential legal liability.

As dependence on digital technologies has increased in our industry cyber incidents, including deliberate attacks and unintentional events, have also increased. Our systems and infrastructure are, and those of our business partners, including vendors, service providers, operating partners, purchasers of our production and financial institutions may be, subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. We and our business partners also face various other cyber-security threats from criminal hackers, state-sponsored intrusion, industrial espionage and employee malfeasance, including threats to gain access to sensitive information or to render data or systems unusable.

Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business ~~operations.~~operations and planned business transactions. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. To our knowledge, we have not suffered material losses related to cyber-attacks to date; however, there can be no assurance that we will not suffer material losses in the future either as a result of an interruption to or a breach of our systems or those of our third-party vendors and service providers. If we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. Insurance may not provide adequate protection from these risks. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.

The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. An economy-wide transition to lower GHG energy sources could have a variety of adverse effects on our operations and financial results.

Many scientists have shown that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth’s atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such events were to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance.

Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. As a result, if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Efforts by governments, international bodies, businesses and consumers to reduce GHGs and otherwise mitigate the effects of climate change are ongoing. The nature of these efforts and their effects on our business are inherently unpredictable and subject to change. Certain regulatory responses to climate change issues are discussed above under the heading “We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business. Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us” and in Items 1 and 2 - Business and Properties - Governmental Regulation. However, actions taken by private parties in anticipation of, or to facilitate, a transition to a lower-GHG economy will affect us as well. For example, our cost of capital may increase if lenders or other market participants decline to invest in fossil fuel-related companies for regulatory or reputational reasons. Similarly, increased demand for low-carbon or renewable energy sources from consumers could reduce the demand for, and the price of, the products we produce. Technological changes, such as developments in renewable energy and low-carbon transportation, could also adversely affect demand for our products.

Risks Relating to Financial Matters

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. Lender hesitancy to offer financing to our industry may increase this risk.

Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated from operations and proceeds

from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including:

•our proved reserves;

•the amount of crude oil, natural gas and NGLs we are able to produce from existing wells;

•the prices at which crude oil, natural gas and NGLs are sold;

•the costs to produce crude oil, natural gas and NGLs; and

•our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense.

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Additionally, due to ~~recent default rates in the oil and gas industry and other factors,~~increasing climate change awareness, some lenders have expressed a hesitancy to lend to oil and gas producers, and may require terms less favorable to the producers or, in some cases, may refuse to provide financing to the industry altogether. The number of lenders participating in our revolving credit facility decreased in connection with the amendment and restatement of the facility in 2021, and may decline further in the future. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability.

The cost of servicing, and risks related to refinancing, our debt could adversely affect our business. Those risks could increase if we incur more debt.

As of December 31, ~~2021,~~2022, we had a total long-term debt of ~~$950 million.~~$1.32 billion. Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash, and cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control.

A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, reducing our capital expenditures, selling assets, refinancing all or a portion of our existing debt or obtaining additional financing. We may ~~or may~~ not be able to complete any such steps on satisfactory terms. Any ~~ability~~inability to generate sufficient cash flows to satisfy our debt obligations or contractual commitments, or to refinance our debt on commercially reasonable terms, could materially and adversely affect our financial condition and results of operations. In addition, our financing costs are affected by changing macroeconomic factors, including in particular interest rates. For example, under our revolving credit facility, one of the applicable interest rates on amounts borrowed at the end of 2021 was 0.1% and has since increased to 4.4% as of the end of 2022, resulting in higher costs on our outstanding debt.

Covenants in our debt agreements currently impose, and future financing agreements may impose, operating and financial restrictions.

Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to:

•incur additional debt;

•pay dividends on, redeem or repurchase stock;

•create certain liens;

•make specified types of investments;

•apply net proceeds from certain asset sales;

•engage in transactions with our affiliates;

•engage in sales and leaseback transactions;

•merge or consolidate; and

•sell, assign, transfer, lease, convey or dispose of assets.

Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in our current operating subsidiaries. The restrictions contained in our current or future debt agreements, including the possible addition of ESG-related metrics pursuant to our existing amended and restated credit agreement, may prevent us from taking actions that we believe would be in the best interest of our ~~business.~~business, or may increase cost of borrowings in the future. In addition, our ability to comply with covenants and restrictions in our debt agreements in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of these restrictions and covenants could result in a default under our debt agreements. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder, and under other agreements to which a cross-default or cross-acceleration provision applies, to be due and payable, together with accrued and unpaid interest; the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation.

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Our lenders have sole discretion to set our borrowing availability based on anticipated commodity prices and corporate outlook.

The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas or NGLs may have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately unless we pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results.

Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income.

We use commodity derivatives for a portion of the production from our own wells to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity.

At December 31, ~~2021,~~2022, we had hedged a total of ~~22.2~~25.3 MMBbls crude oil for ~~2022~~2023 to ~~2024~~2025 and ~~102.5 MMBtu~~214.8 BBtu of natural gas for ~~2022 and 2023.~~2023 to 2025. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices.

Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income.

We may be unable to return capital to our stockholders, and there is no assurance we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.

Starting in 2022, we adopted a return of capital program with a quarterly base dividend and a return of approximately 60 percent or more of our post base dividend adjusted free cash flows, a non-U.S. GAAP financial measure, through stock repurchases and special dividends, as needed. Additionally, since the first quarter of 2022, our board of directors has approved the increases in quarterly base dividend from $0.12 per share to $0.40 per share. Our ability to pay cash dividends and to otherwise return capital to shareholders in the future depends on, among other things, our liquidity, financial condition, financial requirements, contractual restrictions, restrictions imposed by applicable law and other factors considered relevant by our board. Our board, based on this evaluation, may decide not to declare future dividends or otherwise return capital to shareholders, or may do so at levels that are less than anticipated.

Our capital return program may change from time to time, and we cannot guarantee we will continue to pay dividends or repurchase shares. Our announcement of capital return programs does not obligate us to pay any particular dividend amount (except with respect to dividends already declared) or repurchase any specific dollar amount or number of shares of common stock. A reduction, suspension or change in our capital return programs could have a negative effect on our stock price.

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The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.

The market price of our common stock is highly volatile and we expect it to continue to be volatile for the foreseeable future. Adverse events including changes in production volumes, worldwide demand and prices for crude oil and natural gas, regulatory developments, and changes in securities analysts’ estimates of our financial performance could negatively impact the market price of our common stock. General market conditions, including the level of, and fluctuations in, the trading prices of ~~stocks~~securities generally could also have a similar negative impact. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes.

~~Risks Relating to Pending Great Western Acquisition~~

If completed, the Great Western Acquisition may not achieve its intended results and may result in us assuming unanticipated liabilities. To date, we have conducted only limited diligence regarding the assets and liabilities we would assume in the transaction.

We entered into the Purchase Agreement with the expectation that the Great Western Acquisition would result in various benefits, growth opportunities and synergies. Achieving the anticipated benefits of the transaction is subject to a number of risks and uncertainties. For example, under the Purchase Agreement, we have the opportunity to conduct customary environmental and title due diligence following the execution of the agreement, but our diligence efforts to date have been limited. As a result, we may discover title defects or adverse environmental or other conditions of which we are currently unaware. Environmental, title and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We would assume substantially all of the liabilities associated with the acquired properties and would be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure you that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant.

As with other acquisitions, the success of the Great Western Acquisition depends on, among other things, the accuracy of our assessment of the reserves and drilling locations associated with the acquired properties, future oil, NGL and natural gas prices and operating costs and various other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price for the acquisition from the sale of production from the property or recognize an acceptable return from such sales.

~~The reserves, production and drilling locations estimates with respect to the properties to be acquired in the Great Western Acquisition may differ materially from the actual amounts.~~

Our estimates of the reserves, production and drilling locations associated with the properties to be acquired in the Great Western Acquisition are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines. Such analysis is based, in significant part, on data provided by the sellers. We cannot assure you that these estimates are accurate. After such data is further reviewed by us and our independent engineers, the actual reserves, production and number of viable drilling locations may differ materially from the amounts we have estimated.

The transactions contemplated by the Purchase Agreement are subject to conditions that may not be satisfied on a timely basis or at all. Failure to complete the transactions contemplated by the Purchase Agreement could have material and adverse effects on us.

Completion of the Great Western Acquisition is subject to a number of conditions, including the accuracy of the parties’ representations in the Purchase Agreement and the receipt of certain governmental approvals. Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the completion of the Great Western Acquisition uncertain. In addition, the Purchase Agreement contains certain termination rights for both Great Western and us, which if exercised will also result in the Great Western Acquisition not being consummated. Furthermore, the governmental authorities from which the federal regulatory approvals are required may impose conditions on the completion of the Great Western Acquisition or requireTax law changes ~~to the terms of the acquisition or the Purchase Agreement.~~

If the transactions contemplated by the Purchase Agreement are not completed, our business may be adversely affected and, without realizing any of the benefits of having completed the Great Western Acquisition, we will be subject to a number of risks, including the following: we will be required to pay our costs relating to the Great Western Acquisition, such as legal, accounting, and financial advisory fees; time and resources committed by our management to matters relating to the Great Western Acquisition could otherwise have been devoted to pursuing other beneficial opportunities; and the market price of our common stock could be impacted to the extent that the current market price reflects a market assumption that the Great Western Acquisition will be completed. In addition, if the Purchase Agreement is terminated and the Board seeks another acquisition, we cannot be certain that we will be able to find a party willing to enter into a transaction as attractive to us as the Great Western Acquisition.

~~We will be subject to business uncertainties while the Great Western Acquisition is pending, which could adversely affect our business.~~

It is possible that certain persons with whom we have a business relationship may delay certain business decisions relating to us, or seek to terminate, change or renegotiate their relationships with us, in connection with the pendency of the Great Western~~Acquisition. This could negatively affect our revenues, earnings and cash flows, as well as the market price of our common stock, regardless of whether the Great WesternAcquisition is completed. Also, our ability to attract, retain and motivate employees may be impaired until the Great WesternAcquisition is completed and for a period of time thereafter as current and prospective employees may experience uncertainty about their roles within the combined company following the transaction.~~

~~In addition, under the terms of the Purchase Agreement, we are subject to certain restrictions on the conduct of our business prior to the completion of the Great Western~~Acquisition, which may adversely affect our ability to execute certain of our business strategies. Such limitations could negatively affect our business and operations prior to the completion of the Great Western~~Acquisition.~~

~~Even if the Great Western Acquisition is completed, we may not achieve the anticipated benefits and the Great Western Acquisition may disrupt our current plans or operations.~~

~~The success of the Great Western~~Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and Great Western’s businesses, and there can be no assurance that we will be able to successfully integrate Great Western~~or otherwise realize the anticipated benefits of the Great WesternAcquisition. Difficulties in integrating Great Western~~into our company may result in us 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, among others:

•~~the inability to successfully integrate Great Western into PDC in a manner that permits us to achieve the full cost savings or operating synergies anticipated from the Great Western Acquisition;~~

•~~complexities associated with managing a larger, more complex, integrated business;~~

•~~the disruption or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.~~

~~We are expected to incur significant transaction costs in connection with the Great Western Acquisition, which may be in excess of those we currently anticipate.~~

~~We expect to incur a number of non-recurring costs associated with negotiating and completing the Great Western~~Acquisition, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial and, in many cases, will be borne by us whether or not the Great Western~~Acquisition is completed. A substantial majority of our non-recurring expenses will consist of transaction costs related to the Great Western~~Acquisition and include, among others, fees paid to financial, legal, accounting and other advisors. We will also incur transaction costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and other employment-related costs. We will continue to assess the magnitude of these costs, and we may incur additional unanticipated costs. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not offset integration-related costs and achieve a net benefit in the near term or at all. The costs described above and any unanticipated costs and expenses, many of which will be borne by us even if the Great Western~~Acquisition is not completed,~~ could have an adverse effect on our financial ~~condition~~position, results of operations and ~~operating results.~~cash flows.

~~After the Great Western Acquisition is completed, PDC will be proportionally more exposed~~As of December 31, 2022, we have fully released our tax valuation allowance and we anticipate incurring federal and state income taxes in 2023. In addition, substantive changes to ~~regulatory risks associated with~~existing federal income tax laws have been proposed that, if adopted, would repeal many tax incentives and deductions that are currently used by U.S. oil and gas ~~operations~~companies and would impose new taxes. The proposals include: repeal of the percentage depletion allowance for oil and gas properties; elimination of the ability to fully deduct intangible drilling costs in ~~Colorado~~the year incurred; and ~~other risks associated with~~an increase in the geological and geophysical amortization period for independent producers. Additional proposed general tax law changes include raising tax rates on both domestic and foreign income and imposing a ~~more geographically-concentrated asset base.~~new alternative minimum tax on book income. Further, many states are currently in deficits, and have been enacting laws eliminating or limiting certain deductions, carryforwards and credits in order to increase tax revenue. Should the U.S. or any relevant state pass tax legislation limiting any currently allowed tax incentives or deductions, our taxes would increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities. Since future changes to federal and state tax legislation and regulations are unknown, we cannot predict the ultimate impact such changes may have on our business.

PDC's principal assets in terms of production and reserves are located in the Wattenberg Field located within the Denver-Julesburg Basin of Colorado, but we also have a significant acreage position in the Delaware Basin in Texas. During 2021, 87 percent of PDC's production came from its assets in Colorado and 13 percent came from its assets in Texas. All of Great Western’s properties, and all of its current production and reserves, are located in Colorado. Various new regulatory requirements applicable to oil and natural gas operations in Colorado have been proposed or adopted in recent years as described elsewhere in this report.

The increased percentage of PDC's combined production located in the Wattenberg Field following the Great Western Acquisition will proportionately increase PDC's exposure to risks associated with operating in a more concentrated geographic area, including Colorado-specific regulatory and midstream risks as described elsewhere in this section.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

Information regarding our legal proceedings can be found in Note 1312 - Commitments and Contingencies - Litigation and Legal Items included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report.

Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of ~~December 31, 2021 which~~the date of the filing of this report that have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses in the consolidated balance sheets.

Following a self-audit of final reclamation activities associated with site retirements, we formally disclosed identified deficiencies to the Colorado Oil and Gas Conservation Commission (“COGCC”) in December 2019. ~~In August 2020, the COGCC issued a Notice of Alleged Violation (“NOAV”) citing a failure to comply with reclamation requirements at multiple locations.~~ To resolve the alleged violations in July of 2021, the COGCC and PDC jointly agreed to an Administrative Order by Consent (“AOC”) which assessed penalties in the amount of approximately $500,000, with approximately $350,000 suspended pending PDC meeting certain conditions of the AOC. We are implementing programs to meet the requirements of the AOC and correct any identified deficiencies.

OnCommencing in early 2020, we conducted a comprehensive air quality compliance audit over the facilities acquired in

Table of cont ents

the SRC Acquisition. Through the self-audit process, we identified certain deficiencies and disclosed them to CDPHE and the EPA in July 2021. We do not believe potential penalties and other expenditures associated with the deficiencies identified will have a material effect on our financial condition or results of operations, but such penalties may exceed $300,000.

In August ~~30,~~ 2021 and November 1, 2021, the COGCC issued us ~~NOAVs~~a Notice of Alleged Violation (“NOAV”) related to the timing of wellhead pressure test reporting for certain wells in the Wattenberg Field. Pursuant to the NOAVs, we have conducted and submitted a comprehensive audit of our wellhead pressure testing and reporting processes. We ~~are actively updating~~have updated our processes to mitigate against the possibility of the alleged violations occurring in the future. We do not anticipate a material effect on our financial condition or results of operations. However, the potential penalties may exceed $300,000.

~~Commencing in early 2020,~~In June 2022, we ~~conducted a comprehensive~~received Compliance Advisories from the Colorado Air Pollution Control Division for alleged historical air quality ~~compliance audit~~violations over ~~the~~ facilities acquired in

the SRC Acquisition. ~~Through~~In January 2023, we paid a total penalty of approximately $340,000 to resolve and settle the ~~self-audit process,~~Compliance Advisories.

In July 2022, we ~~identified certain deficiencies~~received a Notice of Violation/Cease and ~~disclosed them~~Desist Order (“NOV”) from the CDPHE, pursuant to a Great Western Operating Company May 2021 Stormwater Permit Audit and subsequent Compliance Advisory. Having acquired the ~~Colorado Department of Public Health~~Great Western assets on May 6, 2022, we are working with the CDPHE to ensure ongoing compliance and ~~Environment (“CDPHE”) and~~resolve the ~~U.S. Environmental Protection Agency (“EPA”) in July 2021.~~NOV. We do not ~~believe~~anticipate potential penalties and other expenditures associated with the ~~deficiencies identified~~NOV will have a

material effect on our financial condition or results of operations, but such penalties ~~may~~will likely exceed $300,000.

Clean Air Act Agreement and Related Consent Decree. WeWhile we continue to implement the requirements of a consent decree entered into with the EPA and CDPHE in 2017, as well as a revised compliance order on consent, the latter of which was modified by the CDPHE after the SRC Acquisition was completed. Per the terms of the agreements, we will apply for termination in early 2022. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with thesuch consent decree ~~including any sanctions associated~~was terminated with ~~these deficiencies, will have a material effect on our financial condition or results~~no further penalties as of ~~operations, but they may exceed $300,000.~~December 15, 2022.

Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

3834

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Holders of Record

Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol “PDCE”. As of February ~~15, 2022,~~14, 2023, we had approximately ~~386~~363 stockholders of record.

~~In May 2021, our~~Dividend Policy

Our board of directors ~~approved~~have authority to declare dividends to the ~~Company’s quarterly dividend program and we announced the initiation of a quarterly dividend in the amount of $0.12 per share~~holders of our common stock. ~~We declared and paid an aggregate amount~~Our board of ~~$0.86 per share~~directors intent is to continue the payment of dividends to the holders of our common stock ~~during 2021, which included a special dividend of $0.50 per share of our common stock declared and paid~~ in the ~~fourth quarter of 2021. The~~future. However, the dividend program and payment of any future dividends ~~thereunder~~ will be made at the discretion of our board of directors and will depend on our results of operations, cash flows, financial position and capital requirements, as well as general business conditions, legal, tax and regulatory ~~restrictions and other~~ factors ~~our board of directors deems~~deemed relevant at the time ~~it determines~~ to declare such dividends.

Additionally, our revolving credit facility, as well as the indentures governing our 6.125% senior notes due 2024 (“2024 Senior ~~Notes~~Notes”) and our 5.75% senior notes due 2026 (the “2026 Senior Notes”), the terms of which are summarized in Note 109 - Long-term Debt in Item 8. Financial Statements and Supplementary Data included elsewhere in this report, include restrictions based on our leverage and certain other ~~certain~~ financial metrics that could impact our ability to pay cash dividends. As we declare dividends in the future, we will monitor compliance with such restrictions.

Repurchase of Equity Securities

The following table presents information about our purchases of our common stock during the year ended December 31, ~~2021:~~2022:


Period	Period	Total Number of Shares Purchased (1) (2)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions)		Period	Total Number of Shares Purchased (1) (2)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions)
January	January	28,831	$	23.27	—	$	346.8	January	592,567	$	55.54	501,000	$	159.5
February	February	53,401	32.25		2,289	346.7		February	71,735	56.73		4,340	1,250.0
March	March	596,388	36.99		595,460	324.7		March	825,680	69.71		820,555	1,192.8
April	April	345,614	35.36		255,268	315.7		April	714,091	74.22		613,658	1,147.4
May	May	211,555	40.14		210,310	307.3		May	1,382,199	69.33		1,381,407	1,051.6
June	June	201,576	46.39		196,070	298.2		June	970,777	75.74		970,777	978.1
July	July	283,191	41.10		280,000	286.7		July	866,538	58.71		864,738	927.3
August	August	915,811	39.30		915,000	250.7		August	2,187,393	63.38		2,187,240	788.7
September	September	281,058	43.47		281,058	238.5		September	1,153,214	62.22		1,153,214	716.9
October	October	54,680	45.54		50,000	236.2		October	718,215	67.82		714,088	668.5
November	November	275,200	54.48		275,200	221.2		November	1,797,291	76.78		1,785,771	531.3
December	December	692,800	48.95		692,800	187.3		December	1,148,300	66.69		1,148,300	454.7
Total purchases	Total purchases	3,940,105	$	42.16	3,753,455	$	187.3	Total purchases	12,428,000	$	67.71	12,145,088	$	454.7


Delaware			95-2636730
(State of incorporation)			(I.R.S. Employer Identification No.)


Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐


	PART I	Page

Items 1. and 2.	Business and Properties	3
Item 1A.	Risk Factors	2320
Item 1B.	Unresolved Staff Comments	3833
Item 3.	Legal Proceedings	3833
Item 4.	Mine Safety Disclosures	3834

	PART II

Item 5.	Market for the ~~Registrant~~’sRegistrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	3935
Item 6.	[Reserved]	4137
Item 7.	~~Management~~’sManagement’s Discussion and Analysis of Financial Condition and Results of Operations	4137
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	6358
Item 8.	Financial Statements and Supplementary Data	6560
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~108~~101
Item 9A.	Controls and Procedures	~~108~~101
Item 9B.	Other Information	~~108~~101
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	~~108~~101

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	~~109~~102
Item 11.	Executive Compensation	~~109~~102
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~109~~102
Item 13.	Certain Relationships and Related Transactions and Director Independence	~~109~~102
Item 14.	Principal Accounting Fees and Services	~~109~~102

	PART IV

Item15.	Exhibits, Financial Statement Schedules	~~109~~102
Item 16.	Form 10-K Summary	~~109~~102

	Signatures	~~112~~105

	Glossary of Units of Measurements and Industry Terms	~~113~~106


		Year Ended/As of							Year Ended/As of
		December 31,						Percent Change				December 31,						Percent Change
		2021			2020			2021-2020				2022			2021			2022-2021
		(production and reserves in MMBoe, dollars in millions)								(production and reserves in MMBoe, dollars in millions)
Wells:	Wells:										Wells:
Gross productive wells	Gross productive wells	3,471			3,727			(7)	%		Gross productive wells	4,098			3,471			18	%
Net productive wells	Net productive wells	2,675			2,841			(6)	%		Net productive wells	3,152			2,675			18	%
Horizontal percentage	Horizontal percentage	66		%	57		%	16	%		Horizontal percentage	74		%	66		%	12	%
Gross operated wells turned-in-line	Gross operated wells turned-in-line	167			137			22	%		Gross operated wells turned-in-line	183			167			10	%
Net operated wells turned-in-line	Net operated wells turned-in-line	160.4			129.5			24	%		Net operated wells turned-in-line	169			160			6	%
Production:	Production:										Production:
Wattenberg Field	Wattenberg Field	61.9			57.5			8	%		Wattenberg Field	74.0			61.9			20	%
Delaware Basin	Delaware Basin	9.4			10.8			(13)	%		Delaware Basin	11.0			9.4			17	%
Total	Total	71.3			68.4			4	%		Total	85.0			71.3			19	%
Reserves:	Reserves:										Reserves:
Proved reserves	Proved reserves	814.2			731.1			11	%		Proved reserves	1,100			814			35	%
Proved developed reserves percentage	Proved developed reserves percentage	49		%	44		%	11	%		Proved developed reserves percentage	47		%	49		%	(4)	%
Standardized measure	Standardized measure	$	7,908.2		$	3,282.2		141	%		Standardized measure	$	14,987		$	7,908		90	%
PV-10 (1)	PV-10 (1)	$	9,708.8		$	3,454.6		181	%		PV-10 (1)	$	19,053		$	9,709		96	%

Liquidity		1,514			1,400			8	%
Available liquidity (2)											Available liquidity (2)	1,116			1,514			(26)	%
Leverage ratio	Leverage ratio	0.6			1.7			(65)	%		Leverage ratio	0.5			0.6			(17)	%


		December 31,							December 31,
		2021		2020		2019			2022		2021		2020
Proved reserves	Proved reserves							Proved reserves
Crude oil and condensate (MMBbls)	Crude oil and condensate (MMBbls)	214		212		197		Crude oil and condensate (MMBbls)	270		214		212
Natural gas (Bcf)	Natural gas (Bcf)	2,160		1,901		1,558		Natural gas (Bcf)	2,893		2,160		1,901
NGLs (MMBbls)	NGLs (MMBbls)	240		203		154		NGLs (MMBbls)	348		240		203
Total proved reserves (MMBoe)	Total proved reserves (MMBoe)	814		731		611		Total proved reserves (MMBoe)	1,100		814		731

Proved developed reserves (MMBoe)	Proved developed reserves (MMBoe)	399		322		214		Proved developed reserves (MMBoe)	518		399		322
Standardized measure (in millions)	Standardized measure (in millions)	$	7,908	$	3,282	$	3,310	Standardized measure (in millions)	$	14,987	$	7,908	$	3,282
Estimated undiscounted future net cash flows (in millions) (1)	Estimated undiscounted future net cash flows (in millions) (1)	$	13,872	$	5,633	$	5,896	Estimated undiscounted future net cash flows (in millions) (1)	$	26,916	$	13,872	$	5,633
PV-10 (in millions) (2)	PV-10 (in millions) (2)	$	9,709	$	3,455	$	3,837	PV-10 (in millions) (2)	$	19,053	$	9,709	$	3,455


Operating Region/Area	Operating Region/Area	Crude Oil and Condensate (MMBbls)	Natural Gas (Bcf)	NGLs (MMBbls)	Crude Oil Equivalent (MMBoe)	Percent		Operating Region/Area	Crude Oil and Condensate (MMBbls)	Natural Gas (Bcf)	NGLs (MMBbls)	Crude Oil Equivalent (MMBoe)	Percent
Proved developed	Proved developed							Proved developed
Wattenberg Field	Wattenberg Field	77	946	106	341	42	%	Wattenberg Field	102	1,209	154	457	41	%
Delaware Basin	Delaware Basin	20	143	14	58	7	%	Delaware Basin	22	146	15	61	6	%
Total proved developed	Total proved developed	97	1,089	120	399	49	%	Total proved developed	124	1,355	169	518	47	%
Proved undeveloped	Proved undeveloped							Proved undeveloped
Wattenberg Field	Wattenberg Field	110	1,026	116	397	49	%	Wattenberg Field	135	1,458	171	549	50	%
Delaware Basin	Delaware Basin	7	45	4	18	2	%	Delaware Basin	11	80	8	33	3	%

Total proved undeveloped	Total proved undeveloped	117	1,071	120	415	51	%	Total proved undeveloped	146	1,538	179	582	53	%
Total proved reserves	Total proved reserves							Total proved reserves
Wattenberg Field	Wattenberg Field	187	1,972	222	738	91	%	Wattenberg Field	237	2,667	325	1,006	91	%
Delaware Basin	Delaware Basin	27	188	18	76	9	%	Delaware Basin	33	226	23	94	9	%
Total proved reserves	Total proved reserves	214	2,160	240	814	100	%	Total proved reserves	270	2,893	348	1,100	100	%


		Average Benchmark Prices							Average Benchmark Prices
December 31,	December 31,	Crude Oil (per Bbl) (1)		Natural Gas (per MMBtu) (1)		NGLs (per Bbl) (2)		December 31,	Crude Oil (per Bbl) (1)		Natural Gas (per MMBtu) (1)		NGLs (per Bbl) (2)
2022								2022	$	93.67	$	6.36	$	93.67
2021	2021	$	66.56	$	3.60	$	66.56	2021	66.56		3.60		66.56
2020	2020	39.57		1.99		39.57		2020	39.57		1.99		39.57
2019		55.69		2.58		55.69


		Price Used to Estimate Reserves (1)							Price Used to Estimate Reserves (1)
December 31,	December 31,	Crude Oil (per Bbl)		Natural Gas (per MMBtu)		NGLs (per Bbl)		December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2022								2022	$	94.23	$	4.82	$	31.60
2021	2021	$	65.37	$	2.85	$	24.96	2021	65.37		2.85		24.96
2020	2020	37.52		1.26		10.55		2020	37.52		1.26		10.55
2019		52.63		1.50		12.21


		Pricing Scenario - NYMEX												Pricing Scenario - NYMEX
		Crude Oil (per Bbl)		Natural Gas (per MMBtu)		Proved Reserves (MMBoe)	% Change from December 31, 2021 Estimated Reserves		PV-10 (in Millions)		PV-10 % Change from December 31, 2021 Estimated Reserves			Crude Oil (per Bbl)		Natural Gas (per MMBtu)		Proved Reserves (MMBoe)	% Change from December 31, 2022 Estimated Reserves		PV-10 (in Millions)		PV-10 % Change from December 31, 2022 Estimated Reserves
2021 SEC Reserve Report (1)		$	66.56	$	3.60	814,188	—		$	9,708.8	—
2022 SEC Reserve Report (1)													2022 SEC Reserve Report (1)	$	93.67	$	6.36	1,099,766	—		$	19,053.0	—
Alternate Price Scenario 1	Alternate Price Scenario 1	$	60.00	$	3.60	809,928	(1)	%	$	8,651.6	(11)	%	Alternate Price Scenario 1	$	75.00	$	6.36	1,092,010	(1)	%	$	15,270.0	(20)	%
Alternate Price Scenario 2	Alternate Price Scenario 2	$	45.00	$	3.60	796,618	(2)	%	$	6,239.7	(36)	%	Alternate Price Scenario 2	$	50.00	$	6.36	1,075,461	(2)	%	$	10,185.0	(47)	%


		Crude Oil		Natural Gas		Total			Crude Oil		Natural Gas		Total
Operating Region/Area	Operating Region/Area	Gross	Net	Gross	Net	Gross	Net	Operating Region/Area	Gross	Net	Gross	Net	Gross	Net
Wattenberg Field	Wattenberg Field	2,205	1,586.5	1,129	977.0	3,334	2,563.5	Wattenberg Field	3,013	2,224	930	801	3,943	3,025
Delaware Basin	Delaware Basin	52	37.9	85	73.4	137	111.3	Delaware Basin	53	37	102	90	155	127
Total productive wells	Total productive wells	2,257	1,624.4	1,214	1,050.4	3,471	2,674.8	Total productive wells	3,066	2,261	1,032	891	4,098	3,152


		Developed		Undeveloped		Total			Developed		Undeveloped		Total
Operating Region/Area	Operating Region/Area	Gross	Net	Gross	Net	Gross	Net	Operating Region/Area	Gross	Net	Gross	Net	Gross	Net
Wattenberg Field	Wattenberg Field	166,131	154,726	68,200	63,488	234,331	218,214	Wattenberg Field	222,037	201,827	80,950	72,741	302,987	274,568
Delaware Basin	Delaware Basin	27,627	25,316	905	343	28,532	25,659	Delaware Basin	27,636	24,703	959	906	28,595	25,609
Total acreage	Total acreage	193,758	180,042	69,105	63,831	262,863	243,873	Total acreage	249,673	226,530	81,909	73,647	331,582	300,177


		Operated Development and Exploratory Well Drilling Activity							Operated Development and Exploratory Well Drilling Activity
		As of and For the Year Ended December 31,							As of and For the Year Ended December 31,
		2021		2020		2019			2022		2021		2020
Operating Region/Area	Operating Region/Area	Gross	Net	Gross	Net	Gross	Net	Operating Region/Area	Gross	Net	Gross	Net	Gross	Net
Development Wells	Development Wells							Development Wells
Wattenberg Field	Wattenberg Field	149	143.0	124	116.5	114	105.1	Wattenberg Field	164	150	149	143	124	117
Delaware Basin	Delaware Basin	16	15.5	13	13.0	21	20.1	Delaware Basin	19	19	16	16	13	13
Total development wells	Total development wells	165	158.5	137	129.5	135	125.2	Total development wells	183	169	165	159	137	130

In-Process Development Wells	In-Process Development Wells							In-Process Development Wells
Wattenberg Field	Wattenberg Field	143	133.0	214	201.8	145	135.0	Wattenberg Field	200	185	143	133	214	202
Delaware Basin	Delaware Basin	21	20.6	18	17.2	26	25.3	Delaware Basin	12	12	21	21	18	17
Total in-process wells	Total in-process wells	164	153.6	232	219.0	171	160.3	Total in-process wells	212	197	164	154	232	219

Exploratory Wells - Productive
Developmental Wells - Dry Hole								Developmental Wells - Dry Hole
Wattenberg Field								Wattenberg Field	1	1	—	—	—	—
Delaware Basin	Delaware Basin	2	1.9	2	2.0	2	2.0	Delaware Basin	2	2	—	—	—	—
Total developmental wells - dry hole								Total developmental wells - dry hole	3	3	—	—	—	—

In-Process Exploratory Wells
Delaware Basin		—	—	2	1.9	4	3.9
Exploratory Wells - Delaware Basin								Exploratory Wells - Delaware Basin
Productive								Productive	—	—	2	2	2	2
Dry Hole								Dry Hole	1	1	—	—	—	—
In-Process								In-Process	—	—	—	—	2	2


		Year Ended December 31,							Year Ended December 31,
		2016	2017	2018	2019	2020	2021		2017	2018	2019	2020	2021	2022
PDC Energy	PDC Energy	100.00	71.01	41.00	36.06	28.29	69.20	PDC Energy	100.00	57.74	50.78	39.83	96.43	129.22
S&P 500	S&P 500	100.00	121.83	116.49	153.17	181.35	233.41	S&P 500	100.00	95.62	125.72	148.85	191.58	156.89
Peer Group		100.00	97.71	72.90	66.54	40.68	81.79
XOP								XOP	100.00	80.50	90.17	58.24	108.95	172.69


		Operated Wells							Operated Wells
		Wattenberg Field		Delaware Basin		Total			Wattenberg Field		Delaware Basin		Total
		Gross	Net	Gross	Net	Gross	Net		Gross	Net	Gross	Net	Gross	Net
In-process as of December 31, 2020		214	201.8	20	19.0	234	220.8
In-process as of December 31, 2021								In-process as of December 31, 2021	143	133	21	21	164	154
Wells spud	Wells spud	78	74.2	19	19.0	97	93.2	Wells spud	174	161	13	13	187	174
Wells acquired in-process (1)								Wells acquired in-process (1)	48	41	—	—	48	41
Wells turned-in-line	Wells turned-in-line	(149)	(143.0)	(18)	(17.4)	(167)	(160.4)	Wells turned-in-line	(164)	(150)	(19)	(19)	(183)	(169)
In-process as of December 31, 2021		143	133.0	21	20.6	164	153.6
Developmental and exploratory dry hole								Developmental and exploratory dry hole	(1)	(1)	(3)	(3)	(4)	(4)
In-process as of December 31, 2022								In-process as of December 31, 2022	200	185	12	12	212	197

Plugged and abandoned - Vertical Wells	Plugged and abandoned - Vertical Wells	404	392.0	—	—	404	392.0	Plugged and abandoned - Vertical Wells	253	244	—	—	253	244


	Year Ended December 31, ~~2021~~2022
	(in millions)
Change in:
Production	$	~~(3.5)~~58.0
Increase in production from acquisitions	464.8
Average crude oil price	~~749.7~~723.2
Average natural gas price	~~329.9~~395.0
Average NGLs price	~~323.9~~103.1
Total change in crude oil, natural gas and NGLs sales revenue	$	~~1,400.0~~1,744.1


2020		Average NYMEX Price		Average Realized Price Before TGP Expense		Average Realization Percentage Before TGP Expense		Average TGP Expense(1)		Average Realized Price After TGP Expense		Average Realization Percentage After TGP Expense
2021														2021	Average NYMEX Price		Average Realized Price Before TGP Expense		Average Realization Percentage Before TGP Expense		Average TGP Expense(1)		Average Realized Price After TGP Expense		Average Realization Percentage After TGP Expense
Crude oil (per Bbl)	Crude oil (per Bbl)	$	39.40	$	34.44	87	%	$	2.34	$	32.10	81	%	Crude oil (per Bbl)	$	67.92	$	67.49	99	%	$	3.10	$	64.39	95	%
Natural gas (per MMBtu)	Natural gas (per MMBtu)	2.08		1.08		52	%	0.12		0.96		46	%	Natural gas (per MMBtu)	3.76		2.96		79	%	0.13		2.83		75	%
NGLs (per Bbl)	NGLs (per Bbl)	39.40		9.21		23	%	—		9.21		23	%	NGLs (per Bbl)	67.92		25.94		38	%	—		25.94		38	%
Crude oil equivalent (per Boe)	Crude oil equivalent (per Boe)	28.52		16.86		59	%	1.10		15.76		55	%	Crude oil equivalent (per Boe)	49.29		35.78		73	%	1.30		34.48		70	%


2019		Average NYMEX Price		Average Realized Price Before TGP Expense		Average Realization Percentage Before TGP Expense		Average TGP Expense(1)		Average Realized Price After TGP Expense		Average Realization Percentage After TGP Expense
2020														2020	Average NYMEX Price		Average Realized Price Before TGP Expense		Average Realization Percentage Before TGP Expense		Average TGP Expense(1)		Average Realized Price After TGP Expense		Average Realization Percentage After TGP Expense
Crude oil (per Bbl)	Crude oil (per Bbl)	$	57.03	$	53.26	93	%	$	1.24	$	52.02	91	%	Crude oil (per Bbl)	$	39.40	$	34.44	87	%	$	2.34	$	32.10	81	%
Natural gas (per MMBtu)	Natural gas (per MMBtu)	2.63		1.30		49	%	0.17		1.13		43	%	Natural gas (per MMBtu)	2.08		1.08		52	%	0.12		0.96		46	%
NGLs (per Bbl)	NGLs (per Bbl)	57.03		12.41		22	%	0.10		12.31		22	%	NGLs (per Bbl)	39.40		9.21		23	%	—		9.21		23	%
Crude oil equivalent (per Boe)	Crude oil equivalent (per Boe)	40.95		26.46		65	%	0.90		25.56		62	%	Crude oil equivalent (per Boe)	28.52		16.86		59	%	1.10		15.76		55	%


		As of/Year Ended December 31,									As of/Year Ended December 31,
		2021				2020					2022				2021
		Issuer		Guarantor		Issuer		Guarantor			Issuer		Guarantors		Issuer		Guarantor
		(in millions)									(in millions)
Assets	Assets									Assets
Current assets	Current assets	$	402.6	$	56.0	$	271.4	$	(57.8)	Current assets	$	539.1	$	54.7	$	402.6	$	56.0
Intercompany accounts receivable, guarantor subsidiary	Intercompany accounts receivable, guarantor subsidiary	—		40.8		107.3		—		Intercompany accounts receivable, guarantor subsidiary	—		334.2		—		40.8
Investment in guarantor subsidiary	Investment in guarantor subsidiary	1,767.2		—		1,767.2		—		Investment in guarantor subsidiary	1,766.8		—		1,767.2		—
Properties and equipment, net	Properties and equipment, net	3,875.0		939.9		3,982.1		877.1		Properties and equipment, net	6,286.4		1,007.0		3,875.0		939.9
Other non-current assets	Other non-current assets	58.5		4.8		56.6		4.3		Other non-current assets	88.0		7.7		58.5		4.8

Liabilities	Liabilities									Liabilities
Current liabilities	Current liabilities	$	862.5	$	57.6	$	751.3	$	28.5	Current liabilities	$	1,361.5	$	58.7	$	862.5	$	57.6
Intercompany accounts payable	Intercompany accounts payable	27.9		—		—		94.2		Intercompany accounts payable	334.2		—		27.9		—
Long-term debt	Long-term debt	942.1		—		1,409.5		—		Long-term debt	1,314.0		—		942.1		—
Other non-current liabilities	Other non-current liabilities	392.3		172.0		254.9		178.1		Other non-current liabilities	1,101.7		164.1		392.3		172.0

Statement of Operations	Statement of Operations									Statement of Operations
Crude oil, natural gas and NGLs sales	Crude oil, natural gas and NGLs sales	$	2,163.1	$	389.5	$	968.8	$	183.7	Crude oil, natural gas and NGLs sales	$	3,639.3	$	657.4	$	2,163.1	$	389.5
Commodity price risk management gain (loss), net	Commodity price risk management gain (loss), net	(701.5)		—		180.3		—		Commodity price risk management gain (loss), net	(463.6)		—		(701.5)		—
Total revenues	Total revenues	1,464.5		391.4		1,151.5		182.5		Total revenues	3,179.7		666.0		1,464.5		391.4
Production costs	Production costs	892.4		189.0		740.7		177.5		Production costs	1,167.4		281.6		892.4		189.0
Gross profit (1)	Gross profit (1)	1,270.7		200.4		228.1		6.2		Gross profit (1)	2,471.9		375.8		1,270.7		200.4
Impairment of properties and equipment	Impairment of properties and equipment	0.4		—		2.0		880.4		Impairment of properties and equipment	0.8		5.9		0.4		—
Net income (loss)	Net income (loss)	327.7		194.9		(49.2)		(670.0)		Net income (loss)	1,419.5		358.6		327.7		194.9


		Year Ended December 31,							Year Ended December 31,
		2021		2020		2019			2022		2021		2020
Revenues	Revenues							Revenues
Crude oil, natural gas and NGLs sales	Crude oil, natural gas and NGLs sales	$	2,552,558	$	1,152,555	$	1,307,275	Crude oil, natural gas and NGLs sales	$	4,296,681	$	2,552,558	$	1,152,555
Commodity price risk management gain (loss), net	Commodity price risk management gain (loss), net	(701,456)		180,270		(162,844)		Commodity price risk management gain (loss), net	(463,611)		(701,456)		180,270
Other income	Other income	4,808		6,401		11,692		Other income	12,663		4,808		6,401
Total revenues	Total revenues	1,855,910		1,339,226		1,156,123		Total revenues	3,845,733		1,855,910		1,339,226
Costs, expenses and other	Costs, expenses and other							Costs, expenses and other
Lease operating expense	Lease operating expense	180,659		161,346		142,248		Lease operating expense	262,986		180,659		161,346
Production taxes	Production taxes	165,209		59,368		80,754		Production taxes	311,778		165,209		59,368
Transportation, gathering and processing expense	Transportation, gathering and processing expense	100,403		77,835		46,353		Transportation, gathering and processing expense	124,577		100,403		77,835
Exploration, geologic and geophysical expense	Exploration, geologic and geophysical expense	1,064		1,376		4,054		Exploration, geologic and geophysical expense	13,079		1,064		1,376
General and administrative expense	General and administrative expense	127,733		161,087		161,753		General and administrative expense	156,276		127,733		161,087
Depreciation, depletion and amortization	Depreciation, depletion and amortization	635,184		619,739		644,152		Depreciation, depletion and amortization	749,657		635,184		619,739
Accretion of asset retirement obligations	Accretion of asset retirement obligations	12,086		10,072		6,117		Accretion of asset retirement obligations	13,408		12,086		10,072
Impairment of properties and equipment	Impairment of properties and equipment	402		882,393		38,536		Impairment of properties and equipment	6,762		402		882,393
Loss (gain) on sale of properties and equipment	Loss (gain) on sale of properties and equipment	(912)		(724)		9,734		Loss (gain) on sale of properties and equipment	212		(912)		(724)

Other expense	Other expense	2,490		10,272		11,317		Other expense	—		2,490		10,272
Total costs, expenses and other	Total costs, expenses and other	1,224,318		1,982,764		1,145,018		Total costs, expenses and other	1,638,735		1,224,318		1,982,764
Income (loss) from operations	Income (loss) from operations	631,592		(643,538)		11,105		Income (loss) from operations	2,206,998		631,592		(643,538)

Interest expense, net	Interest expense, net	(82,698)		(88,684)		(71,099)		Interest expense, net	(64,734)		(82,698)		(88,684)
Gain on bargain purchase								Gain on bargain purchase	90,057		—		—
Income (loss) before income taxes	Income (loss) before income taxes	548,894		(732,222)		(59,994)		Income (loss) before income taxes	2,232,321		548,894		(732,222)
Income tax benefit (expense)	Income tax benefit (expense)	(26,583)		7,902		3,322		Income tax benefit (expense)	(454,200)		(26,583)		7,902
Net income (loss)	Net income (loss)	$	522,311	$	(724,320)	$	(56,672)	Net income (loss)	$	1,778,121	$	522,311	$	(724,320)

Earnings (loss) per share	Earnings (loss) per share							Earnings (loss) per share
Basic	Basic	$	5.30	$	(7.37)	$	(0.89)	Basic	$	18.76	$	5.30	$	(7.37)
Diluted	Diluted	5.22		(7.37)		(0.89)		Diluted	18.49		5.22		(7.37)

Weighted-average common shares outstanding
Weighted average common shares outstanding								Weighted average common shares outstanding
Basic	Basic	98,546		98,251		64,032		Basic	94,796		98,546		98,251
Diluted	Diluted	100,154		98,251		64,032		Diluted	96,174		100,154		98,251


	Year Ended December 31,
Production Ratio by Operating Region	2021		2020		2019
Wattenberg Field
Crude oil	31	%	34	%	38	%
Natural gas	41	%	41	%	40	%
NGLs	28	%	25	%	22	%
Total	100	%	100	%	100	%
Delaware Basin
Crude oil	40	%	38	%	41	%
Natural gas	38	%	38	%	35	%
NGLs	22	%	24	%	24	%
Total	100	%	100	%	100	%


		Year Ended December 31,
Weighted Average Realized Sales Price by Operating Region	Weighted Average Realized Sales Price by Operating Region							Percent Change				Weighted Average Realized Sales Price by Operating Region	Year Ended December 31,						Percent Change
(excluding net settlements on derivatives)	(excluding net settlements on derivatives)	2021		2020		2019		2021-2020		2020-2019		(excluding net settlements on derivatives)	2022		2021		2020		2022-2021		2021-2020
Crude oil (per Bbl)	Crude oil (per Bbl)											Crude oil (per Bbl)
Wattenberg Field	Wattenberg Field	$	67.49	$	34.21	$	52.99	97	%	(35)	%	Wattenberg Field	$	93.34	$	67.49	$	34.21	38	%	97	%
Delaware Basin	Delaware Basin	67.47		35.48		54.08		90	%	(34)	%	Delaware Basin	96.22		67.47		35.48		43	%	90	%
Weighted average price	Weighted average price	67.49		34.44		53.26		96	%	(35)	%	Weighted average price	93.80		67.49		34.44		39	%	96	%
Natural gas (per Mcf)	Natural gas (per Mcf)											Natural gas (per Mcf)
Wattenberg Field	Wattenberg Field	2.98		1.22		1.49		144	%	(18)	%	Wattenberg Field	4.97		2.98		1.22		67	%	144	%
Delaware Basin	Delaware Basin	2.81		0.28		0.57		*		(51)	%	Delaware Basin	4.68		2.81		0.28		67	%	*
Weighted average price	Weighted average price	2.96		1.08		1.30		174	%	(17)	%	Weighted average price	4.94		2.96		1.08		67	%	174	%
NGLs (per Bbl)	NGLs (per Bbl)											NGLs (per Bbl)
Wattenberg Field	Wattenberg Field	24.77		8.84		11.51		180	%	(23)	%	Wattenberg Field	28.24		24.77		8.84		14	%	180	%
Delaware Basin	Delaware Basin	35.72		11.32		15.12		216	%	(25)	%	Delaware Basin	46.46		35.72		11.32		30	%	216	%
Weighted average price	Weighted average price	25.94		9.21		12.41		182	%	(26)	%	Weighted average price	30.17		25.94		9.21		16	%	182	%
Crude oil equivalent (per Boe)	Crude oil equivalent (per Boe)											Crude oil equivalent (per Boe)
Wattenberg Field	Wattenberg Field	34.95		16.84		26.31		108	%	(36)	%	Wattenberg Field	49.18		34.95		16.84		41	%	108	%
Delaware Basin	Delaware Basin	41.25		16.94		26.95		144	%	(37)	%	Delaware Basin	59.58		41.25		16.94		44	%	144	%
Weighted average price	Weighted average price	35.78		16.86		26.46		112	%	(36)	%	Weighted average price	50.53		35.78		16.86		41	%	112	%


	Year Ended December 31,
	~~2021~~2022
	(in millions)
Increase in production	$	~~24.8~~120.3
Decrease in weighted average ~~depreciation,~~ depletion ~~and amortization rates~~rate	~~(8.3)~~(5.9)
Total decrease in DD&A expense related to crude oil and natural gas properties	$	~~16.5~~114.4


Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information

Financial Statements:
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)						6661
Consolidated Balance Sheets						6864
Consolidated Statements of Operations						6965
Consolidated Statements of Cash Flows						7066
Consolidated Statements of ~~Stockholders~~’Stockholders’ Equity						7167
Notes to Consolidated Financial Statements						7268

Supplemental Information - Unaudited:
Crude Oil and Natural Gas Information						~~100~~93

Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 2022, 2021 ~~2020~~ and ~~2019~~2020						~~107~~100


		Common Stock			Additional Paid-in Capital				Treasury Stock						Retained Earnings (Accumulated Deficit)				Total Stockholders’ Equity					Common Stock					Additional Paid-in Capital			Treasury Stock					Retained Earnings (Accumulated Deficit)			Total Stockholders’ Equity
		Shares	Amount				Shares			Amount											Shares				Amount			Shares				Amount
Balance at January 1, 2019		66,149	$	661			$	2,519,423		(45)			$	(2,103)			$	8,727				$	2,526,708
Net income (loss)		—	—		—				—		—				(56,672)				(56,672)
Stock-based compensation		213	2		23,835				—		—				—				23,837
Purchase of treasury shares for employee stock-based compensation tax withholding obligations		—	—		—				(106)		(4,003)				—				(4,003)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations		(4)	—		(127)				4		127				—				—
Retirement of treasury shares		(4,706)	(46)		(154,317)				4,706		154,363				—				—

Issuance of treasury shares		—	—		(4,505)				112		4,505				—				—

Purchase of treasury shares under stock repurchase program		—	—		—				(4,706)		(154,363)				—				(154,363)
Balance at December 31, 2019		61,652	617		2,384,309				(35)		(1,474)				(47,945)				2,335,507
Balance at January 1, 2020																					Balance at January 1, 2020			61,652		$	617			$	2,384,309		(35)		$	(1,474)		$	(47,945)		$	2,335,507
Net income (loss)	Net income (loss)	—	—		—				—		—				(724,320)				(724,320)		Net income (loss)			—		—			—			—		—			(724,320)			(724,320)
Issuance pursuant to acquisition	Issuance pursuant to acquisition	39,182	391		1,014,921				—		—				—				1,015,312		Issuance pursuant to acquisition			39,182		391			1,014,921			—		—			—			1,015,312
Stock-based compensation	Stock-based compensation	530	5		19,738				—		2,457				—				22,200		Stock-based compensation			530		5			19,738			—		2,457			—			22,200
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—				(457)		(9,345)				—				(9,345)		Purchase of treasury shares for employee stock-based compensation tax withholding obligations			—		—			—			(457)		(9,345)			—			(9,345)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(339)	(3)		(7,407)				339		7,413				—				3		Retirement of treasury shares for employee stock-based compensation tax withholding obligations			(339)		(3)			(7,407)			339		7,413			—			3
Retirement of treasury shares	Retirement of treasury shares	(1,266)	(12)		(23,807)				1,266		23,819				—				—		Retirement of treasury shares			(1,266)		(12)			(23,807)			1,266		23,819			—			—

Issuance of treasury shares	Issuance of treasury shares	—	—		—				115		—				—				—		Issuance of treasury shares			—		—			—			115		—			—			—

Purchase of treasury shares under stock repurchase program	Purchase of treasury shares under stock repurchase program	—	—		—				(1,266)		(23,819)				—				(23,819)		Purchase of treasury shares under stock repurchase program			—		—			—			(1,266)		(23,819)			—			(23,819)
Balance at December 31, 2020	Balance at December 31, 2020	99,759	998		3,387,754				(38)		(949)				(772,265)				2,615,538		Balance at December 31, 2020			99,759		998			3,387,754			(38)		(949)			(772,265)			2,615,538
Net income (loss)	Net income (loss)	—	—		—				—		—				522,311				522,311		Net income (loss)			—		—			—			—		—			522,311			522,311
Stock-based compensation	Stock-based compensation	531	5		20,831				—		2,187				—				23,023		Stock-based compensation			531		5			20,831			—		2,187			—			23,023
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—				(181)		(6,038)				—				(6,038)		Purchase of treasury shares for employee stock-based compensation tax withholding obligations			—		—			—			(181)		(6,038)			—			(6,038)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(117)	(1)		(4,156)				117		4,157				—				—		Retirement of treasury shares for employee stock-based compensation tax withholding obligations			(117)		(1)			(4,156)			117		4,157			—			—
Retirement of treasury shares	Retirement of treasury shares	(3,705)	(37)		(157,058)				3,711		157,401				—				306		Retirement of treasury shares			(3,705)		(37)			(157,058)			3,711		157,401			—			306
Issuance of treasury shares	Issuance of treasury shares	—	—		—				89		—				—				—		Issuance of treasury shares			—		—			—			89		—			—			—
Purchase of treasury shares under stock repurchase program	Purchase of treasury shares under stock repurchase program	—	—		—				(3,753)		(159,463)				—				(159,463)		Purchase of treasury shares under stock repurchase program			—		—			—			(3,753)		(159,463)			—			(159,463)
Dividends declared ($0.86 per share)	Dividends declared ($0.86 per share)	—	—		(85,430)				—		—				—				(85,430)		Dividends declared ($0.86 per share)			—		—			(85,430)			—		—			—			(85,430)
Balance at December 31, 2021	Balance at December 31, 2021	96,468	$	965	$	3,161,941			(55)		$	(2,705)			$	(249,954)			$	2,910,247	Balance at December 31, 2021			96,468		965			3,161,941			(55)		(2,705)			(249,954)			2,910,247
Net income (loss)																					Net income (loss)			—		—			—			—		—			1,778,121			1,778,121
Issuance pursuant to acquisition																					Issuance pursuant to acquisition			4,007		40			293,274			—		—			—			293,314
Stock-based compensation																					Stock-based compensation			1,038		10			22,673			—		4,163			—			26,846
Purchase of treasury shares for employee stock-based compensation tax withholding obligations																					Purchase of treasury shares for employee stock-based compensation tax withholding obligations			—		—			—			(283)		(18,105)			—			(18,105)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations																					Retirement of treasury shares for employee stock-based compensation tax withholding obligations			(170)		(2)			(11,199)			170		11,684			(483)			—
Retirement of treasury shares																					Retirement of treasury shares			(12,119)		(121)			(584,199)			12,119		820,993			(236,673)			—
Issuance of treasury shares																					Issuance of treasury shares			—		—			—			75		—			—			—
Purchase of treasury shares under stock repurchase program																					Purchase of treasury shares under stock repurchase program			—		—			—			(12,145)		(823,357)			—			(823,357)
Dividends declared ($1.95 per share)																					Dividends declared ($1.95 per share)			—		—			(59,126)			—		—			(125,195)			(184,321)
Balance at December 31, 2022																					Balance at December 31, 2022			89,224		$	892		$	2,823,364		(119)		$	(7,327)		$	1,165,816		$	3,982,745


	(in ~~thousands)~~thousands, except share and per share data)
Consideration:
Cash	$	40542,500
Retirement of ~~seller’s~~Great Western’s credit facility	~~166,238~~235,822
Extinguishment of Great Western’s secured senior notes	361,231
Total cash consideration	~~166,278~~ $	1,139,553

Common stock issued	~~1,009,015~~4,007,018
~~Shares withheld in lieu~~Fair value of ~~taxes~~PDC common stock on May 6, 2022	~~6,299~~$	73.20
Total fair value of common stock issued	293,314

Total consideration	$	~~1,181,592~~1,432,867

~~Recognized amounts of identifiable assets acquired and liabilities assumed:~~
Assets acquired:
~~Current assets~~Cash	$	~~145,792~~63,183
Accounts receivable	164,026
Other current assets	3,129
Properties and equipment, net - proved	~~1,613,674~~
~~Properties and equipment, net - unproved~~	~~109,615~~2,091,301
Properties and equipment, net - other	~~16,242~~
~~Deferred tax asset~~	~~189,311~~7,035
Other noncurrent assets	~~11,810~~20,345
Total assets acquired	$	~~2,086,444~~2,349,019

Liabilities assumed:
~~Current liabilities~~Accounts payable	$	~~(253,967)~~(119,142)
~~Senior notes~~Production tax liability	~~(555,500)~~(110,940)
Funds held for distribution	(170,708)
Other current liabilities	(19,203)
Fair value of derivatives	(319,600)
Asset retirement obligations	~~(42,417)~~(25,300)
Deferred tax liabilities	(28,400)
Other liabilities	~~(52,968)~~(32,802)
Total liabilities assumed	~~(904,852)~~$	(826,095)

Total identifiable net assets acquired	$	~~1,181,592~~1,522,924
Gain on bargain purchase	90,057
Purchase price consideration	$	1,432,867


	Year Ended December 31,

Revenue by Commodity and Operating Region	2021		2020		2019
	(in thousands)
Crude oil
Wattenberg Field	$	1,275,666	$	668,948	$	767,760
Delaware Basin	255,135		147,902		252,929
Total	1,530,801		816,850		1,020,689
Natural gas
Wattenberg Field	458,870		171,755		137,143
Delaware Basin	60,733		6,997		13,877
Total	519,603		178,752		151,020
NGLs
Wattenberg Field	428,570		128,126		94,347
Delaware Basin	73,584		28,827		41,219
Total	502,154		156,953		135,566
Crude oil, natural gas and NGLs
Wattenberg Field	2,163,106		968,829		999,250
Delaware Basin	389,452		183,726		308,025
Total	$	2,552,558	$	1,152,555	$	1,307,275


		December 31, 2021						December 31, 2020
	Consolidated Balance Sheet Line Item	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
		(in thousands)
Derivative assets
Current	Fair value of derivatives	$	—	$	17,909	$	17,909	$	36,580	$	12,289	$	48,869
Non-current	Fair value of derivatives	605		14,572		15,177		315		9,250		9,565
Total		$	605	$	32,481	$	33,086	$	36,895	$	21,539	$	58,434

Derivative liabilities
Current	Fair value of derivatives	$	(230,695)	$	(74,175)	$	(304,870)	$	(76,420)	$	(21,732)	$	(98,152)
Non-current	Fair value of derivatives	(74,715)		(20,846)		(95,561)		(28,125)		(8,234)		(36,359)
Total		$	(305,410)	$	(95,021)	$	(400,431)	$	(104,545)	$	(29,966)	$	(134,511)


		December 31, 2022						December 31, 2021
	Consolidated Balance Sheet Line Item	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
		(in thousands)
Derivative assets
Current	Fair value of derivatives	$	9,178	$	22,785	$	31,963	$	—	$	17,909	$	17,909
Non-current	Fair value of derivatives	20,439		5,123		25,562		605		14,572		15,177
Total		$	29,617	$	27,908	$	57,525	$	605	$	32,481	$	33,086

Derivative liabilities
Current	Fair value of derivatives	$	(214,171)	$	(60,047)	$	(274,218)	$	(230,695)	$	(74,175)	$	(304,870)
Non-current	Fair value of derivatives	(49,749)		(3,851)		(53,600)		(74,715)		(20,846)		(95,561)
Total		$	(263,920)	$	(63,898)	$	(327,818)	$	(305,410)	$	(95,021)	$	(400,431)


	Year Ended December 31,
Consolidated Statements of Operations Line Item	2021		2020		2019
	(in thousands)
Commodity price risk management gain (loss), net
Net settlements	$	(410,188)	$	279,271	$	(17,598)
Net change in fair value of unsettled derivatives	(291,268)		(99,001)		(145,246)
Total commodity price risk management gain (loss), net	$	(701,456)	$	180,270	$	(162,844)


	Collars					Fixed-Price Swaps
Commodity/ Index/ Maturity Period	Quantity (Crude oil - MBbls Natural Gas - BBtu)	Weighted Average Contract Price				Quantity (Crude Oil - MBbls Gas and Basis- BBtu)	Weighted Average Contract Price		Fair Value December 31, 2021 (in thousands)
		Floors		Ceilings
Crude Oil
NYMEX
2022	5,472	$	53.18	$	67.33	6,744	$	44.42	$	(235,146)
2023	2,775	55.00		70.00		5,502	56.83		(58,299)
2024	225	55.00		75.12		1,500	61.27		(2,276)
Total Crude Oil	8,472					13,746			(295,721)

Natural Gas
NYMEX
2022	35,460	3.14		4.78		33,600	2.70		(41,165)
2023	3,000	3.00		4.42		30,398	2.68		(19,171)




Total Natural Gas	38,460					63,998			(60,336)







Basis Protection - Natural Gas
CIG
2022	—	—		—		69,060	(0.25)		(10,650)
2023	—	—		—		29,438	(0.27)		(638)




Total Basis Protection - Natural Gas	—					98,498			(11,288)

Commodity Derivatives Fair Value									$	(367,345)


	Total Gross Amount Presented on the Balance Sheet		Effect of Master Netting Agreements		Total Net Amount
As of December 31, 2021	(in thousands)
Derivative asset instruments, at fair value	$	33,086	$	(33,086)	$	—
Derivative liability instruments, at fair value	$	400,431	$	(33,086)	$	367,345

As of December 31, 2020
Derivative asset instruments, at fair value	$	58,434	$	(39,691)	$	18,743
Derivative liability instruments, at fair value	$	134,511	$	(39,691)	$	94,820


		December 31,
Leases	Consolidated Balance Sheet Line Item	2022		2021
		(in thousands)
Operating lease ROU assets	Other assets	$	19,577	$	7,630
Finance lease ROU assets	Properties and equipment, net	6,184		3,483
Total ROU assets		$	25,761	$	11,113

Operating lease obligation - short-term	Other accrued expenses	$	3,825	$	5,937
Operating lease obligation - long-term	Other liabilities	37,720		4,044
Finance lease obligation - short-term	Other accrued expenses	2,162		1,260
Finance lease obligation - long-term	Other liabilities	4,095		2,230
Total lease liabilities		$	47,802	$	13,471


	Operating Leases		Finance Leases		Total
	(in thousands)
2022	$	6,214	$	1,378	$	7,592
2023	1,767		1,119		2,886
2024	950		612		1,562
2025	950		473		1,423
2026	747		148		895

Total lease payments	10,628		3,730		14,358
Less: Interest and discount	(647)		(240)		(887)
Present value of lease liabilities	$	9,981	$	3,490	$	13,471


	Year Ending December 31,
	2022		2023		2024		2025		2026		Thereafter		Total		Expiration Date for Thereafter
Natural gas (MMcf)	82,264		82,264		82,489		70,296		37,029		73,050		427,392		December 31, 2030
Crude oil (MBbls)	23,360		19,685		9,882		9,855		6,561		—		69,343
Water (MBbls)	6,207		6,207		6,224		—		—		—		18,638

Purchase obligation (Tons)	110,000		300,000		—		0		0		0		410,000

Dollar commitment (in thousands)	$	153,857	$	157,370	$	92,247	$	77,491	$	39,631	$	37,811	$	558,407


		Shares	Weighted Average Grant-Date Fair Value per Share			Shares	Weighted Average Grant-Date Fair Value per Share
Non-vested at beginning of period	Non-vested at beginning of period	1,150,970	$	20.14	Non-vested at beginning of period	1,165,187	$	25.33
Granted	Granted	657,972	33.64		Granted	363,395	70.01
Vested	Vested	(547,985)	24.86		Vested	(581,343)	26.15
Forfeited	Forfeited	(95,770)	22.74		Forfeited	(50,728)	40.58
Non-vested at end of period	Non-vested at end of period	1,165,187	25.33		Non-vested at end of period	896,511	42.05


	Shares	Weighted Average Grant-Date Fair Value per Share
Non-vested at December 31, 2021	439,229	$	43.21
Granted	102,098	107.85
Granted for performance multiple(1)	347,363	33.52
Vested	(578,937)	33.52
Non-vested at December 31, 2022	309,753	71.76


	Shares	Weighted Average Grant-Date Fair Value per Share
Non-vested at December 31, 2020	499,547	$	38.66
Granted	207,655	54.01
Vested	(267,973)	43.10

Non-vested at December 31, 2021	439,229	43.21


		Crude Oil, Condensate (MBbls)	Natural Gas (MMcf)	NGLs (MBbls)	Total (MBoe)		Crude Oil, Condensate (MBbls)	Natural Gas (MMcf)	NGLs (MBbls)	Total (MBoe)
Proved reserves, January 1, 2019		190,349	1,335,689	131,987	544,953
Revisions of previous estimates		25,875	328,290	31,559	112,147
Extensions, discoveries and other additions		1,056	10,262	1,519	4,285
Acquisition of reserves		553	4,558	448	1,761
Dispositions		(1,412)	(5,052)	(614)	(2,868)
Production		(19,166)	(115,950)	(10,923)	(49,414)
Proved reserves, December 31, 2019		197,255	1,557,797	153,976	610,864
Proved reserves, January 1, 2020						Proved reserves, January 1, 2020	197,255	1,557,797	153,976	610,864
Revisions of previous estimates	Revisions of previous estimates	(41,089)	(272,243)	(14,774)	(101,237)	Revisions of previous estimates	(41,089)	(272,243)	(14,774)	(101,237)
Extensions, discoveries and other additions	Extensions, discoveries and other additions	812	2,991	324	1,635	Extensions, discoveries and other additions	812	2,991	324	1,635
Acquisition of reserves	Acquisition of reserves	80,590	795,977	81,770	295,023	Acquisition of reserves	80,590	795,977	81,770	295,023
Dispositions	Dispositions	(2,116)	(17,711)	(1,776)	(6,844)	Dispositions	(2,116)	(17,711)	(1,776)	(6,844)
Production	Production	(23,720)	(165,637)	(17,042)	(68,368)	Production	(23,720)	(165,637)	(17,042)	(68,368)
Proved reserves, December 31, 2020	Proved reserves, December 31, 2020	211,732	1,901,174	202,478	731,073	Proved reserves, December 31, 2020	211,732	1,901,174	202,478	731,073
Revisions of previous estimates	Revisions of previous estimates	22,651	408,540	54,634	145,375	Revisions of previous estimates	22,651	408,540	54,634	145,375
Extensions, discoveries and other additions	Extensions, discoveries and other additions	528	1,584	168	960	Extensions, discoveries and other additions	528	1,584	168	960
Acquisition of reserves	Acquisition of reserves	1,616	24,174	2,469	8,113	Acquisition of reserves	1,616	24,174	2,469	8,113
Dispositions	Dispositions	—	—	—	—	Dispositions	—	—	—	—
Production	Production	(22,682)	(175,747)	(19,360)	(71,333)	Production	(22,682)	(175,747)	(19,360)	(71,333)
Proved reserves, December 31, 2021	Proved reserves, December 31, 2021	213,845	2,159,725	240,389	814,188	Proved reserves, December 31, 2021	213,845	2,159,725	240,389	814,188
Revisions of previous estimates						Revisions of previous estimates	15,607	506,220	74,317	174,294
Extensions, discoveries and other additions						Extensions, discoveries and other additions	—	—	—	—
Acquisition of reserves						Acquisition of reserves	68,064	425,870	57,344	196,387
Dispositions						Dispositions	(10)	(195)	(22)	(65)
Production						Production	(27,486)	(199,362)	(24,325)	(85,038)
Proved reserves, December 31, 2022						Proved reserves, December 31, 2022	270,020	2,892,258	347,703	1,099,766

Proved developed reserves, as of:	Proved developed reserves, as of:					Proved developed reserves, as of:
December 31, 2019		66,211	554,234	55,411	213,994
December 31, 2020	December 31, 2020	86,330	860,877	91,702	321,512	December 31, 2020	86,330	860,877	91,702	321,512
December 31, 2021	December 31, 2021	97,420	1,088,700	120,132	399,002	December 31, 2021	97,420	1,088,700	120,132	399,002
December 31, 2022						December 31, 2022	123,783	1,355,169	168,638	518,283
Proved undeveloped reserves, as of:	Proved undeveloped reserves, as of:					Proved undeveloped reserves, as of:
December 31, 2019		131,044	1,003,563	98,565	396,870
December 31, 2020	December 31, 2020	125,402	1,040,297	110,776	409,561	December 31, 2020	125,402	1,040,297	110,776	409,561
December 31, 2021	December 31, 2021	116,425	1,071,025	120,257	415,186	December 31, 2021	116,425	1,071,025	120,257	415,186
December 31, 2022						December 31, 2022	146,237	1,537,089	179,065	581,483


Description	Description	Beginning Balance January 1,		Charged to Costs and Expenses		Deductions (1)		Ending Balance December 31,		Description	Beginning Balance January 1,		Charged to Costs and Expenses		Deductions (1)		Ending Balance December 31,
		(in thousands)									(in thousands)
2022:										2022:

Allowance for doubtful accounts										Allowance for doubtful accounts	$	6,055	$	(446)	$	(164)	$	5,445
Allowance for expirations of unproved crude oil and natural gas properties										Allowance for expirations of unproved crude oil and natural gas properties	206,328		864		(127,185)		80,007
2021:	2021:									2021:

Allowance for doubtful accounts	Allowance for doubtful accounts	$	6,763	$	(359)	$	(349)	$	6,055	Allowance for doubtful accounts	$	6,763	$	(359)	$	(349)	$	6,055
Allowance for expirations of unproved crude oil and natural gas properties	Allowance for expirations of unproved crude oil and natural gas properties	224,019		—		(17,691)		206,328		Allowance for expirations of unproved crude oil and natural gas properties	224,019		—		(17,691)		206,328
2020:	2020:									2020:

Allowance for doubtful accounts	Allowance for doubtful accounts	$	7,476	$	3,179	$	(3,892)	$	6,763	Allowance for doubtful accounts	$	7,476	$	3,179	$	(3,892)	$	6,763
Allowance for expirations of unproved crude oil and natural gas properties	Allowance for expirations of unproved crude oil and natural gas properties	6,881		223,895		(6,757)		224,019		Allowance for expirations of unproved crude oil and natural gas properties	6,881		223,895		(6,757)		224,019
2019:

Allowance for doubtful accounts		$	4,381	$	3,209	$	(114)	$	7,476
Allowance for expirations of unproved crude oil and natural gas properties		542,709		8,523		(544,351)		6,881