Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is -0.21pp more bearish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-0.60pp
Lean -
Net-tone change vs last year's 10-K.
MD&A
+0.19pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
against+2
scrutiny+2
terminated+2
failures+2
litigation+2
Positive rising
satisfy+2
efficiency+2
satisfactory+1
enhance+1
strength+1
Risk Factors (Item 1A)
10,577 words
ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as the value of an investment in our common stock or other securities.
Adverse changes in general economic conditions could have a material adverse effect on our business, results of operations and financial condition.
Current or future economic uncertainties or downturns, including those caused by the COVID-19 pandemic, could adversely affect our business and operating results. Adverse macroeconomic conditions may result from, among other things, changes in gross domestic product growth, financial and credit market fluctuations, rising inflation, recessions, political deadlocks, natural catastrophes, pandemics, military conflicts (such as the Russian invasion of Ukraine) or terrorist attacks, whether in the United States, Europe, the Asia Pacific region or elsewhere, and may result in impacts on our business, including crude oil, natural gas and NGL pricing, reductions in , and reduced capital expenditures.
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
termination+4
volatility+2
slowdown+2
recession+2
intermittent+2
Positive rising
great+21
gain+7
effective+1
highest+1
progress+1
MD&A (Item 7)
12,448 words
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data and also with Item 1A. Risk Factors of this report. A discussion of changes in our results of operations and liquidity from 2020 to 2021 has been omitted from this report but can be found in Item 7. Management’s Discussion and Analysis , of our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 28, 2022. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements in Part I of this report.
EXECUTIVE SUMMARY
2022 Financial Overview of Operations and Liquidity
Market Conditions
The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. Commodity prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment. During 2022, crude oil and natural gas prices experienced high levels of volatility. NYMEX WTI spot prices for crude oil reached a high of $130.50 per barrel in March and a low of $70.08 per barrel in December and NYMEX Henry Hub spot prices for natural gas reached a high of $9.85 per MMBtu in August and a low of $3.46 per MMBtu in November. By the end of 2022, crude oil and natural prices had significantly from the levels seen earlier in the year.
For example, during 2021 and 2022, the United States experienced inflation rates of approximately 7% and 6.5%, respectfully, according to data from the U.S. Bureau of Labor Statistics, which were significant increases relative to prior years. If inflation rates remain elevated or increase further, our expenses and operating costs are likely to increase as well. Inflation may also result in higher interest rates and otherwise adversely impact the macroeconomic environment, which in turn could adversely impact commodity pricing. Additionally, in recent periods the U.S. has experienced a labor shortage, which has contributed to an environment of escalating wages and salaries, which may also adversely affect our operating costs and contribute to general inflationary pressures.
We cannot predict the timing, strength or duration of any economic slowdown, instability or recovery, generally or within any particular industry. If economic conditions in the general economy or industries in which we operate do not improve, or worsen from present levels, our business, operating results, financial condition and cash flows could be adversely affected.
Risks Relating to Our Business and the Industry
Crude oil, natural gas and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and may impede our growth.
Many aspects of our business depend upon crude oil, natural gas and NGL prices, including:
• our revenue, profitability and cash flows;
• our liquidity;
• the quantity and present value of our reserves;
• the borrowing base under our revolving credit facility and access to other sources of capital; and
• the nature and scale of our operations.
The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to, among other things:
• changes in regional, national or global economic conditions and trends, including supply and demand;
• geopolitical factors and events that reduce or increase production from oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries (“OPEC”), and global events, such as the ongoing COVID-19 pandemic, and Russia’s invasion of Ukraine; and
• regulatory changes.
The price of oil has historically been volatile due to a variety of factors including global supply and economic conditions. In the past two years, oil prices have ranged from highs over $130 per barrel to lows of approximately $45 per barrel. Prices for natural gas and NGLs have also experienced substantial volatility. If we reduce our capital expenditures due to low prices, natural declines in production from our wells will result in reduced cash flow from operations. Reduced cash flow would limit our ability to make the capital expenditures necessary to replace our reserves and production.
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In addition to factors generally affecting the price of crude oil, natural gas and NGLs, the prices we receive for our production are affected by factors specific to us and to the local markets where production occurs. The prices we receive for our production vary from the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on markets and other forces, including local or regional supply and demand factors; terms of our sales contracts; investment decisions made by providers of midstream facilities and services, refineries and other industry participants; and the overall regulatory and economic climate. Widening differentials may materially and adversely impact our business.
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.
Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage and natural resource or other damages, and could be required to change, suspend or terminate operations. A summary of certain laws and regulations that apply to us and some potential changes to those laws and regulations is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation . Any of the currently applicable laws and regulations could be amended, including in ways that we do not anticipate, and those changes could adversely affect our operations.
From time to time, we have been subject to sanctions and lawsuits relating to allegednoncompliance with regulatory requirements. For example, in October 2017, in order to settle a lawsuit brought against us by the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, we entered into a consent decree (“CD”) pursuant to which we paid a fine and agreed to implement certain operational changes. In addition, as a result of the acquisition of SRC Energy, Inc. (“SRC”), and Great Western Petroleum, LLC (“GW”), we became subject to SRC’s 2018 Compliance Order on Consent (“SRC COC”) and GW’s 2018 Compliance Order on Consent (“GW COC”), each of which involved issues similar to those addressed in the CD. As of December 31, 2022, each of these matters have been resolved. The CD was terminated on December 15, 2022; the SRC COC was terminated on February 28, 2022; and the GW COC was terminated on November 7, 2022. We may, however, be subject to similar lawsuits and orders in the future.
The regulatory environment in which we operate also changes frequently, often through the imposition of new or more stringent environmental and other requirements, some of which may apply retroactively. We cannot predict the nature, timing, cost or effect of such additional requirements, but they may have a variety of adverse effects on us. The types of regulatory changes that could impact our operations vary widely and include, but are not limited to, the following:
• As discussed in Items 1 and 2, Business and Properties - Governmental Regulation , there is continued ambiguity around COGCC permitting rules as implementation continues. In 2023, we anticipate continued rulemakings and guidance from the COGCC Commissioners and staff. We expect to participate in the stakeholder process to create rules and guidance around high-priority habitat, workers safety and cumulative impacts. We cannot predict the ultimate impact of these requirements on our inventory and operations.
• Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other GHGs. Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program. In addition, like other energy companies, we could be named as a defendant in GHG-related lawsuits.
• The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage and use of surface water or groundwater or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition.
• Corporate governance, public disclosure and compliance practices continue to evolve based upon continuing legislative action, SEC rulemaking and policy positions taken by large institutional stockholders and proxy
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advisors. As a result, the number of rules, regulations and standards applicable to us may become more burdensome to comply with, could increase scrutiny of our practices and policies by these or other groups and increase our legal and financial compliance costs and the amount of time management must devote to governance and compliance activities. For example, the SEC has recently proposed rules requiring that issuers provide significantly increased disclosures concerning cybersecurity matters, insider trading policies and procedures and the impact of climate changes on their business.
Increasing scrutiny, changing expectations from stakeholders and proposed reporting requirements by regulatory bodies with respect to climate-related risk and ESG may impose additional costs on us or expose us to new or additional risks.
Publicly traded companies, both in the oil and natural gas industry and otherwise, are facing increased scrutiny from stakeholders regarding climate changes and ESG matters. Attention to these issues has come from stakeholders including the SEC, local governments and institutional investors, and these stakeholders have and may in the future seek certain outcomes or results on issues they perceive to be material. For example, the SEC has recently proposed rules to enhance and standardize climate-related disclosures for investors. This increased scrutiny could result in reduced access to capital, shareholder proposals and other adverse effects. Companies that fail to adapt or comply with evolving stakeholder expectations, or are perceived as failing to respond appropriately, could suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely impacted.
Many scientists have shown that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth’s atmosphere are changing global climate patterns. The following is a summary of potential climate-related risks that could adversely affect us:
Transition Risks. Transition risks are related to the transition to a lower-carbon economy and include the risk of reduced demand and lower prices for our production.
Policy and Legal Risks. Policy risks include those arising from the regulatory actions intended to discourage activities that contribute to the adverse effects of climate change or to promote adaptation to climate change. President Biden’s administration has made addressing climate change a high priority, and this could lead to a more challenging regulatory environment. Examples of policy actions from federal, state or local governments that could increase the costs of our operations, reduce our future development or production or reduce demand for our oil and gas include the implementation of carbon-pricing mechanisms, regulations designed to shift energy use toward lower emission sources, regulations regarding energy and water use efficiency, regulations disallowing development or production activity on high ozone level days, and regulations intended to promote sustainable land use. Policy actions also may include restrictions or bans on oil and gas activities, which could lead to write-downs or impairments of our assets.
Legal risks include potential lawsuits based on allegedfailures to mitigate impacts of climate change, failures to adapt to climate change and disclosure matters. For example, we may be subject to climate‐related litigation such as “greenwashing” suits with respect to our operations, disclosures, or products. Although we are not a party to any such climate-related or “greenwashing” litigation currently, unfavorable rulings against us in any such case brought against us in the future could significantly impact our operations and could have an adverse impact on our financial condition.
Technology Risks. Technological improvements or innovations that support the transition to a lower-carbon, more energy efficient economic system may have a significant impact on us. The development and use of emerging technologies in renewable energy, battery storage, and energy efficiency may reduce demand for oil and gas, resulting in lower prices and revenues, and higher costs. In addition, many automobile manufacturers have announced plans to shift production from internal combustion engine vehicles to electric powered vehicles, and some states and foreign countries have announced bans on sales of internal combustion engine vehicles beginning as early as 2025, which could reduce demand for oil.
Market Risks. Markets could be affected by climate change through shifts in supply and demand for certain commodities, especially carbon-intensive commodities such as oil and gas and other products dependent on oil and gas. Lower demand for our oil and gas production could result in lower prices and lower revenues. Market risk also may take the form of limited access to capital as investors shift investments to less carbon-intensive industries and alternative energy industries. In addition, certain investment advisers, banks, and sovereign wealth, pension, and endowment funds have in recent years been promoting divestment of investments in fossil fuel companies and pressuring lenders to limit funding to companies engaged in
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the extraction, production, and sale of oil and gas. We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, or at all.
Reputational Risk. Climate change is a potential source of reputational risk, which is tied to changing customer or community perceptions of an organization’s contribution to, or detraction from, the transition to a lower-carbon economy.
Physical Risks . Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, droughts, or floods) or may be driven by longer-term shifts in climate patterns that may cause sea levels to rise or chronic heat waves. Potential physical risks may cause direct damage to assets and indirect impacts, such as supply chain disruption, and also could include changes in water availability, sourcing, and quality, which could impact drilling and completion operations. These physical risks could cause increased costs, production disruptions, and lower revenues and could substantially increase the cost or limit the availability of insurance.
A substantial part of our crude oil, natural gas and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations.
Although we have significant leasehold positions in the Delaware Basin in Texas, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionatelyexposed to the effect of any regional events, including natural disasters, government regulations and midstream interruptions.
For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionatelysevere to us compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, the demand for, and cost of, drilling rigs, equipment, supplies, chemicals, personnel and oilfield services often increase as a result of numerous factors including increases in exploration and production activity, supply chain problems, and labor shortages. Any shortages or increased costs could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations. All of the producing properties and reserves we acquired in the past three years are located in the Wattenberg Field. As a result, the transactions increased the risks we face with respect to the geographic concentration of our properties.
The marketability of our production is dependent upon transportation and processing facilities which we do not control. If these facilities are unavailable, or if we are unable to access these facilities on commercially reasonable terms, our operations could be interrupted, negatively affecting our results of operations.
Our ability to market our production depends in substantial part on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, and transportation pipelines, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production may be curtailed and our results of operations will be adversely affected.
Availability or capacity issues can be a result of increased commodity prices that incentivize increased drilling and completion activities and increase commodity supplies, potentially constraining transportation capacity and subsequently lowering production volumes and realized prices. The increased commodity supplies can sometimes be more heavily weighted toward one commodity versus another. For instance, increased crude oil and natural gas prices in the first half of 2022 have incentivized producers in the Permian Basin to increase the level of drilling and completion activities. The potential increase in production levels has led to high utilization of the existing pipeline capacity out of the region. Until new pipeline expansions are placed in service, the transportation constraints in the Permian Basin may lead to lower realized natural gas prices.
These issues can also result from depressed commodity prices that ultimately reduce investment in new midstream facilities. Additionally, protests over construction of new pipelines and facilities, new or amended government regulations curtailing drilling activities in Colorado which could discourage investment in midstream facilities, extreme weather, fire, or other reasons could also negatively affect our production volumes and realized prices.
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Like other producers, we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to substantial shortfalls, deficiency, or similar fees.
Our undeveloped acreage must be drilled before lease expiration, and production must thereafter be maintained under applicable lease terms to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells and thereafter maintain production under applicable lease terms could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established and thereafter maintained under applicable lease terms within the spacing or pooled units covering our undeveloped acreage, our leases for such acreage will expire. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. Unexpected lease expirations could occur if our actual drilling activities or our ongoing production differ materially from our current expectations, and this could result in impairment charges. The risk of lease expiration is greater at times and in areas where the pace of our exploration and development activity slows or production declines or is otherwise shut-in. Our ability to drill, develop, and maintain production under applicable lease terms from the locations necessary to maintain our leases depends on a number of factors, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, and regulatory approvals, all of which are subject to risks and uncertainties.
We may incur losses as a result of title defects in the properties in which we invest or acquire.
Prior to acquiring oil and gas leases or interests, we engage oil and gas lease brokers or landmen (rather than title attorneys) to perform record title examinations. The existence of a material title deficiency can decrease a lease’s value and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use at a reasonable cost, in a timely manner and within applicable environmental rules.
Drilling and development activities such as hydraulic fracturing require the use of water and result in the production of wastewater. Our operations could be adversely impacted if we are unable to locate sufficient amounts of water or dispose of or recycle water used and produced in our exploration and production operations. The quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints, supply concerns and regulatory issues, particularly in relatively arid climates such as eastern Colorado and western Texas. For example, increased drilling activity in the Delaware Basin in recent years has led to heightened concerns about water supply issues in the area and this may lead to regulatory actions, including rules providing local governments greater authority over water use, that adversely impact our operations.
Our operations depend on being able to reuse or dispose of wastewater in a timely and economic fashion. Wastewater from oil and gas operations is often disposed of through underground injection. Wells in the Delaware Basin typically produce relatively large amounts of water that require disposal and an increased number of earthquakes have been detected in the Delaware Basin in recent years. Some studies have linked earthquakes, or induced seismicity, in certain areas to underground injection, which is leading to increased public and regulatory scrutiny of injection safety. For example, in November 2022, a magnitude 5.4 earthquake occurred within the Delaware Basin. In response, the Texas Railroad Commission has taken actions to significantly reduce deep and shallow salt water disposal injection volumes in certain areas. This increased scrutiny applies to our Colorado operations as well, though to a lesser extent.
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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 in 2020, to write down assets. Similarly, the significant decline in commodity pricing 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 determined in 2021 that our Delaware Basin position supported fewer wells per unit than previously assumed. Accordingly, our estimated well locations for our Delaware Basin position decreased from 135 to 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 our business acquisitions have increased 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 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.
Our customers, counterparties and lenders may be unable to satisfy their contractual or legal obligations.
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 oil, NGLs and natural gas production and liquidity risk in the event one or more lenders under our existing credit facility are unable to perform their funding obligations. In the event a customer, contractual counterparty or lender fails to 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, 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 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 attract and retain high quality employees with the 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 labor conditions in the oilfield, including a greater number of short-service contractor employees.
Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential environmental 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 gainunauthorized 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 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.
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 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, 2022, we had total long-term debt of $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 not be able to complete any such steps on satisfactory terms. Any 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, 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, 2022, we had hedged a total of 25.3 MMBbls crude oil for 2023 to 2025 and 214.8 BBtu of natural gas for 2023 to 2025. These hedges may be inadequate to protect us from continuing and prolongeddeclines 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 greatervolatility 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 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.
Tax law changes could have an adverse effect on our financial position, results of operations and cash flows.
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 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 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 the year incurred; and 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 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.
declined
Crude Oil Markets
During the first half of 2022, crude oil pricing generally increased due to increased demand, restrained OPEC+ production and uncertainties resulting from the Russian invasion of Ukraine. However, throughout 2022, the U.S. has experienced the highest inflation rates since 1981 resulting mainly from the global recovery from COVID-19, supply chain disruptions, higher labor costs, and higher energy costs. To address the increasing inflation rates, the U.S. Federal Reserve started increasing the benchmark federal funds interest rate. The magnitude and overall effectiveness of these actions remains uncertain, but such monetary policy changes can increase the risk of economic slowdown and/or lead to a recession. A slowdown or recession can cause a decrease in short-term or long-term demand for commodities, resulting in industry oversupply and a potential for lower commodity prices, which would impact our drilling program and further increase the volatility of our common stock price.
Natural Gas and NGL Markets
In addition to the crude oil market drivers noted above, natural gas and NGL prices are also affected by structural changes in supply and demand, growth in levels of liquified natural gas and liquified petroleum gas exports and deviations from seasonally normal weather. Europe’s shift away from Russia’s natural gas has led to Europe becoming increasingly dependent on U.S. LNG exports, creating new sources of demand for U.S. natural gas.
Lower inventory levels and lack of reinvestment in supply growth led to higher natural gas and NGL prices in 2022. However, a warmer winter in some parts of the world and a weakened economy has driven down the price of natural gas in early 2023.
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Financial Matters
Year ended December 31, 2022
• Production volumes increased to 85.0 MMboe in 2022, an increase of 19 percent compared to 71.3 MMboe in 2021, primarily driven by production volumes from the Great Western Acquisition and as a result of our turn-in-line activities in 2022.
• Crude oil, natural gas and NGLs sales increased to $4.3 billion in 2022 compared to $2.6 billion in 2021, primarily due to a 41 percent increase in weighted average realized commodity prices and a 19 percent increase in production volumes between periods.
• Negative net cash settlements from our commodity derivative contracts increased to $880 million in 2022 compared to $410 million in 2021 due to continued improvement in commodity pricing year over year and additional commodity derivatives assumed in the Great Western Acquisition.
• Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 59 percent to $3.4 billion from $2.1 billion in 2021.
• Net income increased to $1,778 million, or $18.49 per diluted share, compared to $522 million, or $5.22 per diluted share, in 2021, primarily due to (i) an increase in crude oil, natural gas and NGLs sales of $1,744 million, (ii) a $238 million decrease in net commodity risk management loss and (iii) a gain on bargain purchase in the Great Western Acquisition of $90 million . These positive factors were partially offset by (i) a $428 million increase in income tax expense (ii) a $253 million increase in production costs and (iii) a $115 million increase in depreciation, depletion and amortization expense between periods.
• Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $2.7 billion compared to $1.6 billion in 2021, primarily due to an increase in sales of $1.3 billion, net of negative net derivative settlements, and a $90 million gain on bargain purchase recognized in 2022, partially offset by an increase in costs experienced in operations between periods.
• Cash flows from operations increased to $2.8 billion compared to $1.5 billion in 2021 primarily due to an increase in sales of $1.3 billion, net of negative net derivative settlements, partially offset by an increase in costs experienced in operations between periods. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to $2.5 billion compared to $1.5 billion in 2021. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to $1,421 million from $949 million in 2021.
See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.
Great Western Acquisition
On May 6, 2022, we completed the acquisition of Great Western for approximately $1.4 billion, inclusive of Great Western’s net debt. Great Western was an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in the Wattenberg Field of Colorado. The consideration paid was $542.5 million in cash and approximately 4.0 million shares of our common stock, valued at $293.3 million on the acquisition date. In addition, we paid off Great Western’s secured credit facility totaling $235.8 million, and paid $361.2 million to terminateGreat Western’s 12 percent senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. The cash portion of the purchase price and the termination of Great Western’s debt was funded through a combination of cash on hand and availability under our revolving credit facility. As a result of the Great Western Acquisition, we acquired approximately 54,000 net acres in the core Wattenberg Field and production of approximately 50,000 Boe per day.
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Drilling, Completion and Vertical Wells Abandonment Overview
In the Wattenberg Field, we operated one full-time drilling rig and one full-time completion crew during 2022, added a second full-time drilling rig in March 2022 and a third full-time drilling rig plus an intermittent completion crew in May 2022 upon closing the Great Western Acquisition . In addition, we operated one full-time drilling rig during 2022 and had one completion crew in the first half of 2022 in the Delaware Basin. Our total capital investments in crude oil and natural gas properties for the year ended December 31, 2022 were $1.1 billion. Pursuant to our plugging and abandonment program, we operated a full-time workover rig in the Wattenberg Field in 2022. The workover rig was focused on our legacy vertical wells to assist in our horizontal drilling program and to reduce our overall produced well emissions. Separate from our capital investments, we spent $21 million on this program in 2022.
The following table summarize our drilling, completion and vertical well abandonment activities for the year ended December 31, 2022:
Operated Wells
Wattenberg Field
Delaware Basin
Total
Gross
Net
Gross
Net
Gross
Net
In-process as of December 31, 2021
Wells spud
Wells acquired in-process (1)
Wells turned-in-line
Developmental and exploratory dry hole
In-process as of December 31, 2022
Plugged and abandoned - Vertical Wells
(1) Represents in-process wells we obtained as part of the Great Western Acquisition.
Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our in-process wells are generally completed and turned-in-line within two years of drilling.
Capital Returns
Stock Repurchase Program. In February 2022, our board of directors approved a new stock repurchase program that reset the total repurchase value to $1.3 billion, which we currently anticipate fully utilizing by December 31, 2023. We repurchased 12.1 million shares of outstanding common stock at a cost of $823 million for the year ended December 31, 2022. As of December 31, 2022, $455 million remained available for repurchase under the program. In February 2023, our board of directors approved a $750 million increase in the size of the program, which we currently anticipate fully utilizing by December 31, 2025.
Dividends . Our board of directors approved the declaration and payment of a quarterly cash dividend of $0.25 per share of common stock in the first quarter of 2022 and increased our base quarterly dividend to $0.35 per share of common stock in the second quarter of 2022. In December 2022, our board of directors declared and paid a special dividend of $0.65 per share of our common stock in addition to the regular fourth quarter dividend. For the year ended December 31, 2022, our dividends declared totaled $184 million or $1.95 per share of outstanding common stock. In February 2023, our board of directors approved an increase in the quarterly base dividend from $0.35 to $0.40 per share.
2023 Operational and Financial Outlook
We anticipate that our production for 2023 will range between 255,000 Boe to 265,000 Boe per day, of which approximately 82,000 Bbls to 86,000 Bbls is expected to be crude oil. Our planned 2023 capital investments in crude oil and natural gas properties, which we expect to be between $1,350 million and $1,500 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin. Our 2023 capital budget and operating costs may continue to be impacted by cost inflation, supply chain constraints and availability of labor services.
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We have operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining inventory to best meet our short- and long-term corporate strategy. We may revise our 2023 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds and acquisition and divestitureopportunities.
Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field. Our 2023 capital investment program for the Wattenberg Field represents approximately 80 percent of our expected total capital investments in crude oil and natural gas properties. Our plan includes spudding and turning-in-line 200 to 225 operated wells. To meet our development plan, we intend on running three full-time horizontal drilling rigs and one full-time completion crew plus an intermittent completion crew during the year. As of December 31, 2022, we have approximately 200 gross operated DUCs and 915 approved permitted or CAP locations (i.e., locations that are contemplated by an approved CAP but still require approval under an OGDP).
Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2023 are expected to be approximately 20 percent of our total capital investments. In 2023, we anticipate spudding and turning-in-line 15 to 25 operated wells.
We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2023, we expect 2023 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. Our first priority is to pay our quarterly base dividend of $0.40 per share. Then we expect to use approximately 60 percent or more of our remaining adjusted free cash flow, a non-U.S. GAAP financial measure, for share repurchases and special dividends, as needed. Any remaining adjusted free cash flows will be used for reducing debt and other general corporate purposes.
Regulatory and Political Updates
Colorado law requires an operator to obtain an OGDP prior to initiating development work relating to a well. The OGDP process streamlines single pad locations or proximate multi-pad locations into a single permitting package.
Operators in Colorado also have an option to pursue a CAP. A CAP is designed to represent an overview of oil and gas development over a larger area over a longer period of time through means including a comprehensive cumulative impact analysis, an alternative location analysis, and extensive communication with both local elected officials and communities. A CAP will include multiple OGDPs within its boundaries.
In June 2022, the COGCC granted PDC unanimous approval for a 69-well OGDP and a 30-well OGDP acquired in the Great Western Acquisition, our second and third approvals under the new Colorado permitting process. Additionally, in December 2022, the COGCC unanimously approved our first CAP, filed in December 2021, which encompasses approximately 450 wells in Weld County, Colorado. Following the approval of the CAP, we will submit individual OGDP packages for each of the locations within the CAP. The CAP, along with our prior OGDPs, represent the majority of our projected Wattenberg Field turn-in-line activity into 2028 based on our current pace and drilling plan in 2023.
Environmental, Social and Governance
We are committed to a meaningful and measurable ESG strategy. Our mission of being a cleaner, safer and more socially responsible company begins with a sound strategy, is supported in the boardroom and is overseen by our Environmental, Social, Governance and Nominating Committee at the board of directors, our internal Steering Committee and is considered at every level of our business.
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We recognize the importance of reducing our environmental footprint and have created proactive programs and targets related to emission reduction. These initiatives, which include the plugging and abandonment of legacy vertical wells, retrofits of air pneumatics on older facilities, electrification of our facilities, transportation pipelines, technological innovations and other activities, require capital and operational investments which are proactively and regularly built into our annual budgeting process. In 2022, we spent approximately $80 million on ESG initiatives, which included (i) $20.5 million in plugging and abandonment costs for 243 vertical wells, (ii) approximately $20.0 million on emission reduction devices, such as electric drilling, air pneumatics and vapor recovery units on new and older wells, (iii) $10.5 million on the installment of water pipelines, and (iv) $5.0 million on giving, outreach and community relations. In 2023, additional environmental and compliance transition costs, such as emission reduction costs, are included in our budget. Some of our larger anticipated capital projects in 2023 include $10 million to $15 million for the installation of water pipelines primarily in Adams County, $20 million to $25 million for plugging and abandonment of approximately 250 legacy vertical wells and $15 million to $20 million for the continued increase of electrification in our operations.
As part of our ESG initiatives, we have set aggressive targets to (i) reduce greenhouse gas intensity by 60% from 2020 levels by 2025 and 74% by 2030, (ii) reduce methane emissions intensity by 50% from 2020 levels by 2025 and 70% by 2030, and (iii) eliminate routine flaring, as defined by World Bank, by 2025. In March 2022, we completed our EPA annual filing for 2021 emissions and reported an approximate 12% reduction in GHG emissions, an approximate 17% reduction in methane emissions intensity and an approximate 70% reduction in flared hydrocarbons from 2020 baseline levels (each on a per unit of production basis), putting us on track to meet our goals.
In May 2022, our board of directors approved quantitative metrics for GHG and methane emissions reductions for our 2022 short-term incentive program, including 15% GHG and 30% methane emissions reduction targets from 2021 to 2022. As noted above, this supports the Company’s previously announced sustainability goals. In total, over 25% of our short-term incentive program in 2022 was tied to ESG and other environmental, health and safety initiatives. Our 2022 initial results indicate a reduction of over 30% in GHG and 50% in methane emissions from our 2021 levels.
In 2022 our board of directors was significantly engaged in our Sustainability reporting process, as it and our senior management team underwent its first TCFD process. Additionally, we filed our first Carbon Disclosure Project (“CDP”) Climate Change Questionnaire, examining our future through a range of climate-focused scenarios. In September 2022, we issued our annual Sustainability reports. The reports include key metrics and data from 2021 operations and are aligned with Sustainable Accounting Standards Board (“SASB”) standards and TCFD.
Additional information on our ESG practices, including sustainability goals, key metrics and progressachieved, can be found on the Sustainability page of our website at www.pdce.com. The information on our website, including the Sustainability reports, is not incorporated by reference in this report.
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Results of Operations
Summary of Operating Results
The following table presents selected information regarding our operating results for the periods presented:
Year Ended December 31,
Percent Change
(dollars in millions, except per unit data)
Production:
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Crude oil equivalent (MBoe)
Average Boe per day (Boe)
Crude Oil, Natural Gas and NGLs Sales:
Crude oil
Natural gas
NGLs
Total crude oil, natural gas and NGLs sales
Net Settlements on Commodity Derivatives:
Crude oil
Natural gas
Total net settlements on derivatives
Average Sales Price (excluding net settlements on derivatives):
Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Crude oil equivalent (per Boe)
Average Costs and Expense (per Boe):
Lease operating expense
Production taxes
Transportation, gathering and processing expenses
General and administrative expense
Depreciation, depletion and amortization
Lease Operating Expense by Operating Region (per Boe):
Wattenberg Field
Delaware Basin
* Percent change is not meaningful.
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Crude Oil, Natural Gas and NGLs Sales
Crude oil, natural gas and NGLs sales for the year ended December 31, 2022 increased compared to the year ended December 31, 2021 due to the following:
Year Ended December 31, 2022
(in millions)
Change in:
Production
Increase in production from acquisitions
Average crude oil price
Average natural gas price
Average NGLs price
Total change in crude oil, natural gas and NGLs sales revenue
Crude Oil, Natural Gas and NGLs Production
The following table presents crude oil, natural gas and NGLs production for the periods presented:
Year Ended December 31,
Percent Change
Production by Operating Region
Crude oil (MBbls)
Wattenberg Field
Delaware Basin
Total
Natural gas (MMcf)
Wattenberg Field
Delaware Basin
Total
NGLs (MBbls)
Wattenberg Field
Delaware Basin
Total
Crude oil equivalent (MBoe)
Wattenberg Field
Delaware Basin
Total
Average crude oil equivalent per day (Boe)
Wattenberg Field
Delaware Basin
Total
Net production volumes for crude oil, natural gas and NGLs increased 19 percent during the year ended December 31, 2022 compared to 2021. The increase in production volume between periods was primarily due to approximately 11.5 MMboe of additional production volumes as a result of the Great Western Acquisition and the net impact of turn-in-line activities in both basins since the fourth quarter of 2021. The increase was partially offset by normal decline in production from our existing wells.
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The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented:
Year Ended December 31,
Production Ratio by Operating Region
Wattenberg Field
Crude oil
Natural gas
NGLs
Total
Delaware Basin
Crude oil
Natural gas
NGLs
Total
Midstream Capacity
Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, as well as transportation pipelines out of the basin, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available on a timely basis and at acceptable costs, our production and results of operations could be adversely affected.
The ultimate timing and availability of adequate infrastructure remains out of our control. Weather, regulatory developments, preventative routine maintenance and other factors also affect the adequacy of midstream infrastructure. Like other producers, from time to time we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to meet our projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls.
Our production from the Wattenberg Field and the Delaware Basin was not materially affected by midstream or downstream capacity constraints during the year ended December 31, 2022. We continuously monitor infrastructure capacities versus producer activity and production volume forecasts. Increases in crude oil and natural gas prices in 2022 have incentivized producers in the Permian Basin to increase the level of drilling and completion activities. The increase in production levels and continued increase in development may lead to natural gas transportation constraints out of the Permian Basin in 2023, which may result in lower realized Waha natural gas prices. However, approximately half of PDC’s gas production in the Delaware Basin is dedicated to the Permian Highway Pipeline and is exposed to Houston-based gas pricing. We believe that this reduces the risk of a decrease in realized natural gas prices related to transportation constraints.
Crude Oil, Natural Gas and NGLs Pricing
Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially.
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The following table presents weighted average sales prices of crude oil, natural gas and NGLs for the periods presented:
Weighted Average Realized Sales Price by Operating Region
Year Ended December 31,
Percent Change
(excluding net settlements on derivatives)
Crude oil (per Bbl)
Wattenberg Field
Delaware Basin
Weighted average price
Natural gas (per Mcf)
Wattenberg Field
Delaware Basin
Weighted average price
NGLs (per Bbl)
Wattenberg Field
Delaware Basin
Weighted average price
Crude oil equivalent (per Boe)
Wattenberg Field
Delaware Basin
Weighted average price
* Percent change is not meaningful.
Crude oil, natural gas and NGLs revenues are recognized when we transfer control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to occur when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production.
Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or “gross” method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us based on a percent of proceeds or a sales price fixed at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index on which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transportation and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing (“TGP”) expense.
Information related to the components and classifications of TGP expense on the consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based on average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based on first-of-the-month index prices, as in each case this is the method used to sell the majority of these commodities pursuant to terms of the relevant sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after TGP expense shown in the table below represents our approximate composite per barrel price for NGLs for the periods presented.
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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)
Natural gas (per MMBtu)
NGLs (per Bbl)
Crude oil equivalent (per Boe)
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)
Natural gas (per MMBtu)
NGLs (per Bbl)
Crude oil equivalent (per Boe)
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)
Natural gas (per MMBtu)
NGLs (per Bbl)
Crude oil equivalent (per Boe)
(1) Average TGP expense excludes unutilized firm transportation fees of $0.14, $0.11, and $0.04 per Boe for the years ended December 31, 2022, 2021, and 2020, respectively.
Our average realization percentage for crude oil equivalent was relatively consistent in 2022 as compared to 2021 due to the overall increases in commodity prices between periods and realized improved differentials from our 2022 crude oil sales contracts. This was offset by a weakening Mont Belvieu price in the second half of 2022, impacting our realized price for NGLs and higher TGP rates for our natural gas production.
Commodity Price Risk Management
We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including collars, fixed-price exchanges, and basis protection exchanges on a portion of our estimated crude oil and natural gas production. For our commodity exchanges, we ultimately realize the fixed price value related to the swaps. See Note 6 - Commodity Derivative Financial Instruments in Item 8. Financial Statements and Supplementary Data included elsewhere in this report for a summary of our derivative positions as of December 31, 2022.
Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, and the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas production.
Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The
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net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward price curves and changes in certain differentials.
The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net:
Year Ended December 31,
(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil collars and fixed price exchanges
Natural gas collars and fixed price exchanges
Natural gas basis protection exchanges
Total net settlements of commodity derivative instruments
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments
Crude oil collars and fixed price exchanges
Natural gas collars and fixed price exchanges
Natural gas basis protection exchanges
Net change in fair value of unsettled commodity derivative instruments
Total commodity price risk management gain (loss), net
The significant increase in commodity prices during 2022 had an overall unfavorable impact on the fair value and settlements of our commodity derivatives.
Lease Operating Expense
Lease operating (“LOE”) expense increased by 46 percent to $263.0 million in 2022 compared to $180.7 million in 2021. The period-over-period increase in LOE was primarily due to (i) an approximate $30.0 million increase from operated wells acquired in the Great Western Acquisition, (ii) an increase of $20.0 million from increased activity and the impact of inflation in the Wattenberg Field, (iii) a $15.2 million increase in workover expense relating to activities mainly in the Delaware Basin and (iv) a $12.5 million increase in chemical treatments, water disposal and well services in the Delaware Basin as a result of increased activity and the impact of inflation. LOE per Boe increased 22 percent to $3.09 in 2022 from $2.53 in 2021 primarily due to the additional costs outlined above.
Production Taxes
Production taxes are comprised mainly of severance tax and ad valorem tax, and are directly related to crude oil, natural gas and NGLs sales and are generally assessed as a percentage of net revenues. From time to time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined based upon activity levels and relative commodity prices.
Production taxes increased 89 percent to $311.8 million in 2022 compared to $165.2 million in 2021. The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs sales between periods. Production taxes per Boe increased 58 percent to $3.67 in 2022 compared to $2.32 in 2021.
Transportation, Gathering and Processing Expense
TGP expense increased 24 percent to $124.6 million in 2022 compared to $100.4 million in 2021. The increase in TGP expense between periods was primarily due to an increase in gas processing volumes and higher rates in the Delaware Basin. TGP per Boe was $1.46 and $1.41 for 2022 and 2021, respectively.
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Exploration, Geologic, and Geophysical Expense
Exploration, geologic and geophysical expense increased to $13.1 million in 2022 compared to $1.1 million in 2021. In 2022, we drilled and turned-in-line an exploratory well in the Delaware Basin that was not economically viable. During 2022, we expensed the associated lease costs and related infrastructure assets of the exploratory dry hole at a cost of $12.0 million .
Impairment of Properties and Equipment
The following table sets forth the major components of our impairment of properties and equipment for the periods presented:
Year Ended December 31,
(in millions)
Impairment of proved and unproved properties
Impairment of infrastructure and other
Total impairment of properties and equipment
There were no significant impairment charges recognized in relation to our proved and unproved oil and gas properties in 2022 or 2021. If crude oil prices were to decline, or we change other estimates impacting future net cash flows (e.g. reserves, price differentials, future operating and/or development costs), our proved and unproved oil and gas properties could be subject to additional impairments in future periods.
During the first quarter of 2020, we recorded impairment charges of $881.1 million to our proved and unproved properties in the Delaware Basin. These impairment charges were due to a significant decline in crude oil prices, which was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment.
General and Administrative Expense
General and administrative expense increased to $156.3 million in 2022 compared to $127.7 million in 2021 primarily due to $18.2 million in transaction and transition costs relating to the Great Western Acquisition and a $6.4 million increase related to salaries, wages and benefits as a result of an increase in headcount from the Great Western Acquisition along with an increase in drilling activity.
Depreciation, Depletion and Amortization Expense
Crude oil and natural gas properties. During 2022 and 2021, we invested $1,107.7 million and $583.6 million, respectively, exclusive of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties. Depreciation, depletion and amortization expense (“DD&A”) related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $741.9 million and $627.5 million in 2022 and 2021, respectively. The increase in total DD&A expense was primarily due to a 19 percent increase in production volumes between periods driven by the Great Western Acquisition. The increase was partially offset by a decrease in weighted average depletion rate resulting from the improved reserve quantities as of December 31, 2022 as a result of increased commodity prices in 2022.
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The year-over-year change in DD&A expense for related to crude oil and natural gas properties was primarily due to the following:
Year Ended December 31,
(in millions)
Increase in production
Decrease in weighted average depletion rate
Total decrease in DD&A expense related to crude oil and natural gas properties
The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties for the periods presented:
Year Ended December 31,
(per Boe)
Operating Region/Area
Wattenberg Field
Delaware Basin
Total weighted average DD&A expense rate
Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $7.8 million for the year ended December 31, 2022, compared to $7.7 million for the year ended December 31, 2021.
Interest Expense, net
Interest expense, net decreased by $18.0 million to $64.7 million in 2022 compared to $82.7 million in 2021. The decrease was primarily due to (i) a $17.8 million decrease from a partial redemption of our 2024 Senior Notes and a full redemption of Convertible Notes and certain Senior Notes in the second half of 2021, (ii) a $6.9 million loss on extinguishment recognized in 2021 relating to the redemption of certain other Senior Notes and (iii) an $8.0 million decrease in debt issuance cost amortization as a result of debt expiration and redemptions in 2021. These decreases were partially offset by an $18.4 million increase relating to increased borrowings under our revolving credit facility in 2022 to finance the cash portion of the purchase price of the Great Western Acquisition as well as an overall increase in interest rates on our credit facility.
Gain on Bargain Purchase
We recognized a $90.1 million gain on the bargain purchase of the Great Western Acquisition, net of related income taxes of $28.4 million, in 2022. For additional information, see Note 3 - Business Combination in Item 8. Financial Statements and Supplementary Data included elsewhere in this report.
Provision for Income Taxes
We recorded income tax expense of $454.2 million and $26.6 million for 2022 and 2021, respectively, resulting in effective tax rates of 20.3 percent and 4.8 percent on the respective pre-tax income. The effective tax rates differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax income due to state income taxes and changes in the valuation allowance against our deferred income tax assets.
We consider whether a portion, or all, of our deferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the available taxes in carryback periods, the future reversals of existing taxable temporary differences, tax planning strategies and projected future taxable income in making this assessment. Our oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to provide a valuation allowance against our DTAs beginning January 1, 2020 since we previously could not conclude that it is more likely than not that our DTAs will be fully realized in future periods.
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As we previously disclosed, we maintained a valuation allowance on our net federal deferred tax assets and continued to do so until sufficient positive evidence existed to support a reversal of the allowance. In 2022, continued higher commodity prices increased our income, resulting in the reversal of objective negative evidence of cumulative loss in recent years, and we determined that we have sufficient positive evidence to release the valuation allowance. As a result, we released the full valuation allowance of $56.6 million against our deferred income tax assets and recognized a corresponding decrease to income tax expense.
Given recent improvements in oil and gas prices and assumptions based on our current production forecasts, we estimate that we will incur federal and state cash income taxes in 2023.
In August 2022, the IRA was signed into law. The IRA includes implementation of a new alternative minimum tax, an excise tax on stock buybacks, and significant tax incentives for energy and climate initiatives, among other provisions. The alternative minimum tax and excise tax on stock buyback provisions are effective for tax years beginning after December 31, 2022. We continue to monitor updates to the IRA and the impact of the IRA on our financial position, results of operations and liquidity. We do not believe the IRA will have a material impact on our stock buyback program or our financial position in 2023, however, we are still assessing the impact for subsequent years.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors impacting net income of $1,778 million and $522 million in 2022 and 2021, respectively, are discussed above.
Adjusted net income, a non-U.S. GAAP financial measure, was $1,450 million and $800 million for the year ended December 31, 2022 and 2021, respectively. With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted net income. See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.
Financial Condition, Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash and cash equivalents, cash flows from operating activities, unused borrowing capacity from our revolving credit facility, proceeds raised in debt and equity capital market transactions and other sources, such as asset sales.
Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile, and we manage a portion of this volatility through our use of commodity derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production.
We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions, capital returns and for general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. These activities typically result in a working capital deficit; however, we do not believe that our working capital deficit as of December 31, 2022 is an indication of a lack of liquidity. We had working capital deficits of $826 million and $462 million at December 31, 2022 and 2021, respectively. The increase in working capital deficit since December 31, 2021 primarily was a result of the Great Western Acquisition and a significant increase in production taxes payable due to increase in sales between periods. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time.
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From time to time, we may seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise.
Liquidity
Our cash and cash equivalents were $6.5 million at December 31, 2022 and availability under our revolving credit facility was $1.1 billion, providing for total liquidity of $1.1 billion as of December 31, 2022. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests.
Our material short-term and long-term cash requirements consist primarily of capital expenditures, payments of contractual obligations, dividends, share repurchases, income taxes and working capital obligations. If commodity prices increase, our working capital requirements may increase due to higher operating costs and negative settlements on our outstanding commodity derivative contracts. Funding for these requirements may be provided by any combination of our capital resources previously outlined.
As a result of the Great Western Acquisition, we paid $361 million on Great Western’s behalf to pay and discharge Great Western’s 12% senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. Additionally, we paid $236 million on Great Western’s behalf to pay Great Western’s secured credit facility, inclusive of unpaid accrued interest. The termination of Great Western’s debt was funded through a combination of cash on hand and availability under our revolving credit facility.
Based on our current production forecast for 2023, we expect 2023 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. In addition, based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to fund our planned activities through the 12-month period following the filing of this report. We also believe that we will have sufficient expected cash flows from operations to allow us to execute our capital return plan. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board.
Our material long-term cash requirements relate to debt obligations and interest payments, commodity derivative contract liabilities, production taxes, operating and finance leases, asset retirement obligations and firm transportation and processing agreements included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report.
In October 2022, as part of the semi-annual redetermination of the borrowing base under our credit facility, the borrowing base increased from $3.0 billion to $3.5 billion, primarily due to the addition of the reserves acquired from Great Western; however, we maintained our elected commitment level of $1.5 billion. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements (a) to maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 3.5:1.0. For purposes of the current ratio covenant, the revolving credit facility’s definition of total current assets, in addition to current assets as presented under U.S. GAAP, includes, among other things, unused commitments under the revolving credit facility and excludes the fair value of commodity derivative assets. Additionally, the current ratio covenant calculation allows us to exclude the fair value of commodity derivative liabilities and the current portion of our long-term debt and other short-term loans from the U.S. GAAP total current liabilities amount. Accordingly, the existence of a working capital deficit under U.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. At December 31, 2022, we were in compliance with all covenants in the revolving credit facility with a current ratio of 1.5:1.0 and a leverage ratio of 0.5:1.0.
We expect to remain in compliance with the covenants under our credit facility and our Senior Notes throughout the 12-month period following the filing of this report.
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Cash Flows
Our cash flows from operating, investing and financing activities are as follows:
Year ended December 31,
(in thousands)
Cash flows from operating activities
Cash flows from investing activities
Cash flows from financing activities
Net increase (decrease) in cash and cash equivalents
Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities increased by $1,225 million to $2,772 million in 2022 as compared to $1,548 million in 2021. The increase between periods was primarily due to a $1,744 million increase in crude oil, natural gas and NGLs sales and changes in the timing of receivable collections. These increases were partially offset by a $470 million increase in cash settlement losses on commodity derivatives, a $147 million increase in production taxes, an $82 million increase in lease operating expenses and changes in the timing of vendor and royalty owner payments between periods.
Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $1,006 million in 2022 to $2,538 million from $1,533 million in 2021. The increase was primarily due to the factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. Adjusted free cash flow, a non-U.S. GAAP financial measure, increased by $472 million in 2022 to $1,421 million from $949 million in 2021. The increase was primarily due to the increase in cash flows from operating activities, as discussed above, partially offset by an increase in capital investments in crude oil and natural gas properties as a result of our 2022 development plan.
See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.
Investing Activities. As crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our crude oil and natural reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments.
Cash flows from investing activities in 2022 primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $2,150 million during 2022 was primarily due to $1,068 million utilized for the Great Western Acquisition and drilling and completion activities of $1,070 million, partially offset by $16 million in proceeds from the sale of certain properties and equipment.
Net cash used in investing activities of $579 million during 2021 was primarily related to our drilling and completion activities of $583 million, partially offset by $5 million in proceeds from the sale of certain properties and equipment.
Financing Activities. Net cash used in financing activities in 2022 of $650 million was primarily due to (i) the repurchase of 12.1 million shares of our common stock for $818 million pursuant to our stock repurchase program and (ii) dividend payments totaling $182 million, partially offset by net borrowings on our credit facility of $370 million to fund the cash portion of the purchase price of the Great Western Acquisition and to terminateGreat Western’s debt. As of December 31, 2022, $455 million out of the approved $1.3 billion remained available for stock repurchases under the program. In February 2023, our board of directors approved a $750 million increase in the size of the program. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board.
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Net cash used in financing activities in 2021 of $938 million was primarily due to (i) net repayments on our credit facility of $168 million, (ii) redemption and retirement of Convertible Notes and other Senior Notes totaling $509 million, (iii) the repurchase of 3.8 million shares of our common stock for $157 million pursuant to our stock repurchase program and (iv) dividend payments totaling $84 million.
Subsidiary Guarantors
PDC Permian, Inc., a Delaware corporation (“Permian”), and Pioneer Water Pipeline LLC, a Delaware limited liability company (“Pioneer” and together with Permian, the “Guarantors”), each a wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes and 2026 Senior Notes (collectively, the “Senior Notes”). Permian holds our assets located in the Delaware Basin. Pioneer holds certain water midstream assets located in the Wattenberg Field. The Senior Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantors. The guarantees are subject to release in limited circumstances only upon the occurrence of certain customary conditions.
The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility, (ii) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (iii) sell assets, including capital stock of our restricted subsidiaries, (iv) restrict the payment of dividends or other payments by restricted subsidiaries to us, (v) create liens that secure debt, (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.
The following summarized subsidiary guarantor financial information has been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method.
(1) Gross profit is calculated as crude oil, natural gas and NGLs sales less production costs.
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Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements.
Our significant accounting policies are described in Note 2 - Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. The following discussion outlines the accounting policies and practices involving the use of estimates and application of significant judgment that are critical in determining our financial results. Changes in the estimates and assumptions discussed below could materially affect the amount or timing of our financial results.
Crude Oil and Natural Gas Reserve Quantities
We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. In determining the estimates of reserve and economic evaluations, management utilizes specialists, specifically petroleum engineers. Reserve quantities and the related estimates of future net cash flows are used as inputs in our calculation of depletion, evaluation of proved properties for impairment, assessment of expected realizability of our deferred income tax assets and calculation of the standardized measure of discounted future net cash flows.
The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include estimates of reserves volumes, future operating and development costs and historical commodity prices. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, we continually make revisions to reserve estimates as additional information becomes available. We cannot predict the amounts or timing of such future revisions.
If the estimates of proved reserve quantities decline, the rate at which we record depletion expense will increase, which would reduce future net income. Changes in depletion rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified.
We cannot predict future commodity prices. However, we performed a sensitivity analysis on our proved reserve estimates as of December 31, 2022, to present a decrease of approximately 20 percent in crude oil price (and holding all other factors constant), as the value of crude oil influences the value of our proved reserves most significantly. As a result, our proved reserve quantities would decrease by 7.8 MMBoe or 1 percent. The decrease would have increased our DD&A rate by $0.03 per Boe and decreased our pre-tax income by $2.2 million for the year ended December 31, 2022. This estimated impact is based on available data as of December 31, 2022, and future events could require different adjustments to our DD&A rate. During 2022 and 2021, we had positive revisions to our proved reserve quantities of 29.8 MMBoe and 52.9 MMBoe, respectively, as a result of higher average prices for crude oil, natural gas and NGLs. During 2020 we had a negative revision of 39.5 MMBoe as a result of lower average prices for crude oil, natural gas and NGLs. For more information regarding reserve estimations, including additional crude oil sensitives and descriptions over historical reserve revisions, see Items 1 and 2. Business and Properties - Oil and Gas Production and Operations and Supplemental Oil and Gas Information within our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data included elsewhere in this report.
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Impairment of Crude Oil and Natural Gas Properties
Upon a triggering event, we assess the valuation of our proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we estimate the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. We estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount.
Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a discount factor. Future commodity prices are estimated by using a combination of assumptions management uses in its budgeting and forecasting process, historical and future prices adjusted for geographical location and quality differentials, and other factors that management believes will impact realizable prices. The discount factor used is the market based weighted average cost of capital which is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas.
Unproved properties with individually significant acquisition costs are periodically assessed for impairment and reduced to fair value based on a review over our future development plans, estimated future cash flows for probable well locations and remaining average lease terms. Items that can impact our future development plans can be driven by drilling results, reservoir performance, capital resources and seismic interpretations. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense.
Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by their nature, highly uncertain and may vary significantly from actual results. We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above.
There were no significant impairment charges recognized related to our proved and unproved properties during the years ended December 31, 2022 or 2021. We recorded impairment charges of $881.1 million to our proved and unproved properties to our Delaware Basin properties in 2020 as a result of a significant decline in crude oil prices.
Valuation of Business Combinations
We follow the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any deficiency of the purchase price over the estimated fair values of the net assets acquired is recorded as a gain in statements of operations.
In connection with the Great Western Acquisition in 2022, we allocated $1.5 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the acquisition date. In estimating the fair values of assets acquired and liabilities assumed the most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices , and a market-based weighted average cost of capital rate. The Great Western Acquisition resulted in a gain on bargain purchase due to the estimated fair value of the identifiable net assets acquired exceeding the purchase consideration transferred by $90.1 million, net of related income taxes of $28.4 million. The bargain purchase was primarily attributable to the increase in commodity price forecasts from the date we entered into the definitive purchase agreement, February 26, 2022, to the closing date of the acquisition, May 6, 2022, when the fair value of the crude oil and natural gas reserves acquired was determined. Additionally, the majority of the acquisition consideration was fixed and therefore did not fluctuate as a result of market increases or decreases between the date of entry into the agreement through the closing date. Assuming all factors are held constant, an approximate 10 percent decrease in future commodity prices used in the valuation of the proved crude oil and natural gas properties would reduce the fair value by approximately $400 million, recognition of approximately $300 million of goodwill and no gain on bargain purchase.
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Additionally, for acquisitions with significant unproved properties, we may also review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties to determine an estimation of fair value.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in a higher depletion expense, which results in lower net earnings. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value.
Recent Accounting Pronouncements
There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of December 31, 2022.
Reconciliation of Non-U.S. GAAP Financial Measures
We use “adjusted cash flows from operations”, “adjusted free cash flow (deficit)”, “adjusted net income (loss)” and “adjusted EBITDAX”, non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.
Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities and to return capital to stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our performance and liquidity. Adjusted free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from the adjusted free cash flow measure.
We are unable to present a reconciliation of forward-looking adjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations.
Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance.
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Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, and acquisitions and to service our debt obligations.
PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves.
The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure for the periods presented:
Year Ended December 31,
(thousands)
Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:
Net cash from operating activities
Changes in assets and liabilities
Adjusted cash flows from operations
Capital expenditures for development of crude oil and natural gas properties
Capital expenditures for midstream assets
Change in accounts payable related to capital expenditures for oil and gas development activities and midstream assets
Adjusted free cash flow
Net income (loss) to adjusted net income (loss):
Net income (loss)
Loss (gain) on commodity derivative instruments
Net settlements on commodity derivative instruments
Tax effect of above adjustments (1)
Adjusted net income (loss)
Net income (loss) to adjusted EBITDAX:
Net income (loss)
Loss (gain) on commodity derivative instruments
Net settlements on commodity derivative instruments
Non-cash stock-based compensation
Interest expense, net
Income tax expense (benefit)
Impairment of properties and equipment
Exploration, geologic and geophysical expense
Depreciation, depletion and amortization
Accretion of asset retirement obligations
Loss (gain) on sale of properties and equipment
Adjusted EBITDAX
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Year Ended December 31,
(thousands)
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities
Gain on bargain purchase
Interest expense, net (2)
Amortization and write-off of debt discount, premium and issuance costs
Exploration, geologic and geophysical expense (3)
Other
Changes in assets and liabilities
Adjusted EBITDAX
Standardized measure of discounted future net cash flows
Present value of estimated future income tax discounted at 10%
(1) Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the year ended December 31, 2020.
(2) Excludes loss on extinguishment from early retirement of our senior notes amounting to $6.9 million for the year ended December 31, 2021.
(3) Excludes exploratory dry hole costs of $12.0 million for the year ended December 31, 2022 .
