Washington, D.C. 20549
PDC ENERGY, INC.
We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement filed pursuant to Regulation 14A for our 20192022 Annual Meeting of Stockholders.
PDC ENERGY, INC.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or theour industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
We are a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties (the "Utica Shale Divestiture") during the first quarter of 2018.
The following map presents the general locations of our development and production activities as of December 31, 2018:2021:
We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties, in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties.
The properties we own are subject to royalty, overriding royalty and other outstanding interests. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties.
The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us.
and disposal, prevention of waste, bonding requirements, surface use and restoration, public health and environmental protection and well plugging and abandonment. The primary state-level regulatory authority regarding these matters in Colorado is the Colorado OilCOGCC and Gas Conservation Commission (the “COGCC”) in Colorado andTexas is the Texas Railroad Commission in Texas. For example, priorCommission. Prior to preparing a surface location and commencing drilling operations on a well, we must procure permits and/or approvals for the various stages of the drilling process from the relevant state and local agencies. Similarly,In addition, our operations must comply with rules governing the size of drilling and spacing units or proration units and the unitization or pooling of lands and leases. Some states, such as Colorado, allow the forced pooling or integration of tracts to facilitate exploration while other states, such as Texas, rely primarily or exclusively on voluntary pooling of lands and leases.
In states such as Texas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore to drill and develop our leases in circumstances where we do not own all of the leases in the proposed unit. These risks also exist in Colorado, where the COGCC has imposed limits on forced pooling. State laws may also prohibit the venting or flaring of natural gas, which may impact rates of production of crude oil and natural gas from our wells. Leases covering state or federal lands often include additional laws, regulations and conditions which can limit the location, timing and number of wells we can drill and impose other requirements on our operations, all of which can increase our costs.
storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC"(“FERC”) under the Natural Gas Act of 1938 ("NGA"(“NGA”) and under the Natural Gas Policy Act of 1978 ("NGPA"(“NGPA”). Rates and charges for the transportation of natural gas in interstate commerce, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Natural gas pipeline companies hold certificates of public convenience and necessity issued by FERC authorizing ownership and operation of certain pipelines, facilities and properties.
Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are, however, subject to state regulation, which includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and rate regulation on a complaint basis. We own certain pipeline facilities in the Delaware Basin that we believe are exempt from regulation under the NGA as “gathering facilities,”facilities”, but which may in some cases be subject to state regulation.
Although FERC has set forth a general test to determine whether facilities are exempt from regulation under the NGA as “gathering” facilities, FERC’s determinations as to the classification of facilities are performed on a case-by-case basis. With respect to facilities owned by third parties and on which we move natural gas, to the extent that FERC subsequently issues an order reclassifying facilities previously thought to be subject to FERC jurisdiction as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of moving natural gas to the point of sale may be increased. Further, to the extent that FERC issues an order reclassifying facilities that we own that were previously thought to be non-jurisdictional gathering facilities as subject to FERC jurisdiction, we could be subject to additional regulatory requirements under the NGA and the NGPA.
Transportation and safety of natural gas is also subject to regulation by the U.S. Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Natural Gas Pipeline Safety Act of 1968, as
amended, which imposes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the “PIPES Act 2006”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “PIPES Act 2011”). We own certain pipeline facilities in the Delaware Basin that are subject to such regulation byunder PHMSA.
In addition to natural gas, we move crude oil, condensate and natural gas liquids (collectively, “liquids”) through pipelines owned by other entities and sell such liquids to other entities that also utilize pipeline facilities that may be subject to regulation by FERC. FERC regulates the rates and terms and conditions of service for the interstate transportation of liquids under the Interstate Commerce Act, as it existed on October 1, 1977 (the “ICA”), and the rules and regulations promulgated thereunder. This includes movements of liquids through any pipelines, including those located solely within one state, that are providing part of the continuous movement of such liquids in interstate commerce for a shipper. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC, setting forth established rates and the rules and regulations governing transportation service, which must be “just and reasonable.”reasonable”. The ICA also requires that services be provided in a manner that is not unduly discriminatory or unduly preferential; in some cases, this may result in the proration of capacity among shippers in an equitable manner.
The availability, terms and cost of transportation affect the amounts we receive for our commodities. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen thean increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area.
Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our operations. We cannot predict the occurrence, timing, nature or effect of these changes. We also operate under a number of environmental permits and authorizations. The issuing agencies may take the position that some or all of these permits and authorizations are subject to modification, suspension, or revocation under certain circumstances, but any such action would have to comply with applicable procedures and requirements.
We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”) and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as hazardous wastes, and therefore may subject us to more rigorous and costly operating and disposal requirements. In December 2016,April 2019, the U.S. District Court for the District of Columbia approvedEPA, pursuant to a consent decree between the EPA and a coalition of environmental groups.groups and a related review of RCRA regulations, determined that revision of the regulations is not necessary. The consent decree requires the EPA to review and determine whetherindicated that it will revise the RCRA regulationscontinue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastewastes continue to treat such waste as hazardous waste. The EPA must complete its reviewbe managed in a manner that is protective of human health and make itsthe environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision regarding revision by March 2019. Ifand will likely continue to press the EPA chooses to reviseissue at the applicable RCRA regulations, it must sign a notice taking final action related to the new regulation by July 2021.federal and state levels.
We currently own or lease numerous properties that have been used for the exploration and production of crude oil and natural gas for many years. If hydrocarbons or other wastes have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such properties, we could be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported or arranged for the disposal of the hazardous substances found at the site. IndividualsParties who are or
were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment or remediation to prevent future contamination and for damages to natural resources. UnderIn addition, under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We consistently utilize hydraulic fracturing in our crude oil and natural gas development programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions, but is also the subject of various other regulatory initiatives at the federal, state and local levels.
Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities.
In the past, Congress has considered proposed legislation to reduce emissions of GHGs. To date, Congress has not adopted any such significant legislation, but couldmay do so in the future. In November 2021, the U.S. House of Representatives passed H.R.5376, section 30114 of which would amend the Clean Air Act to impose a fee of $1,500 per ton of methane emitted above specified thresholds from onshore petroleum and natural gas production facilities, natural gas processing facilities, natural gas transmission and compression facilities, and onshore petroleum and natural gas gathering and boosting facilities, among other facilities. The U.S. Senate is currently considering H.R. 5376 and may adopt, modify, or eliminate the methane fee.
In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. In FebruarySince 2014, and November 2017, Colorado adoptedhas engaged in multiple rulemakings to adopt significant additional rules regulating methane emissions from the oil and gas sector.sector, and Colorado is expected to continue these efforts over the next several years.
The Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020 (the "Paris Agreement"“Paris Agreement”). In June 2017,April 2021, President TrumpBiden announced that the U.S.United States would initiate the formal processaim to withdraw from the Paris Agreement.cut its greenhouse gas emissions 50 percent to 52 percent below 2005 levels by 2030.
In November 2016, the BLM finalized rules to further regulate venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases.leases (the “2016 Rule”). The rules require2016 Rule required additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drains federal minerals. In September 2018, the BLM published a final rule that revisesrevised the 2016 rules.Rule (the “2018 Revised Rule”). The new rule,2018 Revised Rule, among other things, rescindsrescinded the 2016 ruleRule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair. The new rule2018 Revised Rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California.California, and in July 2020, the United States District Court for the Northern District of California vacated the BLM’s 2018 Revised Rule. However, in October 2020, the United States District Court for the District of Wyoming issued a ruling vacating the 2016 Rule, holding that the BLM exceeded its statutory authorities and acted arbitrarily. Both rulings have been appealed. The Spring 2021 Unified Agenda of Regulatory and Deregulatory Actions, published by the Office of Management and Budget’s Office of Information and Regulatory Affairs, identified a potential proposal by the BLM to update its existing rules governing the venting and flaring of natural gas (methane) from onshore Federal and Indian oil and gas leases. The BLM has not yet published such a proposed rule.
State-level rules applicable to our operations include regulations imposed by the CDPHE'sColorado Department of Public Health and Environment’s (“CDPHE”) Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping and reporting matters. In 2020, the COGCC relied in part on a previously-performed human health
The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control and Countermeasure (“SPCC”) requirements of the CWA require appropriate secondary containment, load out controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak.
The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species or that may attract migratory birds, bald eagles or golden eagles.
Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 (“OPA”) establishes requirements for preparation and EPA approval of Facility Response Plans and subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems.
In February 2018, the COGCC comprehensively amended its regulations for oil, gas and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection and other matters. In November 2019, the COGCC further amended its flowline regulations pursuant to SB 19-181 to impose additional requirements regarding flowline mapping, operational status, certification and abandonment, among other things.
We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016.
We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, stockholder communication policy, director nomination procedures, sustainability report and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference.
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 adversely affect the value of an investment in our common stock or other securities.
Risks Relating to the Global COVID-19 Pandemic
Our operations have been adversely affected as a result of the ongoing global COVID-19 pandemic. In particular, the pandemic contributed to a dramatic decrease in overall global economic activity generally, and crude oil prices in particular, in early 2020, and decreases in commodity prices can have a variety of negative effects on our business. While many of the adverse effects of the COVID-19 pandemic on our business have receded, it continues to be a unpredictable, particularly in the light of Delta, Omicron and other variants of concern, and additional adverse impacts on our business - including depressed crude oil, natural gas, and NGL prices, reductions in force, and reduced capital expenditures - could remain a risk for an indefinite period of time.
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.
Our revenue, profitability, cash flows and liquidityMany aspects of our business depend in large part upon the prices we receive for our crude oil, natural gas and NGLs. Changes inNGL prices, affect many aspects of our business, 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:
relatively minor •changes in regional, national or global supply and demand;
regional, national or global economic conditions and perceived trends, in those conditions;including supply and demand;
•geopolitical factors such asand events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries ("OPEC"(“OPEC”);, and global events, such as the ongoing COVID-19 pandemic; and
•regulatory changes.
The price of oil has historically been volatile, since mid-2014, with a high over $100 per barreldue in June 2014 to lows below $30 per barrel in 2016, in each case based on WTI prices, duerecent years to a combination of factors including increased U.S. supply and global economic concerns. In 2018,the past two years, oil prices have ranged from highs of over $70$80 per barrel to lows of less than $50approximately negative $40 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 likely result in reduced production and therefore reduced cash flow from operations, whichoperations. Reduced cash flow would in turn further limit our ability to make the capital expenditures necessary to replace our reserves and production.
In addition to factors generally affecting the price of crude oil, natural gas and NGLs, generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower thanvary 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 market forces. Differentials can be influenced by, amongmarkets and other things,forces, including local or regional supply and demand factors and thefactors; terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such ascontracts; investment decisions made by providers of midstream facilities and services, refineries and other industry participantsparticipants; and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally, or in production from particular basins,Widening differentials may result in widening differentials. materially and adversely impact our business.
We may be materiallyunable to return capital to our stockholders, and adversely impacted by widening differentialsthere is no assurance we will pay any dividends on our production and decreasing commodity prices.
The marketabilityor repurchase shares of our production is dependent upon transportationcommon stock in the future or at levels anticipated by our stockholders.
During each of the second, third and processing facilities, the capacityfourth quarters of 2021, our board of directors declared and operationpaid a quarterly cash dividend of which we do not control. Market conditions or operational impediments affecting midstream facilities$0.12 per share of common stock, and services could hinderin December 2021, our access to crude oil, natural gasboard declared and NGL markets, increase our costs or delay production. Our efforts to address midstream issues may not be successful.paid a special cash dividend of
$0.50 per share of common stock. Our ability to marketpay cash dividends in the future depends on, among other things, our production dependsliquidity, 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 to declare dividends at rates less than anticipated, either of which could reduce overall returns to our stockholders.
In February 2022, our board of directors has also approved an increase to our Stock Repurchase Program to acquire up to $1.25 billion of our outstanding common stock through December 31, 2023. This program is being implemented at the discretion of our board and may be extended, modified or discontinued at any time. We suspended the program in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities 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 and results of operations will be adversely affected. For example, in recent periods,March 2020 due to ongoing drilling activities by us and third parties and seasonal changesadverse market conditions but reinstated it in temperatures, our principal third-party provider in the Wattenberg Field for midstream facilities and services has experienced significantly increased gathering system pressures. The resulting capacity constraints have restricted our production in the area and reduced our revenue. Similarly, rapid production growth in the Permian Basin has strained theFebruary 2021.
available midstream infrastructure there with adverse effects on our operations. The use of alternative forms of transportation for oil production, such as trucks or rail, involves risks, including the risk that increased regulation could lead to increased costs or shortages of trucks or rail-cars. In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas and NGLs we produce.
We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks. For example:
Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties;
Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities;
Some upstream energy companies have sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments,Our overall capital return program may have the effect of reducing investment in midstream infrastructure; and
The possibility that new or amended regulations, including regulations that increase mandatory setbacks or enhance local control of oil and gas development, could result in severely curtailed drilling activities in Colorado may discourage investment in midstream facilities.
Like other producers, wechange from time to time, enter into volume commitmentsand 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 midstream providersrespect to dividends already declared) or repurchase any specific dollar amount or number of shares of common stock. A reduction, suspension or change in order to induce them to provide increased capacity. If our production falls below the level required under these agreements, wecapital return programs could behave a negative effect on our stock price.
We are subject to substantial penalties. We are currently not producing sufficient volumes to satisfy a volume commitment incomplex federal, state, local and other laws and regulations that adversely affect the Delaware Basin; although at current commodity prices we have been able to profitably satisfy our obligations under the agreement with volumes purchased from third parties, this may not continue to be the case.
We have pursued a varietycost and manner of strategies to alleviate some of the risks associated with the midstream services and facilities upon which we rely, including entering into facility expansion agreements with our primary midstream provider in the Wattenberg Field in 2017 and 2018. There can be no assurance that the strategies we pursue will be successful or adequate to meet our needs. For example, while we expect the midstream provider to commence operation of a new facility in the second quarter of 2019, it is not obligated to do so and it may delay or cancel the project entirely. In addition, the benefits to us of that facility may be less than we expect.
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. Environmental and other governmental 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 alleged noncompliance 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 pursuant to which we paid a fine and agreed to implement certain operational changes. The lawsuit claimed that we failed to operate and maintain certain equipment in compliance with applicable law. In addition, as a result of the SRC Acquisition, we are subject to the obligations and requirements of a 2018 Compliance Order on Consent (“COC”) entered into by SRC with CDPHE, applicable to certain SRC oil and gas production facilities we acquired from SRC. The COC resolved SRC’s alleged violations related to storage tank emissions and contains requirements similar to those contained in our consent decree.
The regulatory environment in which we operate also changes frequently, often through the imposition of new or more stringent environmental and other requirements.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:
From time•As discussed in Items 1 and 2, Business and Properties - Governmental Regulation, the COGCC completed extensive rulemaking hearings in November 2020 which resulted in the adoption of new requirements for setbacks, permitting, siting cumulative and surface impacts, asset transfers, venting and flaring, and remediation. The implementation of the final rules could have a significant adverse effect on our unpermitted locations and therefore on our future inventory and reserves. For example, the new planning and permitting process associated with long term, landscape level development (referred to time ballot initiatives haveas Comprehensive Area Plans) has not yet been proposedsuccessfully utilized by any operators in Colorado that would adversely affect our operations. For example, Proposition 112, which was includeddue to a lengthy, highly technical, and resource-intensive approval process. The COGCC is still in the process of issuing guidance and direction regarding the new requirements, and we cannot predict the impact of these requirements on the ballot for the November 2018 election in Colorado but was defeated at the polls, would have amended the Colorado Oil and Gas Conservation Act to, among other things, require all new oil and gas development not on federal land to be located at least 2,500 feet away from any occupied structure or broadly defined “vulnerable area”. If enacted, Proposition 112 would have effectively prohibited the vast majority of our planned future drilling activities in Colorado and would therefore have made it impossible to pursue our current development plans. Despite the defeat of Proposition 112, it is likely that similar proposals to increase setbacks, or other proposals to enhance local control of oil and gas development or otherwise restrict our ability to operate or increase our costs, will be made in future years, either by ballot initiative or by legislation. Similar proposals may also be made in other states.
Substantially all of our drilling activities involve the use of hydraulic fracturing, and proposals are made from time to time at the federal, state and local levels to further regulate, or to ban, hydraulic fracturing practices. Additional laws or regulations regarding hydraulic fracturing could, among other things, increase our costs, reduce our inventory of economically viable drilling locations and reduce our reserves.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 greenhouse gases ("GHGs").GHGs. For example, the EPA has made findings and issued regulations that require us to establish and
report an inventory of
greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. In addition, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline (although President Trump subsequently announced that the U.S. is withdrawing from the Paris Agreement). 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.
•Proposals are made from time to time to amend U.S. federal and state tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling.
•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.
See Items 1Increasing scrutiny and 2, Business and Properties - Governmental Regulation for a summary of certain laws and regulations that currently applychanging expectations from stakeholders with respect to us. Any of such laws and regulations could be amended, andour ESG practices may impose additional costs on us or expose us to new laws or regulations could be implemented, in a way that adversely affects our operations.additional risks.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage 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 within the spacing 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. In 2019, we expect that we will allow 35 percent of our net leaseholdsPublicly traded companies, both in the Delaware Basin to expire based on our current drilling plan, and we incurred an impairment charge in the fourth quarter of 2018 relating to these anticipated expirations. Unexpected lease expirations could also occur if our actual drilling activities differ materially from our current expectations, and this could result in further impairment charges. The risk of lease expiration is greater at times and in areas where the pace of our exploration and development activity slows. Our ability to drill and develop the locations necessary to maintain our leases depends on a number of uncertainties, including oil and natural gas prices,industry and otherwise, are facing increased scrutiny from stakeholders of our practices related to ESG. Attention on these issues may come from stakeholders ranging from the availabilitySEC to local governments to institutional investors, and cost of capital, drilling and production costs, availability of drilling services and equipment, drillingthese stakeholders may seek certain outcomes or results gathering system and pipeline transportation constraints,on issues they perceive to be material. This could result in reduced access to and availability of water sourcing and distribution systems, regulatory approvalscapital, shareholder proposals and other factors.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.
We have experienced increased pressure from our stakeholders focused on climate change to reduce our carbon footprint and prioritize sustainable energy practices. Our stakeholders may also require us to implement additional ESG procedures or standards in order to meet their expectations for continued investment.
We have publicly communicated commitments related to reductions in methane and greenhouse gas emissions and flaring. It is possible that our stakeholders may not be satisfied with these commitments or our progress towards them. This, or a failure to meet our targets, could lead to decreased access to capital or have a negative impact on our stock price.
Additionally, public sentiment related to the oil and gas industry may be affected by uncertainty or instability resulting from climate change, political leadership changes and subsequent policies, changes in social views regarding the importance of fossil fuels, concerns about environmental impact and investor expectations, resulting in decreased demand for our products. This could have a significant financial and operational impact on our business.
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 disproportionately exposed to the effect of any regional events, including:
fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in the area;
including natural disasters, such as the flooding that occurred in northern Colorado in September 2013;government regulations and midstream interruptions.
restrictive governmental regulations; and
curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services and any resulting delays or interruptions of production from existing or planned new wells.
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 disproportionately severe 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, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field and the Delaware Basin, the demand for, and cost of, drilling rigs, equipment, supplies, chemicals, personnel and oilfield services often increase as well. Shortagesa result of numerous factors including increases in exploration and production activity, supply chain problems, and labor shortages. Any shortages or the high cost of drilling rigs, equipment, supplies, chemicals, personnel or oilfield servicesincreased 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.
Certain All of the producing properties and reserves we acquired in the SRC Acquisition are located in the Wattenberg Field. As a result, the transaction increased the risks we face with respect to the geographic concentration of our propertiesproperties.
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 depressed commodity prices that ultimately reduce investment in new midstream facilities, new or amended government regulations curtailing drilling activities in Colorado which could discourage investment in midstream facilities, protests over construction of new pipelines and facilities, weather, fire, or other reasons, and could negatively affect our results of operations. In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas and NGLs we produce.
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 land use restrictions, whichsubstantial 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 limit the mannerresult in which we conduct our business.
Certainsubstantial lease renewal costs or, if renewal is not feasible, loss of our properties are subjectlease 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 land use restrictions, including city ordinances, whichrenew 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 limitoccur 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 manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible usespace of our facilities as well asexploration 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 manner in which we producelocations necessary to maintain our leases depends on a number of factors, including oil and natural gas prices, the availability and may restrict or prohibitcost of capital, drilling in general. Theand production costs, we incuravailability of drilling services and equipment, drilling results, gathering system and pipeline transportation constraints, access to comply with such restrictions may be significant, and we may experience delays or curtailment in the pursuitavailability of development activitieswater sourcing and may be precluded from drilling wells in some areas.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.
It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform record title examinations before we acquire oil and gas leases and related interests. The existence of a material title deficiency can renderdecrease a lease worthlesslease’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.
We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business.
Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental 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. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These costs may put us at a competitive disadvantage compared to larger companies in the industry which can more easily capture economies of scale with respect to compliance. A summary of certain laws and regulations that apply to us is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation.
In June 2017, the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, filed a complaint against us, claiming that we failed to operate and maintain certain condensate collection equipment at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. If we materially fail to comply with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding this litigation.
A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Our ability to obtain the permits needed to pursue our development plans may be impacted by a variety of factors, including opposition by landowners or interest groups. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable or unexpected conditions or costs could have a material adverse effect on our ability to explore or develop our properties.
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. This increased scrutiny applied to our Colorado operations as well. For example, in November 2020, the COGCC adopted various new requirements on the underground injection of fluid waste. In December 2021, the Texas Railroad Commission suspended the deep injection of wastewater in the Gardendale Seismic Response Area.
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.charges in the future. For example, we incurred impairment charges in a number of recent periods, including charges of $882.4 million and $38.5 million in 2020 and 2019, respectively, to write down assets. Similarly, the significant decline in commodity pricing during 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 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 is calculated. However, abasin. A significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. We have incurred impairment charges in a number of recent periods, including charges of $458.4 million and $285.9 million in 2018 and 2017, respectively, to write down assets and $75.1 million to impair goodwill associated with our acquisition in the Delaware Basin in 2017. Similar charges could occur in the future.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 maywill materially affect the quantities and present value of our reserves.
Calculating reserves for
The process of estimating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and NGLs requires subjectiveeconomic 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 remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levelsreserve and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independentevaluations, management utilizes independent petroleum engineers prepare our estimates of crude oil, natural gas and NGLs reserves using pricing, production, cost, tax and other information that we provide.engineers. The reserve estimates are based on assumptions regarding commodity prices, production levels and operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to actual results could greatly affect:
the economically recoverableAs a result, estimated quantities of crude oil, natural gasproved reserves and NGLs attributable to any particular groupprojections of properties;
future depreciation, depletion and amortization (“DD&A”)production rates and amounts;
impairments in the value of our assets;
the classifications of reserves based on risk of recovery;
estimates of future net cash flows;
timing of our capital expenditures;development expenditures may be inaccurate and
the amount of funds available for us to borrow under our revolving credit facility.
Some of our revisions in existing reserve estimates must be made with limited production histories, which renders these estimates less reliable than those based on longer production histories. Further, reserveoccur.
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, sincein part because they will not be produced under the same economic conditions as are used for the reserve calculations.
In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated withYou should not assume that the recoverable quantities of hydrocarbons.
At December 31, 2018, approximately 67 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $4.4 billion during the five years ending December 31, 2023, as estimated in the calculation of the standardized measure of oil and gas activity. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade any PUDs that are not developed within this five-year time frame.
The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as 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 prior year’saverage of the previous 12-months’ first day of the month 12-month average crude oilprices and natural gas index prices. However,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 actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production,development expenditures, the amountrate and timing of future development costs, the supply of and demand for crude oil, natural gas and NGLsproduction and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties willtaxes. Significant variances could materially affect the timingestimated quantities and present value of actual future net cash flows from proved reserves shown in this Annual Report on Form 10-K and thus their actual present value.cause potential impairment charges. 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. The rate of decline may change over time and may exceed our estimates. 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.
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 servicesrigs, and equipment;equipment, supplies, chemicals, personnel and oilfield services;
•drilling results;
•lease expirations or limitations as to depth;
•midstream constraints;
•access to and availability of water sourcing and distribution systems;
•regulatory approvals; and
•other factors.
Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Conversely, a decrease in well density could result in fewer locations in an area but possibly increased production performance on a per-well basis. For example, after examining well performance and other factors, we recently determined that our current Delaware Basin position supports fewer wells per unit than previously assumed. Accordingly, as of December 31, 2021, our estimated well locations for our current Delaware Basin position decreased from 135 to 65.
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 in order to facilitate exploration.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 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 orand 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 accelerated thecontinued a steady pace of our development activities in the Wattenberg Field over the past several years, and thiswhile the SRC Acquisition increased our inventory, continued development has reduced our related inventory of drilling locations. In addition, our Wattenberg Field inventory was further reduced by recent acreage exchange transactions in which we received, among other things, increased working interests in certain locations in exchange for our right to develop other 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 expiration issuesexpirations (as to acreage and/or depths) and our continued analysis of geologic issueschallenges in certain areas. For example, as noted above, we recently reduced our estimated number of locations in the Delaware Basin due to geological issues.
The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities and productive wells may be less successful than we expect.
A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists 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. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. 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 must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging and lease costs associated with the prospect.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"“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. If we drill a dry hole or unprofitable well on a current or future prospect, or if drilling or completion costs increase, the profitability of our operations will decline and the value of our properties will likely be reduced. Exploratory drilling is typically subject to substantially greater risk than development drilling. 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:
unusual•pressures or unexpectedirregularities in geological formations;
pressures;•fires;
fires;•floods, winter storms and other natural disasters and adverse weather conditions;
floods;
•loss of well control;
•loss of drilling fluid circulation;
title problems;
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;
•unanticipated environmental liabilities; and
•compliance with environmental and other governmental requirements; andrequirements.
adverse weather conditions.
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 or loss of wells 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. For example,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 uninsurable or uninsured risks or for amounts in excess of existingwhich we have no effective insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third partythird-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 have transitioned to the use of 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 simultaneously. While we believe that we will be better served by using multi-well pads with longer lateral wells, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program.
The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from our crude oil, natural gas and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage.
Seasonal weather conditions and lease stipulations can adversely affect our operations.
Seasonal weather conditions and lease stipulations designed to prohibit or limit operations during crop-growing seasons and to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or
prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, equipment, supplies, chemicals, personnel, and oilfield services, which may lead to additional or increased costs or periodic shortages. These constraints, and the resulting high costs or shortages, could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, extreme temperatures during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows.
We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues.
We operate approximately 84 percent of the wells in which we own an interest. If we do not operate a property, we do not have control over normal operating procedures, expenditures or future development of the property. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells and use of technology. The failure of an operator to conduct drilling activities properly, or its breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks may be heightened during periods of depressed commodity prices as operators may propose activities that we believe to be economically unattractive, leading us to incur non-consent penalties. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production and related matters.
We participate in oil and gas leasesoperations with third parties who may not be able to fulfill their commitments to our projects.
We frequently own less than all of the working interest in the oil and gas leases and/or wells on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities, arising from the actions of the other owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of our project partners does not pay its share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover the costs from the partner. This could materially adversely affect our financial position.
We may not be able to keep pace with technological developments in our industry.
Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced technology, our business, financial condition and results of operations could be materially adversely affected.
Competition in our industry is intense, which may adversely affect our ability to succeed.
Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, 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. 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.
A failure to complete successful acquisitions would limit our growth.ability to replace our reserves and impact our financial condition.
Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete asset exchanges and other acquisitions that allow us to increase our working interests in particular properties. When attractive opportunities arise, acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. Ifopportunities, and if we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions on acceptable terms, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations.
Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties.
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 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.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.
Complications with the design or implementation of our new enterprise resource planning system could adversely impact our business and operations.
We rely extensively on information systems and technology to manage our business and summarize operating results. We are in the process of implementing a new ERP system. This ERP system will replace our existing operating and financial systems. The ERP system is designed to enhance the maintenance of our financial records, improve operational functionality and provide timely information to our management team related to the operation of the business. The ERP system implementation process has required, and will continue to require, the investment of significant personnel and financial resources. We may not be able to successfully implement the ERP system without experiencing delays, increased costs and other difficulties. If we are unable to successfully design and implement the new ERP system as planned, our financial position, results of operations and cash flows could be negatively impacted. Additionally, if we do not effectively implement the ERP system as planned or the ERP system does not operate as intended, the effectiveness of our internal control over financial reporting could be adversely affected or our ability to assess those controls adequately could be delayed.
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 recent years,January 2021, a purported class action lawsuit was filed against us by a royalty owner alleging we have been subjectimproperly deducting certain post-production costs from the owner’s oil royalty payments. While we intend to lawsuits regarding royalty practices and payments and matters relating to certain of our affiliated partnerships. As discussed invigorously defend this suit, the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report, we are the subject of a recently filed lawsuit relating to our two remaining affiliated partnerships and are currently involved in a fiduciary duty lawsuit regarding our environmental compliance programs. 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 a proceedinglegal 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 our legal proceedings can be found in the footnote titled Commitments and Contingencies - Litigation andItem 3. Legal Items to our consolidated financial statements Proceedings included elsewhere in this report.
Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions.
We face various security threats, including attempts by third parties to gain unauthorized access to, or control of, competitive information or to render data or systems corrupted or unusable; threats to the safety of our employees; threats to the security of our infrastructure or third partythird-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 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 business partners, including vendors, service providers, operating partners, purchasers of our production and financial institutions, are also dependent on digital technology. A vulnerability in the cybersecurity of one or more of our vendors could facilitate an attack on our systems.
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. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. AlthoughTo our knowledge, we have not suffered material losses related to cyber-attacks to date, ifdate; 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. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.
The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. An economy-wide transition to lower GHG energy sources could have a variety of adverse effects on our operations and financial results.
Many scientists believehave shown that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth'sEarth’s atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme weather event that negatively impacted our operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance.
Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our production could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
Efforts by governments, international bodies, businesses and consumers to reduce GHGs and otherwise mitigate the effects of climate change are ongoing. The nature of these efforts and their effects on our business are inherently unpredictable and subject to change. Certain regulatory responses to climate change issues are discussed above under the heading “We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business. Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us” and in Items 1 and 2 - Business and Properties - Governmental Regulation. However, actions taken by private parties in anticipation of, or to facilitate, a transition to a lower-GHG economy will affect us as well. For example, our cost of capital may increase if lenders or other market participants decline to invest in fossil fuel-related companies for regulatory or reputational reasons. Similarly, increased demand for low-carbon or renewable energy sources from consumers could reduce the demand for, and the price of, the products we produce. Technological changes, such as developments in renewable energy and low-carbon transportation, could also adversely affect demand for our products.
Risks Relating to Financial Matters
Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. Lender hesitancy to offer financing to our industry may increase this risk.
Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated byfrom 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.
Additionally, due to recent default rates in the oil and gas industry and other factors, 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.
We have a substantial amount of debt and theThe cost of servicing, and risks related to refinancing, thatour debt could adversely affect our business. Those risks could increase if we incur more debt.
We have
As of December 31, 2021, we had a substantial amounttotal long-term debt of indebtedness outstanding. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs.
$950 million. Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Ourcash, 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. We cannot assure you that our business will generate sufficient cash flow from operations, or that sufficient future borrowings will be available to us under our revolving credit facility or otherwise, to fund our liquidity needs.
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, selling assets, reducing our capital expenditures, selling assets, refinancing all or a portion of our existing debt or obtaining additional financing. These alternative measuresWe may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of our debt agreements could restrict us from implementing some of these alternatives.
In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore,complete any proceeds that we could realize from any dispositions may not be adequatesuch steps on satisfactory terms. Any ability to meetgenerate sufficient cash flows to satisfy our debt service obligations then due.or contractual commitments, or to refinance our debt on commercially reasonable terms, could materially and adversely affect our financial condition and results of operations.
Covenants in our debt agreements currently impose, and future financing agreements may impose, significant 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 salesales and leaseback transactions;
•merge or consolidate; and
restrict dividends or other payments from restricted subsidiaries;
sell equity interests of restricted subsidiaries; 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 may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that subject us to additional restrictive covenants.
Our revolving credit facility has substantial restrictions and financial covenants andbusiness. In addition, our ability to comply with thosecovenants and restrictions and covenants is uncertain. Our lenders can unilaterally reducein our borrowing availability based on anticipated commodity prices.
We expect to depend on our revolving credit facility for part of our future capital needs. The terms of the credit agreement require us to comply with certain financial covenants. Our ability to comply with these covenantsdebt 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 thethese restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under thoseour 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 could cause all of our existing indebtednessa cross-default or cross-acceleration provision applies, to become immediatelybe due and payable.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.
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 can be expected tomay 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.
If we are unable to comply with the restrictions and covenants in our debt agreements, the resulting default could lead to an acceleration of payment of funds that we have borrowed and we may not have or be able to obtain the funds necessary to repay those amounts.
Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our 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. In addition, the default could result in a cross-default under other debt agreements. If our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs and no waiver is obtained, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease.
Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above.
We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we and our subsidiaries now face.
Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period in which they are determined to be non-productive, which reduces our net income in such periods.
We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. The costs of unsuccessful exploratory wells could result in a significant reduction in our profitability in periods in which the costs are required to be expensed.
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 and for natural gas purchases and sales by our marketing subsidiary 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, 2018,2021, we had hedged a total of 19.622.2 MMBbls of crude oil for 2022 to 2024 and 26.4 Bcf102.5 MMBtu of natural gas through 2020.for 2022 and 2023. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices.
Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income.
Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.
The occurrence of a significant accident or other event that is not fully covered by insurance, not properly or timely noticed to our carrier, or that is in excess of our insurance coverage, could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. In addition, pollution and environmental risks are generally not fully insurable.
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 could trigger declines in the price of our common stock, including among others:
changes in production volumes, worldwide demand and prices for crude oil and natural gas;
inability to hedge future production at the same pricing level as our current or prior hedges;
gas, regulatory developments, and changes in securities analysts’ estimates of our financial performance;
fluctuations in stockperformance could negatively impact the market prices and volumes, particularly among securities of energy companies;
changes in market valuations and valuation multiples of similar companies;
changes in interest rates;
announcements regarding adverse timing or lack of success in discovering, acquiring, developing and producing crude oil and natural gas resources;
announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures or capital commitments;
decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate;
operating results that fall below market expectations or variations in our quarterly operating results;
loss of a major customer;
loss of a relationship with a partner;
the occurrence and severity of environmental events and governmental and other third-party responses to the events; or
additions or departures of key personnel.
External events, such as news concerning economic conditions, counterparties to our natural gas or crude oil derivatives arrangements, changes in government regulations impacting the crude oil and natural gas exploration and production industry or the movement of capital into or out of our industry, are also likely to affect the price of our common stock, regardless of our operating performance. For example, there have been recent efforts by some investment advisers, sovereign wealth funds, public pension funds, universities and other investment groups to divest themselves from investments
in companies involved in fossil fuel extraction, and these efforts could reduce the trading prices of our securities. Similarly, our stock price could be adversely affected by changes in the way that analysts and investors assess the geological and economic characteristics of the basins in which we operate. Furthermore, generalstock. General market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock.also have a similar negative impact. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes.
Risks Relating to Pending Great Western Acquisition
If completed, the Great Western Acquisition may not achieve its intended results and may result in us assuming unanticipated liabilities. To date, we have conducted only limited diligence regarding the assets and liabilities we would assume in the transaction.
We entered into the Purchase Agreement with the expectation that the Great Western Acquisition would result in various benefits, growth opportunities and synergies. Achieving the anticipated benefits of the transaction is subject to a number of risks and uncertainties. For example, under the Purchase Agreement, we have the opportunity to conduct customary environmental and title due diligence following the execution of the agreement, but our diligence efforts to date have been limited. As a result, we may discover title defects or adverse environmental or other conditions of which we are currently unaware. Environmental, title and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We would assume substantially all of the liabilities associated with the acquired properties and would be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure you that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant.
As with other acquisitions, the success of the Great Western Acquisition depends on, among other things, the accuracy of our assessment of the reserves and drilling locations associated with the acquired properties, future oil, NGL and natural gas prices and operating costs and various other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price for the acquisition from the sale of production from the property or recognize an acceptable return from such sales.
The reserves, production and drilling locations estimates with respect to the properties to be acquired in the Great Western Acquisition may differ materially from the actual amounts.
Our certificateestimates of incorporation, bylawsthe reserves, production and Delaware law contain provisionsdrilling locations associated with the properties to be acquired in the Great Western Acquisition are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines. Such analysis is based, in significant part, on data provided by the sellers. We cannot assure you that these estimates are accurate. After such data is further reviewed by us and our independent engineers, the actual reserves, production and number of viable drilling locations may differ materially from the amounts we have estimated.
The transactions contemplated by the Purchase Agreement are subject to conditions that may not be satisfied on a timely basis or at all. Failure to complete the transactions contemplated by the Purchase Agreement could have an anti-takeover effectmaterial and adverse effects on us.
Completion of the Great Western Acquisition is subject to a number of conditions, including the accuracy of the parties’ representations in the Purchase Agreement and the receipt of certain governmental approvals. Such conditions, some of which are beyond our control, may delay, defernot be satisfied or preventwaived in a tender offertimely manner or takeover attempt,at all and therefore make the completion and timing of the completion of the Great Western Acquisition uncertain. In addition, the Purchase Agreement contains certain termination rights for both Great Western and us, which if exercised will also result in the Great Western Acquisition not being consummated. Furthermore, the governmental authorities from which the federal regulatory approvals are required may impose conditions on the completion of the Great Western Acquisition or require changes to the terms of the acquisition or the Purchase Agreement.
If the transactions contemplated by the Purchase Agreement are not completed, our business may be adversely affectaffected and, without realizing any of the benefits of having completed the Great Western Acquisition, we will be subject to a number of risks, including the following: we will be required to pay our costs relating to the Great Western Acquisition, such as legal, accounting, and financial advisory fees; time and resources committed by our management to matters relating to the Great Western Acquisition could otherwise have been devoted to pursuing other beneficial opportunities; and the market price of our common stock.
Our certificate of incorporation and bylaws, and certain provisions of Delaware law, may have anti-takeover effects.
For example, our certificate of incorporation authorizes our board of directors to issue preferred stock without shareholder approval. If our board of directors elects to issue preferred stock, it could be more difficult forimpacted to the extent that the current market price reflects a thirdmarket assumption that the Great Western Acquisition will be completed. In addition, if the Purchase Agreement is terminated and the Board seeks another acquisition, we cannot be certain that we will be able to find a party willing to acquireenter into a transaction as attractive to us includingas the Great Western Acquisition.
We will be subject to business uncertainties while the Great Western Acquisition is pending, which could adversely affect our business.
It is possible that certain persons with whom we have a business relationship may delay certain business decisions relating to us, or seek to terminate, change or renegotiate their relationships with us, in circumstances whereconnection with the acquisition is supported bypendency of the holders of a majorityGreat WesternAcquisition. This could negatively affect our revenues, earnings and cash flows, as well as the market price of our stock. In addition, other provisionscommon stock, regardless of whether the Great WesternAcquisition is completed. Also, our certificate of incorporation, bylawsability to attract, retain and Delaware law could make it more difficult for a third party to acquire control of us againstmotivate employees may be impaired until the wishes of our board of directors, including:
the organization of our board of directors as a classified board, which provides that approximately one-third of our directors are subject to election each year;
bylaw provisions that require advance notice of some types of shareholder proposals;Great WesternAcquisition is completed and
Delaware law provisions which prohibit us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years fromtime thereafter as current and prospective employees may experience uncertainty about their roles within the date this person became an interested stockholder, unless various conditions are met.combined company following the transaction.
In addition, shareholder activism in our industry has been increasing. Ifunder the terms of the Purchase Agreement, we are unablesubject to work productively with activist or other shareholders, any resulting disagreements or disputes could require substantial management time and attention and could adversely affectcertain restrictions on the conduct of our resultsbusiness prior to the completion of operations.
Derivatives legislation and regulation couldthe Great WesternAcquisition, which may adversely affect our ability to hedge crudeexecute certain of our business strategies. Such limitations could negatively affect our business and operations prior to the completion of the Great WesternAcquisition.
Even if the Great Western Acquisition is completed, we may not achieve the anticipated benefits and the Great Western Acquisition may disrupt our current plans or operations.
The success of the Great WesternAcquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and Great Western’s businesses, and there can be no assurance that we will be able to successfully integrate Great Westernor otherwise realize the anticipated benefits of the Great WesternAcquisition. Difficulties in integrating Great Westerninto our company may result in us performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:
•the inability to successfully integrate Great Western into PDC in a manner that permits us to achieve the full cost savings or operating synergies anticipated from the Great Western Acquisition;
•complexities associated with managing a larger, more complex, integrated business;
•the disruption or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.
We are expected to incur significant transaction costs in connection with the Great Western Acquisition, which may be in excess of those we currently anticipate.
We expect to incur a number of non-recurring costs associated with negotiating and completing the Great WesternAcquisition, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial and, in many cases, will be borne by us whether or not the Great WesternAcquisition is completed. A substantial majority of our non-recurring expenses will consist of transaction costs related to the Great WesternAcquisition and include, among others, fees paid to financial, legal, accounting and other advisors. We will also incur transaction costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and other employment-related costs. We will continue to assess the magnitude of these costs, and we may incur additional unanticipated costs. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not offset integration-related costs and achieve a net benefit in the near term or at all. The costs described above and any unanticipated costs and expenses, many of which will be borne by us even if the Great WesternAcquisition is not completed, could have an adverse effect on our financial condition and operating results.
After the Great Western Acquisition is completed, PDC will be proportionally more exposed to regulatory risks associated with oil and gas operations in Colorado and other risks associated with a more geographically-concentrated asset base.
PDC's principal assets in terms of production and reserves are located in the Wattenberg Field located within the Denver-Julesburg Basin of Colorado, but we also have a significant acreage position in the Delaware Basin in Texas. During 2021, 87 percent of PDC's production came from its assets in Colorado and 13 percent came from its assets in Texas. All of Great Western’s properties, and all of its current production and reserves, are located in Colorado. Various new regulatory requirements applicable to oil and natural gas prices and increase our costs and adversely affect our profitability.operations in Colorado have been proposed or adopted in recent years as described elsewhere in this report.
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following:
The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portionpercentage of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in futurePDC's combined production and reserves.
If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.
Our derivatives counterparties are subject to significant requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterpartieslocated in the marketWattenberg Field following the Great Western Acquisition will proportionately increase PDC's exposure to risks associated with operating in a more concentrated geographic area, including Colorado-specific regulatory and increased counterparty costs will be passed on to us.midstream risks as described elsewhere in this section.
The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
Information regarding our legal proceedings can be found in the footnote titled Note 13 - Commitments and Contingencies- Litigation and Legal Items included in Item 8.Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report.
Environmental.Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2021 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses in the consolidated balance sheets.
Following a self-audit of final reclamation activities associated with site retirements, we formally disclosed identified deficiencies to the Colorado Oil and Gas Conservation Commission (“COGCC”) in December 2019. In August 2020, the COGCC issued a Notice of Alleged Violation (“NOAV”) citing a failure to comply with reclamation requirements at multiple locations. To resolve the alleged violations in July of 2021, the COGCC and PDC jointly agreed to an Administrative Order by Consent (“AOC”) which assessed penalties in the amount of approximately $500,000, with approximately $350,000 suspended pending PDC meeting certain conditions of the AOC. We are implementing programs to meet the requirements of the AOC and correct any identified deficiencies.
On August 30, 2021 and November 1, 2021, the COGCC issued us NOAVs related to the timing of wellhead pressure test reporting for certain wells in the Wattenberg Field. Pursuant to the NOAVs, we have conducted and submitted a comprehensive audit of our wellhead pressure testing and reporting processes. We are actively updating our processes to mitigate against the possibility of the alleged violations occurring in the future. We do not anticipate a material effect on our financial condition or results of operations. However, the potential penalties may exceed $300,000.
Commencing in early 2020, we conducted a comprehensive air quality compliance audit over the facilities acquired in
the SRC Acquisition. Through the self-audit process, we identified certain deficiencies and disclosed them to the Colorado Department of Public Health and Environment (“CDPHE”) and the U.S. Environmental Protection Agency (“EPA”) in July 2021. We do not believe potential penalties and other expenditures associated with the deficiencies identified will have a
material effect on our financial condition or results of operations, but such penalties may exceed $300,000.
Clean Air Act Agreement and Related Consent Decree.We continue to implement the requirements of a consent decree entered into with the CDPHE in 2017, as well as a revised compliance order on consent, the latter of which was modified by the CDPHE after the SRC Acquisition was completed. Per the terms of the agreements, we will apply for termination in early 2022. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $300,000.
Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'SREGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDERSSTOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE.
“PDCE”. As of February 15, 2019,2022, we had approximately 476386 stockholders of record. Since inception, no cash dividends have been declared on
In May 2021, our board of directors approved the Company’s quarterly dividend program and we announced the initiation of a quarterly dividend in the amount of $0.12 per share of our common stock. CashWe declared and paid an aggregate amount of $0.86 per share of our common stock during 2021, which included a special dividend of $0.50 per share of our common stock declared and paid in the fourth quarter of 2021. The dividend program and payment of any future dividends are restricted underthereunder will be made at the termsdiscretion of our board of directors and will depend on our results of operations, cash flows, financial position and capital requirements, as well as general business conditions, legal, tax and regulatory restrictions and other factors our board of directors deems relevant at the time it determines to declare such dividends.
Additionally, our revolving credit facility, as well as the indentures governing our 6.125% senior notes due September 15, 2024 (the "2024 Senior Notes")Notes and our 5.75% senior notes due May 15, 2026 (the "2026“2026 Senior Notes"Notes”), the terms of which are summarized in Note 10 - Long-term Debt in Item 8. Financial Statements and Supplementary Data included elsewhere in this report, include restrictions based on our leverage and other certain financial metrics that could impact our ability to pay cash dividends. As we presently intend to continue a policy of using retained earnings fordeclare dividends in the expansion of our business.future, we will monitor compliance with such restrictions.
The following table presents information about our purchases of our common stock during the three monthsyear ended December 31, 2018:2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased (1) (2) | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1) | | Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions) |
| January | | 28,831 | | | $ | 23.27 | | | — | | | $ | 346.8 | |
| February | | 53,401 | | | 32.25 | | | 2,289 | | | 346.7 | |
| March | | 596,388 | | | 36.99 | | | 595,460 | | | 324.7 | |
| April | | 345,614 | | | 35.36 | | | 255,268 | | | 315.7 | |
| May | | 211,555 | | | 40.14 | | | 210,310 | | | 307.3 | |
| June | | 201,576 | | | 46.39 | | | 196,070 | | | 298.2 | |
| July | | 283,191 | | | 41.10 | | | 280,000 | | | 286.7 | |
| August | | 915,811 | | | 39.30 | | | 915,000 | | | 250.7 | |
| September | | 281,058 | | | 43.47 | | | 281,058 | | | 238.5 | |
| October | | 54,680 | | | 45.54 | | | 50,000 | | | 236.2 | |
| November | | 275,200 | | | 54.48 | | | 275,200 | | | 221.2 | |
| December | | 692,800 | | | 48.95 | | | 692,800 | | | 187.3 | |
| Total purchases | | 3,940,105 | | | $ | 42.16 | | | 3,753,455 | | | $ | 187.3 | |
_____________
(1)In April 2019, our board of directors approved a program to acquire up to $200.0 million of our outstanding common stock and in August 2019, effective with the closing of the SRC Acquisition, increased such amount to $525.0 million (the “Stock Repurchase Program”). The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by our board of directors at any time. We reinstated our Stock Repurchase Program in late February 2021 and in February 2022, our board of directors increased the size of the program to $1.25 billion and extended it through December 31, 2023.
(2)Purchases outside of the Stock Repurchase Program represent shares withheld from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. The withheld shares are not considered common stock repurchased under the Stock Repurchase Program.
|
| | | | | | | |
| Period | | Total Number of Shares Purchased (1) | | Average Price Paid per Share |
| | | | | |
| October 1 - 31, 2018 | | 5,160 |
| | $ | 47.20 |
|
| November 1 - 30, 2018 | | — |
| | — |
|
| December 1 - 31, 2018 | | 7,022 |
| | 29.00 |
|
| Total fourth quarter 2018 purchases | | 12,182 |
| | 36.71 |
|
__________
| |
(1) | Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. |
STOCKHOLDER PERFORMANCE GRAPH
The following performance graph and related information shall deemed to be furnished, but not filed with the SEC.
The graph below comparesmatches the cumulative 5-Year total return of our common stock over the five-year period ended December 31, 2018 with the cumulative total returns for the same period forof the Standard and Poor's ("Poor’s (“S&P"&P”) 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted compositecustomized peer group of 233 crude petroleum and natural gas126 companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2013,2016 and tracks it through December 31, 2021, in the S&P 500 Index and in the SIC Indexcustomized peer group on the same date. The results shown in the graph below are not necessarily indicative of future stock price performance.
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
Among PDC Energy, Inc., the S&P 500 Index,
and a Peer Group
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
| PDC Energy | 100.00 | | 71.01 | | 41.00 | | 36.06 | | 28.29 | | 69.20 |
| S&P 500 | 100.00 | | 121.83 | | 116.49 | | 153.17 | | 181.35 | | 233.41 |
| Peer Group | 100.00 | | 97.71 | | 72.90 | | 66.54 | | 40.68 | | 81.79 |
ITEM 6. SELECTED FINANCIAL DATA[RESERVED]
This Item has been omitted as we are no longer required to provide five years of selected financial data.
|
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended/As of December 31, |
| | 2018 | | 2017 | | 2016 (1) | | 2015 | | 2014 (2) |
| | (in millions, except per share data and as noted) |
| Statement of Operations (From Continuing Operations): | | | | | | | | | | |
| Crude oil, natural gas and NGLs sales | | $ | 1,390.0 |
| | $ | 913.1 |
| | $ | 497.4 |
| | $ | 378.7 |
| | $ | 471.4 |
|
| Commodity price risk management gain (loss), net | | 145.2 |
| | (3.9 | ) | | (125.7 | ) | | 203.2 |
| | 310.3 |
|
| Total revenues | | 1,548.7 |
| | 921.6 |
| | 382.9 |
| | 595.3 |
| | 856.2 |
|
| Income (loss) from continuing operations | | 2.0 |
| | (127.5 | ) | | (245.9 | ) | | (68.3 | ) | | 107.3 |
|
| | | | | | | | | | |
| Earnings per share from continuing operations: | | | | | | | | | | |
| Basic | | $ | 0.03 |
| | $ | (1.94 | ) | | $ | (5.01 | ) | | $ | (1.74 | ) | | $ | 3.00 |
|
| Diluted | | 0.03 |
| | (1.94 | ) | | (5.01 | ) | | (1.74 | ) | | 2.93 |
|
| | | | | | | | | | |
| Statement of Cash Flows: | | | | | | | | | | |
| Net cash flows from: | | | | | | | | | | |
| Operating activities | | $ | 889.3 |
| | $ | 597.8 |
| | $ | 486.3 |
| | $ | 411.1 |
| | $ | 236.7 |
|
| Investing activities | | (1,087.9 | ) | | (717.0 | ) | | (1,509.1 | ) | | (604.3 | ) | | (474.1 | ) |
| Financing activities | | 18.1 |
| | 65.0 |
| | 1,266.1 |
| | 178.0 |
| | 60.3 |
|
| Capital expenditures from development of crude oil and natural gas properties (3) | | (946.4 | ) | | (737.2 | ) | | (436.9 | ) | | (599.5 | ) | | (623.8 | ) |
| Acquisition of crude oil and natural gas properties | | (180.0 | ) | | (15.6 | ) | | (1,073.7 | ) | | — |
| | — |
|
| | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | |
| Total assets | | $ | 4,544.1 |
| | $ | 4,420.4 |
| | $ | 4,485.8 |
| | $ | 2,370.5 |
| | $ | 2,331.1 |
|
| Working capital (deficit) | | (166.6 | ) | | (16.4 | ) | | 129.2 |
| | 30.7 |
| | 89.5 |
|
| Total debt, net of unamortized discount and debt issuance costs | | 1,194.9 |
| | 1,151.9 |
| | 1,044.0 |
| | 642.4 |
| | 655.5 |
|
| Total equity | | 2,526.7 |
| | 2,507.6 |
| | 2,622.8 |
| | 1,287.2 |
| | 1,137.4 |
|
| | | | | | | | | | |
| Average Pricing and Production Expenses From Continuing Operations (per Boe and as a percent of sales for production taxes): | | | | | | | | | | |
| Sales price (excluding net settlements on derivatives) | | $ | 34.61 |
| | $ | 28.69 |
| | $ | 22.43 |
| | $ | 24.64 |
| | $ | 50.72 |
|
| Lease operating expenses | | 3.26 |
| | 2.82 |
| | 2.70 |
| | 3.71 |
| | 4.56 |
|
| Transportation, gathering and processing | | 0.93 |
| | 1.04 |
| | 0.83 |
| | 0.66 |
| | 0.49 |
|
| Production taxes | | 2.25 |
| | 1.91 |
| | 1.42 |
| | 1.20 |
| | 2.76 |
|
| Production taxes (as a percent of sales) | | 6.5 | % | | 6.6 | % | | 6.3 | % | | 4.9 | % | | 5.4 | % |
| | | | | | | | | | | |
| Production (MBoe): | | | | | | | | | | |
| Production from continuing operations | | 40,160 |
| | 31,830 |
| | 22,176 |
| | 15,369 |
| | 9,294 |
|
| Production from discontinued operations | | — |
| | — |
| | — |
| | — |
| | 1,093 |
|
| Total production | | 40,160 |
| | 31,830 |
| | 22,176 |
| | 15,369 |
| | 10,387 |
|
| | | | | | | | | | | |
| Total proved reserves (MMBoe) | | 544.9 |
| | 452.9 |
| | 341.4 |
| | 272.8 |
| | 250.1 |
|
______________
| |
(1) | In 2016, we closed an acquisition in the Delaware Basin for aggregate consideration of approximately $1.76 billion. |
| |
(2) | In 2014, we completed the sale of our ownership interest in PDC Mountaineer, LLC ("PDCM"). Our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations. |
| |
(3) | Includes impact of change in accounts payable related to capital expenditures. |
ITEM 7. MANAGEMENT'SMANAGEMENT’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 thereto included elsewhere inItem 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 2019 to 2020 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, 2020, filed with the SEC on February 25, 2021. Further, we encourage you to revisitreview the Special Note Regarding Forward-Looking Statements in Part I of this report.
EXECUTIVE SUMMARY
20182021 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.
Crude Oil Markets
In 2020, the COVID-19 pandemic led to a significant decline in commodity prices due to the decrease in demand for crude oil, negatively impacting crude oil and natural gas producers, such as PDC. Due to the decrease in oil demand, the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing countries significantly decreased production, resulting in a low level of global supply. During 2021, the global economy slowly recovered from the impacts of COVID-19 and related variants through vaccination distributions. The recovery of the global economy was supported by gradual increases to production volumes from OPEC and other oil producing countries; however, demand growth exceeded the production increases, resulting in higher commodity prices compared to pre-COVID-19 prices. The commodity price environment may remain volatile for an extended period due to, among other things, outbreaks caused by coronavirus variants, the recovery of the economy, unexpected supply disruptions in key producing countries, geopolitical disputes, weather conditions, and ongoing investor and regulatory pressure to replace fossil fuel consumption with lower carbon emission alternatives.
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 exports and deviations from seasonally normal weather. Lower inventory levels and lack of reinvestment in supply growth have driven natural gas and NGL prices higher than recent levels.
Financial Matters
Twelve months ended December 31, 2021
•Production volumes increased 264 percent to 40.2 MMBoe71.3 MMboe in 20182021 compared to 2017. The increase in production volumes was primarily attributable to the continued success2020 as a result of our horizontal Niobrarafull-year drilling and Codell drillingcompletion program in the Wattenberg Field and growing production from our horizontal Wolfcamp drilling program in our Delaware Basin properties. Crude oil production increased 32 percent in 2018 and comprised approximately 42 percent of our total production. Natural gas production increased 23 percent and NGLs production increased 22 percent in 2018 compared to 2017. On a combined basis, total liquids production of crude oil and NGLs comprised 63 percent of production in 2018. For the month ended December 31, 2018, we maintained an average production rate of approximately 129,000 Boe per day, up from approximately 97,000 Boe per day for the month ended December 31, 2017.during 2021.
•Crude oil, natural gas and NGLs sales increased to $1.4$2.6 billion in 20182021 compared to $913.1 million$1.2 billion in 2017,2020, primarily due to a 26 percent increase in production, combined with a 21the 112 percent increase in weighted average realized commodity prices. Crude oil, natural gas and NGLs sales increased 84 percent in 2017 as compared to 2016 due to a 44 percent increase in production, combined with a 28 percent increase in average realized commodity prices.
We had•Incurred negative net settlements from our commodity derivative contracts of $115.5$410.2 million for 2018 as compared to positive net settlements of $13.3$279.3 million and $208.1 million for 2017 and 2016, respectively. See Results of Operations - Commodity Price Risk Management, Net for further details of our settlements of derivatives and changes in the fair value of unsettled derivatives.2020 due to improvement in commodity prices during 2021.
•Combined revenue from crude oil, natural gas and NGLs sales and net settlements received onfrom our commodity derivative instruments increased 3850 percent to $1.3$2.1 billion from $1.4 billion in 2018 from $926.4 million in 2017. Such combined revenue of $926.4 million in 2017 represented an increase of 31 percent from $705.5 million in 2016.2020.
During 2018, we recorded unproved and proved property impairment charges of $458.4 million, primarily resulting from identified current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin and our determination that we would no longer pursue plans to develop these properties. For more information regarding these charges see Results of Operations - Impairments of Properties.
In 2018, we generated a•Generated net income of $2.0$522.3 million, or $0.03$5.22 per diluted share. Ourshare, compared to a net loss of $724.3 million, or $7.37 per diluted share, in 2020. The net income during the period compared to the net loss in the prior period was most negativelysignificantly impacted by the aforementioned impairment charges.
During the same period, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $868.3 million, up 27 percent relative to 2017. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of adjusted EBITDAX and a reconciliation of adjusted EBITDAX to net income and cash from operating activities. The increase in our 2018 adjusted EBITDAX as compared to 2017 was primarily the result of thean increase in crude oil, natural gas and NGLs sales of $476.9 million. This increase was$1,400.0 million and an $882.4 million impairment charge recognized in 2020. These positive factors were partially offset by an increased loss of $881.7 million in commodity price risk management and $105.8 million in additional production taxes between periods.
•Adjusted EBITDAX, a decreasenon-U.S. GAAP financial measure, was $1,593.8 million compared to $990.6 million in derivative commodity settlements of $128.9 million,2020, primarily due to an increase in operating costssales of $125.3$710.5 million, and the reversalnet of a provision for uncollectible notes receivable of $40.2negative net derivative settlements.
•Cash flows from operations increased to $1,547.8 million compared to $870.1 million in 2017. In 2017 and 2016, our net loss per diluted share was $1.94 and $5.01, respectively, and our adjusted EBITDAX was $682.1 million and $459.8 million, respectively.
Our net cash flows from operating activities in 2018, 2017 and 2016 were $889.3 million, $597.8 million and $486.3 million, respectively, and our adjusted2020. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $808.4increased to $1,532.6 million $582.1compared to $921.6 million in 2020. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to $949.0 million from $399.3 million in 2020.
See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and $466.8 million, respectively.a reconciliation of these measures to the most comparable U.S. GAAP measures.
Pending Acquisition
Liquidity
Available liquidity as of December 31, 2018 wasOn February 26, 2022, we entered into the Acquisition Agreement to acquire Great Western for approximately $1.3 billion, which was comprisedinclusive of $1.4Great Western’s net debt. Great Western is an in dependent oil and gas company focused on the exploration, production and development of crude oil and natural gas in Colorado. We anticipate acquiring approximately 54,000 net acres in the Core Wattenberg and production of approximately 55,000 Boe per day. Under the terms of the Acquisition Agreement, the purchase price of the Great Western Acquisition will consist of approximately 4.0 million shares of our common stock and approximately $543 million in cash. The cash portion of the purchase price is expected to be funded through a combination of cash on hand and cash equivalents and $1.3 billion available for borrowingavailability under our revolving credit facility at our current commitment level.facility. We increasedexpect the commitment level on our revolving credit facility to $1.3 billion in October 2018.
We maintain a significant capital investment program to execute our development plans, which requires capital expendituresGreat Western Acquisition to be madecompleted in periods priorthe second quarter of 2022, subject to initial production from newly-developed wells. Further,certain customary closing conditions. Upon a successful close, we use our available liquidity for other working capital requirements, acquisitions, support for letters of creditanticipate adding between $225 million and for general corporate purposes. From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of December 31, 2018 is an indication of a lack of liquidity. 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 attractive 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 our borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time.
Acquisitions
We closed the Bayswater Asset Acquisition in January 2018, acquiring approximately 7,400 net acres, 24 operated horizontal wells that were either DUCs or in-process wells at the time of closing and approximately 220 gross drilling locations. See the footnote titled Business Combination$275 million to our consolidated financial statements included elsewhere inplanned 2022 Wattenberg capital investment. See Item 1A. Risk Factors for risk factors related to the Great Western Acquisition of this report for further details.report.
Acreage ExchangesDrilling, Completion and Vertical Well Abandonment Overview
During 2018,2021, we completed two acreage exchanges that consolidated our positionoperated one full-time drilling rig, one spudder rig and one full-time completion crew in the core area ofWattenberg Field. In addition, we operated one full-time drilling rig and one part-time completion crew, which started in March and ended in June, in the Wattenberg Field, resultingDelaware Basin. Our total capital investments in us acquiring approximately 14,800 net acres in exchange for 15,500 net acres.
2018 Drilling Overview
During the year ended December 31, 2018, we continued to execute our strategic plan to grow production while preserving our financial strengthcrude oil and liquidity. During 2018, we ran three drilling rigs in each of the Wattenberg Field and Delaware Basin.
The following tables summarizes our drilling and completion activitynatural gas properties for the year ended December 31, 2018:
2021 were $583.7 million. We operated a full-time workover rig in the Wattenberg Field in 2021 for use in our plugging and abandonment program. This program focused on our legacy vertical wells to assist in our horizontal drilling program and to reduce our overall produced well emissions. We spent $30.5 million on this program in 2021.
|
| | | | | | | | | | | | | | | | | | |
| | | Wells Operated by PDC |
| | | Wattenberg Field | | Delaware Basin | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| In-process as of December 31, 2017 | | 87 |
| | 80.1 |
| | 13 |
| | 12.2 |
| | 100 |
| | 92.3 |
|
| Wells spud | | 161 |
| | 150.9 |
| | 31 |
| | 29.7 |
| | 192 |
| | 180.6 |
|
| Acquired in-process (1) | | 24 |
| | 18.2 |
| | — |
| | — |
| | 24 |
| | 18.2 |
|
| Wells turned-in-line | | (139 | ) | | (126.8 | ) | | (26 | ) | | (24.5 | ) | | (165 | ) | | (151.3 | ) |
| In-process as of December 31, 2018 | | 133 |
| | 122.4 |
| | 18 |
| | 17.4 |
| | 151 |
| | 139.8 |
|
The following table summarize our drilling, completion and vertical well abandonment activities for the year ended December 31, 2021:
|
| | | | | | | | | | | | | | | | | | |
| | | Wells Operated by Others |
| | | Wattenberg Field | | Delaware Basin | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| In-process as of December 31, 2017 | | 14 |
| | 2.6 |
| | 8 |
| | 1.0 |
| | 22 |
| | 3.6 |
|
| Wells spud | | 25 |
| | 3.4 |
| | 9 |
| | 1.1 |
| | 34 |
| | 4.5 |
|
| Acquired DUCs (operated at December 31, 2018) (1) | | (3 | ) | | (1.5 | ) | | — |
| | — |
| | (3 | ) | | (1.5 | ) |
| Wells turned-in-line | | (31 | ) | | (2.5 | ) | | (11 | ) | | (1.2 | ) | | (42 | ) | | (3.7 | ) |
| In-process as of December 31, 2018 | | 5 |
| | 2.0 |
| | 6 |
| | 0.9 |
| | 11 |
| | 2.9 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Operated Wells |
| | Wattenberg Field | | Delaware Basin | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| In-process as of December 31, 2020 | | 214 | | | 201.8 | | | 20 | | | 19.0 | | | 234 | | | 220.8 | |
| Wells spud | | 78 | | | 74.2 | | | 19 | | | 19.0 | | | 97 | | | 93.2 | |
| Wells turned-in-line | | (149) | | | (143.0) | | | (18) | | | (17.4) | | | (167) | | | (160.4) | |
| In-process as of December 31, 2021 | | 143 | | | 133.0 | | | 21 | | | 20.6 | | | 164 | | | 153.6 | |
| | | | | | | | | | | | |
| Plugged and abandoned - Vertical Wells | | 404 | | | 392.0 | | | — | | | — | | | 404 | | | 392.0 | |
_______________
|
| |
(1) | Represents DUCs and completed wells that had not been turned-in-line that we acquired with the Bayswater Asset Acquisition in January 2018. |
Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our DUCsin-process wells are generally completed and turned-in-line within a yeartwo years of drilling.
2019
Debt Reductions and Capital Returns
Debt Reduction. During the year ended December 31, 2021, we significantly reduced our indebtedness by $670.3 million. This reduction included net repayments of $168.0 million on our revolving credit facility, resulting in no outstanding balance at the period end. On September 15, 2021, we redeemed and retired our 2021 Convertible Notes with a cash payment for the principal amount of $200 million, plus accrued and unpaid interest. Additionally, on November 3, 2021, we redeemed the aggregate $200 million principal amount of our outstanding 2024 Senior Notes at a redemption price of 101.531 percent of the principal plus accrued and unpaid interest, leaving an aggregate principal amount outstanding of $200 million. Finally, on December 1, 2021, we redeemed the remaining $102.3 million principal amount of our outstanding 6.25% Senior Notes due in 2025 (the “2025 Senior Notes”) at a redemption price of 103.125 percent of the principal plus accrued and unpaid interest.
The redemptions of our 2021 Convertible Notes and 2025 Senior Notes as well as the partial redemption of our 2024 Senior Notes were financed by our cash flows from operations.
Stock Repurchase Program. In February 2021, we reinstated our Stock Repurchase Program. During the year ended December 31, 2021, we repurchased 3.8 million shares of outstanding common stock at a cost of $159.5 million. As of December 31, 2021, $187.3 million remained available under the program. In February 2022, our board of directors increased the size of the program to $1.25 billion, which we anticipate fully utilizing by December 31, 2023.
Dividends. In the second quarter of 2021, our board of directors commenced the declaration and payment of quarterly cash dividends of $0.12 per share of our common stock. In December 2021, our board of directors declared and paid a special dividend of $0.50 per share of our common stock in addition to the regular fourth quarter dividend declared. For the year ended December 31, 2021, our dividends paid totaled $0.86 per share of common stock or $83.6 million in the aggregate.
2022 Operational and Financial Outlook
We anticipate that our production for 20192022 will range between 46 MMBoe to 50 MMBoe, or approximately 126,000195,000 Boe to 137,000205,000 Boe per day, for the year. We expect that approximately 4162,000 Bbls to 45 percent65,000 Bbls of our 2019 production willwhich are expected to be comprised of crude oil and approximately 21 to 23 percent will be NGLs, for total liquids of approximately 62 to 68 percent.oil. Our planned 20192022 capital investments in crude oil and natural gas properties, which we expect to be between $810$675 million and $870$725 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin. Our 2022 capital investments budget incorporates an increase in both basins relating to service cost inflation resulting in an estimated cost increase of approximately 10 to 15 percent per well, based on costs we have experienced since the third quarter of 2021.
In 2019, we also expect to spend approximately $20 million for corporate capital, the majority of which is related to the implementation of an ERP system to replace our existing operating and financial systems. This long-planned investment is being made to enhance maintenance of our financial records, improve operational functionality and provide timely information to our management team related to the operation of the business.
We believe that we maintain a degree ofhave 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 in order to best meet our short- and long-term corporate strategy. Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate.
Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie and Plains development areas. Our 2019 capital investment program for the Wattenberg Field is approximately 60 percent of our total capital investments in crude oil and natural gas properties, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. We plan to drill standard-reach lateral (“SRL”), mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells in 2019, the
majority of which will be in the Kersey area of the field. In 2019, we anticipate spudding approximately 135 to 150 operated wells and turning-in-line approximately 110 to 125 operated wells. We expect to drill at a three-rig pace in 2019 with an average development cost per well of between $3 million and $5 million, depending upon the lateral length of the well. The remainder of the Wattenberg Field capital investment program is expected to be used for non-operated drilling, land, capital workovers and facilities projects.
��
Delaware Basin. Our 2019 capital investment program for the Delaware Basin contemplates operating between a two- and three-rig pace throughout the year. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2019 are expected to be approximately 40 percent of our total capital investments in crude oil and natural gas properties, of which approximately 80 percent is allocated to spud approximately 25 to 30 operated wells and turn-in-line approximately 20 to 25 operated wells. We plan to drill MRL and XRL wells in 2019 with an expected average development cost per well of between $11.5 million and $13 million, depending upon the lateral length of the well. We do not plan to drill any SRL wells in the Delaware Basin in 2019. Based on the timing of our operations and requirements to hold acreage, we may elect to drill wells different from or in addition to those currently anticipated as we are continuing to analyze the terms of the relevant leases. We plan to use approximately 20 percent of our budgeted capital for midstream assets, leasing, non-operated capital, seismic and technical studies and facilities.
We are in the process of actively marketing our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets for sale and currently expect to execute agreements for the sales of these assets in the first half of 2019. We anticipate making capital investments for midstream assets of approximately $40 million in 2019, a portion of which would be made prior to such sales depending on the timing of the divestitures. Such expenditures are included in the Delaware Basin capital investment amounts noted above. We expect that we would recover a portion of these expenditures upon settlement of the final sale prices.
Financial Guidance. We are committed to our disciplined approach to managing our development plans and expect that cash flows from operations in 2019 will exceed our capital investments in crude oil and natural gas properties assuming an average NYMEX crude oil price of at least $50.00. Based on our current production forecast for 2019 and our average 2019 price assumptions of $55.00 for NYMEX crude oil and $3.00 for NYMEX natural gas, we expect 2019 cash flows from operations to exceed our capital investments in crude oil and natural gas properties by approximately $65.0 million. Assuming a NYMEX crude oil price of $50.00, we expect cash flows from operations to exceed our capital investments in crude oil and natural gas properties by approximately $25.0 million. We anticipate that capital investments will exceed cash flows from operations during the first half of 2019 and expect cash flows from operations to exceed capital investment during the remainder of the year.
Assuming a NYMEX crude oil price of $45.00, we expect cash flows from operations to approximate our capital investments in crude oil and natural gas properties. A significant decline in NYMEX crude oil prices below approximately $45.00 per barrel would negatively impact our results of operations, financial condition and future development plans. Our leverage ratio, as defined in our revolving credit facility agreement, is expected to decrease from 1.4 as of the end of 2018 to approximately 1.3 by the end of 2019 based on anticipated production and $50.00 to $55.00 NYMEX crude oil prices. We may revise our 20192022 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, requirements to hold acreage, 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 orand acquisition and/orand divestiture opportunities.
Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie, Plains, and Summit development areas. Our 2022 capital investment program for the Wattenberg Field represents approximately 75 percent of our expected total capital investments in crude oil and natural gas properties. In 2022, the majority of the wells we plan to drill are 1.5 mile and 2.0 mile lateral wells in the Wattenberg Field. In 2022, we anticipate spudding approximately 130 to 145 operated wells and turning-in-line approximately 115 to 130 operated wells. As of December 31, 2021, we have approximately 145 gross operated DUCs and 235 approved permitted locations. In 2022, we expect to add a rig in March, bringing us to two full-time horizontal rigs and one completion crew along with a part-time spudder rig.
Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2022 are expected to be approximately 25 percent of our total capital investments. In 2022, we anticipate spudding and turning-in-line approximately 15 to 20 operated wells. The majority of the wells we plan to drill in 2022 in the Delaware Basin are 2.0 mile lateral wells.
We currentlyare committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2022, we expect similar levels2022 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 financial performance and growth in 2020 as$0.25 per share. Then we anticipate experiencing in 2019. Based upon similar pricing assumptions used inexpect to use approximately 60% or more of our 2019 outlook and our focus on capital investment discipline, we currently anticipate increasingremaining adjusted free cash flowflows, 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, building cash on our consolidated balance sheet or other general corporate purposes.
Regulatory and Political Updates
In Colorado, certain interest groups opposed to oil and natural gas development have proposed ballot initiatives that could hinder or eliminate the ability to develop resources in 2020.the state. In 2019, the Colorado legislature passed Senate Bill 19-181 (“SB 19-181”) to address concerns underlying the ballot initiatives.
As part of SB 19-181, a series of rulemaking hearings were conducted, which focused on issues such as permitting requirements, setbacks and siting requirements, resulting in the adoption of new regulatory requirements. Rulemakings focused on financial assurance and permit fees have not been completed. The financial assurance rulemaking could result in increased bonding requirements, though the final language and impact will not be known until early 2022.
A key component of SB 19-181 was the change in the COGCC mission from “fostering” the industry to “regulating” the industry. As a result, changes were made to the permitting process in Colorado. As of January 2021, permits are now designed as Oil and Gas Development Plans (“OGDP”), which streamlines single pad locations or proximate multi-pad locations into a single permitting package.
Operators also have an option to pursue a Comprehensive Area Plan (“CAP”). A CAP is designed to represent an overview of oil and gas development over a larger area over a longer period of time, 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. As both CAPs and OGDPs are new processes and the COGCC staff is working to develop the appropriate requirements and adjusting to their new operating plan, the time needed to obtain a permit has been prolonged. COGCC rules provide that the permitting process could range between six to twelve months or more from submission to approval.
We cannot predict whether future ballot initiatives or other legislation or regulation will be proposed that would limit the areas of the state in which drilling is permitted to occur or impose other requirements or restrictions.
Wattenberg Permits Update. PDC was granted unanimous approval for an 8-well OGDP located in rural Weld County in October 2021, our first approval under the new permitting process resulting from a company-wide collaborative effort. As part of the permit process, we successfully obtained consent from all nearby residents and landowners, which was an option designed by the COGCC for locations with residential building units within 2,000 feet. Additionally, in September, we submitted our application for an OGDP covering an approximate 70-well, multi-pad development plan. We anticipate a COGCC determination on approval of this OGDP in the second quarter of 2022.
In December, PDC submitted our first CAP. The application proposes approximately 450 wells spread amongst 25 surface locations in Weld County, to be developed over several years. We conducted a comprehensive analysis of potential impacts and have committed to transport all water and commodity production via pipeline and to provide electrical infrastructure to all locations. These commitments will lessen the impact of traffic, noise, light and emissions. Additionally, we developed a dashboard to analyze disproportionately impacted communities in the area and developed a robust communication plan designed to encourage communication with and garner feedback from these key stakeholders. We anticipate a COGCC determination on approval of our CAP by year end 2022 or early 2023, recognizing that there may be delays in this new process.
Together, these applications represent our planned Wattenberg Field turn-in-line activity into 2027.
Environmental, Social and Governance
We are committed to a meaningful and measurable ESG strategy. Our mission to be a cleaner, safer and more socially responsible company begins with a sound strategy, is supported in the boardroom and is overseen by our newly created ESG&N Committee at the board of directors and is applied at every level of our business.
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, technological innovations and other activities, require capital and operational investments which are proactively and regularly built into our annual budgeting process. We anticipate approximately $80 million in spending relating to ESG in 2022, which include certain expenditures to ensure compliance with state regulations and the plugging and abandonment of approximately 300 legacy vertical wells. We anticipate a similar level of annual spending over the next several years relating to ESG and compliance to achieve our emission target goals outlined below. We do not anticipate these projects having a material impact on our operations. However, we may revise our 2022 ESG budget during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, a significant change in cash flows or regulatory developments.
During 2021, we implemented the following ESG initiatives:
•Formalized our board oversight of ESG issues by incorporating ESG into our N&G Committee, which became the ESG&N Committee.
•Issued a Sustainability Report addressing a variety of ESG and sustainability matters, including significant Sustainability Accounting Standards Board compliance. The Sustainability Report is available on our website at www.pdce.com and is not incorporated by reference in this report.
•Continued board of directors refreshment by adding two diverse directors and one additional diverse director in February 2022, reflecting a commitment to diversity, refreshment and independence.
•Set aggressive targets to (i) reduce greenhouse gas intensity by 60% from 2020 emissions by 2025 and 74% by 2030, (ii) reduce methane emissions intensity by 50% from 2020 emissions by 2025 and 70% by 2030, and (iii) eliminate routine flaring by 2025.
The following table provides projected financial guidance for 2019:SEC and other regulatory bodies are proposing a number of climate change-focused and broader ESG reporting requirements. If adopted, we will modify our disclosures accordingly.
|
| | | | | | | |
| | Low | | High |
| Operating Expenses |
| Lease operating expenses ($/Boe) | $ | 2.85 |
| | $ | 3.15 |
|
| Transportation, gathering and processing expenses ("TGP") ($/Boe) | $ | 0.80 |
| | $ | 1.00 |
|
| Production taxes (% of crude oil, natural gas and NGL sales) | 6 | % | | 7 | % |
| General and administrative expense ($/Boe) | $ | 3.00 |
| | $ | 3.40 |
|
| | | | |
| Estimated Price Realizations (% of NYMEX, excludes TGP) |
| Crude oil | 90 | % | | 95 | % |
| Natural gas | 50 | % | | 55 | % |
| NGLs | 30 | % | | 35 | % |
Results of Operations
Summary of Operating Results
The following table presents selected information regarding our operating results:results for the periods presented:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| | | | | | | Percent Change |
| 2021 | | 2020 | | 2019 | | 2021-2020 | | 2020-2019 |
| (dollars in millions, except per unit data) | | | | |
| Production: | | | | | | | | | |
| Crude oil (MBbls) | 22,682 | | | 23,720 | | | 19,166 | | | (4) | % | | 24 | % |
| Natural gas (MMcf) | 175,747 | | | 165,637 | | | 115,950 | | | 6 | % | | 43 | % |
| NGLs (MBbls) | 19,360 | | | 17,042 | | | 10,923 | | | 14 | % | | 56 | % |
| Crude oil equivalent (MBoe) | 71,333 | | | 68,368 | | | 49,414 | | | 4 | % | | 38 | % |
| Average Boe per day (Boe) | 195,433 | | | 186,798 | | | 135,381 | | | 5 | % | | 38 | % |
| | | | | | | | | |
| Crude Oil, Natural Gas and NGLs Sales: | | | | | | | | | |
| Crude oil | $ | 1,530.8 | | | $ | 816.8 | | | $ | 1,020.7 | | | 87 | % | | (20) | % |
| Natural gas | 519.6 | | | 178.8 | | | 151.0 | | | 191 | % | | 18 | % |
| NGLs | 502.2 | | | 157.0 | | | 135.6 | | | 220 | % | | 16 | % |
| Total crude oil, natural gas and NGLs sales | $ | 2,552.6 | | | $ | 1,152.6 | | | $ | 1,307.3 | | | 121 | % | | (12) | % |
| | | | | | | | | |
| Net Settlements on Commodity Derivatives: | | | | | | | | | |
| Crude oil | $ | (289.1) | | | $ | 294.4 | | | $ | (18.3) | | | (198) | % | | * |
| Natural gas | (121.1) | | | (15.1) | | | 0.7 | | | * | | * |
| Total net settlements on derivatives | $ | (410.2) | | | $ | 279.3 | | | $ | (17.6) | | | (247) | % | | * |
| | | | | | | | | |
| Average Sales Price (excluding net settlements on derivatives): | | | | | | | | | |
| Crude oil (per Bbl) | $ | 67.49 | | | $ | 34.44 | | | $ | 53.26 | | | 96 | % | | (35) | % |
| Natural gas (per Mcf) | 2.96 | | | 1.08 | | | 1.30 | | | 174 | % | | (17) | % |
| NGLs (per Bbl) | 25.94 | | | 9.21 | | | 12.41 | | | 182 | % | | (26) | % |
| Crude oil equivalent (per Boe) | 35.78 | | | 16.86 | | | 26.46 | | | 112 | % | | (36) | % |
| | | | | | | | | |
| Average Costs and Expense (per Boe): | | | | | | | | | |
| Lease operating expense | $ | 2.53 | | | $ | 2.36 | | | $ | 2.88 | | | 7 | % | | (18) | % |
| Production taxes | 2.32 | | | 0.87 | | | 1.63 | | | 167 | % | | (47) | % |
| Transportation, gathering and processing expenses | 1.41 | | | 1.14 | | | 0.94 | | | 24 | % | | 21 | % |
| General and administrative expense | 1.79 | | | 2.36 | | | 3.27 | | | (24) | % | | (28) | % |
| Depreciation, depletion and amortization | 8.90 | | | 9.06 | | | 13.04 | | | (2) | % | | (31) | % |
| | | | | | | | | |
| Lease Operating Expense by Operating Region (per Boe): | | | | | | | | | |
| Wattenberg Field | $ | 2.19 | | | $ | 2.15 | | | $ | 2.50 | | | 2 | % | | (14) | % |
| Delaware Basin | 4.76 | | | 3.48 | | | 4.15 | | | 37 | % | | (16) | % |
____________
* Percent change is not meaningful.
|
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | | | | | | | Percent Change |
| | 2018 | | 2017 | | 2016 | | 2018-2017 | | 2017-2016 |
| | (dollars in millions, except per unit data) | | | | |
| Production: | | | | | | | | | |
| Crude oil (MBbls) | 16,963 |
| | 12,902 |
| | 8,728 |
| | 31.5 | % | | 47.8 | % |
| Natural gas (MMcf) | 88,017 |
| | 71,689 |
| | 51,730 |
| | 22.8 | % | | 38.6 | % |
| NGLs (MBbls) | 8,527 |
| | 6,981 |
| | 4,826 |
| | 22.1 | % | | 44.7 | % |
| Crude oil equivalent (MBoe) | 40,160 |
| | 31,830 |
| | 22,176 |
| | 26.2 | % | | 43.5 | % |
| Average Boe per day (Boe) | 110,027 |
| | 87,206 |
| | 60,590 |
| | 26.2 | % | | 43.9 | % |
| Crude Oil, Natural Gas and NGLs Sales: | | | | | | | | | |
| Crude oil | $ | 1,038.0 |
| | $ | 625.0 |
| | $ | 348.9 |
| | 66.1 | % | | 79.1 | % |
| Natural gas | 163.2 |
| | 158.3 |
| | 91.6 |
| | 3.1 | % | | 72.8 | % |
| NGLs | 188.8 |
| | 129.8 |
| | 56.9 |
| | 45.5 | % | | 128.1 | % |
| Total crude oil, natural gas and NGLs sales | $ | 1,390.0 |
| | $ | 913.1 |
| | $ | 497.4 |
| | 52.2 | % | | 83.6 | % |
| | | | | | | | | | |
| Net Settlements on Commodity Derivatives: | | | | | | | | | |
| Crude oil | $ | (124.4 | ) | | $ | (2.7 | ) | | $ | 165.2 |
| | * |
| | (101.6 | )% |
| Natural gas | 13.9 |
| | 23.3 |
| | 42.9 |
| | (40.3 | )% | | (45.7 | )% |
| NGLs (propane portion) | (5.0 | ) | | (7.3 | ) | | — |
| | (31.5 | )% | | * |
|
| Total net settlements on derivatives | $ | (115.5 | ) | | $ | 13.3 |
| | $ | 208.1 |
| | * |
| | (93.6 | )% |
| | | | | | | | | | |
| Average Sales Price (excluding net settlements on derivatives): | | | | | | | | | |
| Crude oil (per Bbl) | $ | 61.19 |
| | $ | 48.45 |
| | $ | 39.96 |
| | 26.3 | % | | 21.2 | % |
| Natural gas (per Mcf) | 1.85 |
| | 2.21 |
| | 1.77 |
| | (16.3 | )% | | 24.9 | % |
| NGLs (per Bbl) | 22.14 |
| | 18.59 |
| | 11.80 |
| | 19.1 | % | | 57.5 | % |
| Crude oil equivalent (per Boe) | 34.61 |
| | 28.69 |
| | 22.43 |
| | 20.6 | % | | 27.9 | % |
| | | | | | | | | | |
| Average Costs and Expenses (per Boe): | | | | | | | | | |
| Lease operating expenses | $ | 3.26 |
| | $ | 2.82 |
| | $ | 2.70 |
| | 15.6 | % | | 4.4 | % |
| Production taxes | 2.25 |
| | 1.91 |
| | 1.42 |
| | 17.8 | % | | 34.5 | % |
| Transportation, gathering and processing expenses | 0.93 |
| | 1.04 |
| | 0.83 |
| | (10.6 | )% | | 25.3 | % |
| General and administrative expense | 4.25 |
| | 3.78 |
| | 5.07 |
| | 12.4 | % | | (25.4 | )% |
| Depreciation, depletion and amortization | 13.94 |
| | 14.74 |
| | 18.80 |
| | (5.4 | )% | | (21.6 | )% |
| | | | | | | | | | |
| Lease Operating Expenses by Operating Region (per Boe): | | | | | | | | | |
| Wattenberg Field | $ | 2.99 |
| | $ | 2.48 |
| | $ | 2.70 |
| | 20.6 | % | | (8.1 | )% |
| Delaware Basin | 4.14 |
| | 5.16 |
| | 8.79 |
| | (19.8 | )% | | (41.3 | )% |
| Utica Shale (1) | 3.46 |
| | 1.66 |
| | 1.75 |
| | 108.4 | % | | (5.1 | )% |
| |
* | Percentage change is not meaningful or equal to or greater than 300% or not applicable. |
Amounts may not recalculate due to rounding.
______________
(1) In March 2018, we completed the disposition of our Utica Shale properties.
Crude Oil, Natural Gas and NGLs Sales
The year-over-year change in crudeCrude oil, natural gas and NGLs sales revenue were primarilyfor the year ended December 31, 2021 increased compared to the year ended December 31, 2020 due to the following:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 |
| | (in millions) |
| Increase in production | $ | 261.6 |
| | $ | 227.5 |
|
| Increase in average crude oil price | 216.1 |
| | 109.6 |
|
| Increase (decrease) in average natural gas price | (31.1 | ) | | 31.2 |
|
| Increase in average NGLs price | 30.3 |
| | 47.4 |
|
| Total increase in crude oil, natural gas and NGLs sales revenue | $ | 476.9 |
| | $ | 415.7 |
|
| | | | | | | |
| Year Ended December 31, 2021 | | |
| (in millions) |
| Change in: | | | |
| Production | $ | (3.5) | | | |
| | | |
| Average crude oil price | 749.7 | | | |
| Average natural gas price | 329.9 | | | |
| Average NGLs price | 323.9 | | | |
| Total change in crude oil, natural gas and NGLs sales revenue | $ | 1,400.0 | | | |
The negative impact in sales relating to the change in production volumes during the year ended December 31, 2021 compared to 2020 was impacted by a 4 percent decrease in crude oil production between periods.
Crude Oil, Natural Gas and NGLs Production
The following table presents crude oil, natural gas and NGLs production.production for the periods presented:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | | | |
| | | | | | | | Percent Change |
| Production by Operating Region | | 2021 | | 2020 | | 2019 | | 2021-2020 | | 2020-2019 |
| Crude oil (MBbls) | | | | | | | | | | |
| Wattenberg Field | | 18,901 | | | 19,552 | | | 14,489 | | | (3) | % | | 35 | % |
| Delaware Basin | | 3,781 | | | 4,168 | | | 4,677 | | | (9) | % | | (11) | % |
| Total | | 22,682 | | | 23,720 | | | 19,166 | | | (4) | % | | 24 | % |
| Natural gas (MMcf) | | | | | | | | | | |
| Wattenberg Field | | 154,150 | | | 140,845 | | | 91,785 | | | 9 | % | | 53 | % |
| Delaware Basin | | 21,597 | | | 24,792 | | | 24,165 | | | (13) | % | | 3 | % |
| Total | | 175,747 | | | 165,637 | | | 115,950 | | | 6 | % | | 43 | % |
| NGLs (MBbls) | | | | | | | | | | |
| Wattenberg Field | | 17,300 | | | 14,495 | | | 8,198 | | | 19 | % | | 77 | % |
| Delaware Basin | | 2,060 | | | 2,547 | | | 2,725 | | | (19) | % | | (7) | % |
| Total | | 19,360 | | | 17,042 | | | 10,923 | | | 14 | % | | 56 | % |
| Crude oil equivalent (MBoe) | | | | | | | | | | |
| Wattenberg Field | | 61,892 | | | 57,521 | | | 37,984 | | | 8 | % | | 51 | % |
| Delaware Basin | | 9,441 | | | 10,847 | | | 11,430 | | | (13) | % | | (5) | % |
| Total | | 71,333 | | | 68,368 | | | 49,414 | | | 4 | % | | 38 | % |
| Average crude oil equivalent per day (Boe) | | | | | | | | | | |
| Wattenberg Field | | 169,567 | | | 157,161 | | | 104,066 | | | 8 | % | | 51 | % |
| Delaware Basin | | 25,866 | | | 29,637 | | | 31,315 | | | (13) | % | | (5) | % |
| Total | | 195,433 | | | 186,798 | | | 135,381 | | | 5 | % | | 38 | % |
Net production volumes for oil, natural gas and NGLs increased 4 percent during the year ended December 31, 2021 compared to 2020. The increase in production volume between periods was primarily due to a greater number of wells turned-in-line since the fourth quarter of 2020. This increase was partially offset by normal decline in production from our existing wells and lower performance of wells turned-in-line in the Delaware Basin during 2021.
|
| | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | | | | | | | Change |
| Production by Operating Region | | 2018 | | 2017 | | 2016 | | 2018-2017 | | 2017-2016 |
| Crude oil (MBbls) | | | | | | | | | | |
| Wattenberg Field | | 12,809 |
| | 10,922 |
| | 8,230 |
| | 17.3 | % | | 32.7 | % |
| Delaware Basin | | 4,108 |
| | 1,699 |
| | 79 |
| | 141.8 | % | | * |
|
| Utica Shale (1) | | 46 |
| | 281 |
| | 419 |
| | (83.6 | )% | | (32.9 | )% |
| Total | | 16,963 |
| | 12,902 |
| | 8,728 |
| | 31.5 | % | | 47.8 | % |
| Natural gas (MMcf) | | | | | | | | | | |
| Wattenberg Field | | 68,326 |
| | 60,106 |
| | 48,889 |
| | 13.7 | % | | 22.9 | % |
| Delaware Basin | | 19,277 |
| | 9,410 |
| | 373 |
| | 104.9 | % | | * |
|
| Utica Shale (1) | | 414 |
| | 2,173 |
| | 2,468 |
| | (80.9 | )% | | (12.0 | )% |
| Total | | 88,017 |
| | 71,689 |
| | 51,730 |
| | 22.8 | % | | 38.6 | % |
| NGLs (MBbls) | | | | | | | | | | |
| Wattenberg Field | | 6,455 |
| | 5,876 |
| | 4,568 |
| | 9.9 | % | | 28.6 | % |
| Delaware Basin | | 2,038 |
| | 917 |
| | 36 |
| | 122.2 | % | | * |
|
| Utica Shale (1) | | 34 |
| | 188 |
| | 222 |
| | (81.9 | )% | | (15.3 | )% |
| Total | | 8,527 |
| | 6,981 |
| | 4,826 |
| | 22.1 | % | | 44.7 | % |
| Crude oil equivalent (MBoe) | | | | | | | | | | |
| Wattenberg Field | | 30,652 |
| | 26,815 |
| | 20,945 |
| | 14.3 | % | | 28.0 | % |
| Delaware Basin | | 9,359 |
| | 4,184 |
| | 178 |
| | 123.7 | % | | * |
|
| Utica Shale (1) | | 149 |
| | 831 |
| | 1,053 |
| | (82.1 | )% | | (21.1 | )% |
| Total | | 40,160 |
| | 31,830 |
| | 22,176 |
| | 26.2 | % | | 43.5 | % |
| Average crude oil equivalent per day (Boe) | | | | | | | | |
| Wattenberg Field | | 83,978 |
| | 73,466 |
| | 57,227 |
| | 14.3 | % | | 28.4 | % |
| Delaware Basin | | 25,641 |
| | 11,463 |
| | 486 |
| | 123.7 | % | | * |
|
| Utica Shale (1) | | 408 |
| | 2,277 |
| | 2,877 |
| | (82.1 | )% | | (20.9 | )% |
| Total | | 110,027 |
| | 87,206 |
| | 60,590 |
| | 26.2 | % | | 43.9 | % |
|
| |
* | Percentage change is not meaningful or equal to or greater than 300 percent. |
| Amounts may not recalculate due to rounding. |
(1) | In March 2018, we completed the disposition of our Utica Shale properties. |
47
The following table presents our crude oil, natural gas and NGLs production ratio by operating region:region for the periods presented:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| Production Ratio by Operating Region | | 2021 | | 2020 | | 2019 |
| Wattenberg Field | | | | | | |
| Crude oil | | 31 | % | | 34 | % | | 38 | % |
| Natural gas | | 41 | % | | 41 | % | | 40 | % |
| NGLs | | 28 | % | | 25 | % | | 22 | % |
| Total | | 100 | % | | 100 | % | | 100 | % |
| Delaware Basin | | | | | | |
| Crude oil | | 40 | % | | 38 | % | | 41 | % |
| Natural gas | | 38 | % | | 38 | % | | 35 | % |
| NGLs | | 22 | % | | 24 | % | | 24 | % |
| Total | | 100 | % | | 100 | % | | 100 | % |
|
| | | | | | | | | |
| | | Year Ended December 31, |
| | | | | | | |
| Production Ratio by Operating Region | | 2018 | | 2017 | | 2016 |
| Wattenberg Field | | | | | | |
| Crude oil | | 42 | % | | 41 | % | | 39 | % |
| Natural gas | | 37 | % | | 37 | % | | 39 | % |
| NGLs | | 21 | % | | 22 | % | | 22 | % |
| Total | | 100 | % | | 100 | % | | 100 | % |
| Delaware Basin | | | | | | |
| Crude oil | | 44 | % | | 41 | % | | 45 | % |
| Natural gas | | 34 | % | | 37 | % | | 35 | % |
| NGLs | | 22 | % | | 22 | % | | 20 | % |
| Total | | 100 | % | | 100 | % | | 100 | % |
| Utica Shale (1) | | | | | | |
| Crude oil | | 31 | % | | 34 | % | | 40 | % |
| Natural gas | | 46 | % | | 43 | % | | 39 | % |
| NGLs | | 23 | % | | 23 | % | | 21 | % |
| Total | | 100 | % | | 100 | % | | 100 | % |
______________The change in production mix in the Wattenberg Field during the year ended December 31, 2021 compared to 2020 and 2019 was driven by our 2021 development plan being focused on areas that have a higher gas/oil ratio and due to less bypass processing of gas which increased our NGLs ratio and economics.
(1) In March 2018, we completed the disposition of our Utica Shale properties.
Midstream Capacity
Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, pipelinescompression 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 to us on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. Both of our current areas of operation have seen substantial development in recent years, and this has made it more difficult for providers of midstream infrastructure and services to keep pace with the corresponding increases in field-wide production.
The ultimate timing and availability of adequate infrastructure is not withinremains out of our control and we could experience capacity constraints for extended periods of time that would negatively impact our ability to meet our production targets.control. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure.
Wattenberg Field. Elevated line pressures on gas gathering facilities have adversely affected production from the Wattenberg Field Like other producers, from time to time most recently beginning in mid-2017 and continuing into the fourth quarter of 2018. DCP completed its Mewbourn 3 Plant in August of 2018. This project, along with associated new compression, resulted in significant incremental capacity being added to the DCP system. System pressures began to decrease as these projects were started and reached full capacity during the third and fourth quarters of 2018. Concurrently, additional residue pipeline capacity became available as pipeline expansion projects were completed and commissioned in November 2018. As a result, system pressures have recently been maintained at a lower level than during the latter part of 2017. These lower pressures, along with the system improvements implemented by DCP to prevent freezes, combined with relatively mild weather in late 2018, resulted in a significant reduction in line freezes compared to those experienced during late 2017.
DCP continues to make progress on construction of its O’Conner 2 Plant, which we expect to be completed by the end of the second quarter of 2019. We expect that the start-up of the O’Conner 2 Plant will further reduce the line pressures on the system, while providing additional processing capacity for incremental production associated with our ongoing drilling program. This is the second plant that includes baseline volume commitments for us and the other operators and guarantees a specified profit margin to DCP for a three-year period, beginning on the initial start-up date of the plant. Under our current drilling plans and in the current commodity pricing environment, we currently expect to satisfy the volume commitment and profit margin requirements with minimal payment from us. See the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report for additional details regarding these agreements.
We have been engaged with DCP in planning for further incremental increases to the processing capacity in the field and it is currently our expectation that an additional plant will be constructed and commissioned on DCP’s system in mid-2020. We also continue to work with our other midstream service providers in the field in an effort to ensure all of the existing infrastructure is fully utilized and that all options for system expansion are evaluated and implemented to the extent possible.
Additional residue and NGL takeaway pipeline expansions/conversions are expected to be completed in the third and fourth quarters of 2019 to help ensure that all products associated with additional processing capacity will be transported to market.
NGL fractionation on the Gulf Coast and Conway is running at full capacity and this could potentially impact the operation of gas plants in the Wattenberg Field. While our Wattenberg Field operations are not currently being impacted by NGL fractionation capacity constraints, the limitation on NGL fractionation capacity did limit the throughput of some gas processing plants in the field for a portion of the fourth quarter of 2018. Limitations on downstream fractionation capacity could limit the ability of our service providers to adjust ethane and propane recoveries to optimize the plant product mix to maximize revenue. Additional fractionation capacity is scheduled to come online later in 2019 and in 2020.
Delaware Basin. Like other producers, we from time to time enter into volume commitments with midstream providers in order to induceincentivize them to provide increased capacity.capacity to sufficiently 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 substantial penalties.In the second quarter of 2018, we entered into firm sales and pipeline agreementstransportation charges or aid in construction payments for portions of our Delaware Basin crude oil and natural gas production, respectively. The crude oil agreement runs through December 2023 and provides for firm physical takeaway for all of our forecasted 2019 Delaware Basin crude oil volumes. This agreement provides us with price diversification through realization of export market pricing that includes access to a Corpus Christi terminal and exposure to Brent-weighted prices. As a result of this agreement, we expect to realize approximately 94 percent of West Texas Intermediate ("WTI") crude oil pricing for our total Delaware Basin production in 2019, after deducting transportation and other related marketing expenses. Our actual realization for Delaware Basin production for 2018 was 95 percent of WTI crude oil pricing. We are currently not producing sufficient volumes to satisfy this volume commitment in the Delaware Basin; although at current commodity prices we have been able to profitably satisfy our obligations under the agreement with volumes purchased from third parties, this may not continue to be the case.shortfalls.
Our Delaware Basin natural gas sales agreements run through December 2021 and provide for firm physical takeaway of amounts that vary between 50,000 MMbtu and 115,000 MMbtu per day of our natural gas volumes from the basin during the term of the agreements. We installed additional compression in the Central area of the basin during the third quarter of 2018, which allowed us to move our Central area natural gas volumes with minimal flaring.
Our production from the Wattenberg Field and Delaware Basin was not materially affected by midstream or downstream capacity constraints during 2018. However, natural gas takeaway capacity downstream of in-field gatheringthe year ended December 31, 2021. We continuously monitor infrastructure capacities versus producer activity and processing facilities in the basin is operating close to capacity, and near-term production constraints are possible.volume forecasts.
As discussed above, NGL fractionation on the Gulf Coast and Conway is running at full capacity, and this could potentially impact the operation of gas plants in the Delaware Basin. In addition, residue pipeline and downstream crude oil pipelines in the Delaware Basin are operating at high utilization rates. We expect additional residue gas and crude oil pipelines to be available in early 2020, and additional NGL fractionation infrastructure to be available starting in mid-2019, with more projects scheduled to be completed in 2020.
See Item 1A. Risk Factors - The marketability of our production is dependent upon transportation and processing facilities, the capacity and operation of which we do not control. Market conditions or operational impediments affecting midstream facilities and services could hinder our access to crude oil, natural gas and NGL markets, increase our costs or delay production. Our efforts to address midstream issues may not be successful.
Crude Oil, Natural Gas and NGLs Pricing
Our results of operations depend upon many factors. Key factors include the pricemarket prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLNGLs prices have a high degree of volatility and our realizations can change substantially. Our weighted average realized salescommodity prices for crude oil and NGLs increased and our realized prices for natural gas decreased112 percent during 20182021 as compared to 2017.2020. The NYMEX average daily crude oil prices increased 27 percent and NYMEX first-of-the-month natural gas prices decreased slightlyincreased 72 percent and 81 percent, respectively, as compared to 2017. Our realized sales prices for crude oil, natural gas and NGLs increased during 2017 compared to 2016. NYMEX crude oil prices increased 18 percent and NYMEX natural gas prices increased 26 percent as compared to 2016.2020.
The following tables present weighted-averagetable presents weighted average sales prices of crude oil, natural gas and NGLs for the periods presented.presented:
| | | | | | | | | | | | | | Year Ended December 31, | |
| | | Year Ended December 31, | |
| Weighted-Average Sales Price by Operating Region | | | | | | | | Change | |
| Weighted Average Realized Sales Price by Operating Region | | Weighted Average Realized Sales Price by Operating Region | | | | Percent Change |
| (excluding net settlements on derivatives) | | 2018 | | 2017 | | 2016 | | 2018-2017 | | 2017-2016 | (excluding net settlements on derivatives) | | 2021 | | 2020 | | 2019 | | 2021-2020 | | 2020-2019 |
| Crude oil (per Bbl) | | | | | | | | | | | Crude oil (per Bbl) | | | | | | | | | | |
| Wattenberg Field | | $ | 61.14 |
| | $ | 48.48 |
| | $ | 39.99 |
| | 26.1 | % | | 21.2 | % | Wattenberg Field | | $ | 67.49 | | | $ | 34.21 | | | $ | 52.99 | | | 97 | % | | (35) | % |
| Delaware Basin | | 61.37 |
| | 48.68 |
| | 49.28 |
| | 26.1 | % | | (1.2 | )% | Delaware Basin | | 67.47 | | | 35.48 | | | 54.08 | | | 90 | % | | (34) | % |
| Utica Shale (1) | | 58.10 |
| | 45.63 |
| | 37.62 |
| | 27.3 | % | | 21.3 | % | |
| Weighted-average price | | 61.19 |
| | 48.45 |
| | 39.96 |
| | 26.3 | % | | 21.2 | % | |
| Weighted average price | | Weighted average price | | 67.49 | | | 34.44 | | | 53.26 | | | 96 | % | | (35) | % |
| Natural gas (per Mcf) | | | | | | | | | | | Natural gas (per Mcf) | |
| Wattenberg Field | | 1.90 |
| | 2.19 |
| | 1.77 |
| | (13.2 | )% | | 23.7 | % | Wattenberg Field | | 2.98 | | | 1.22 | | | 1.49 | | | 144 | % | | (18) | % |
| Delaware Basin | | 1.66 |
| | 2.26 |
| | 2.78 |
| | (26.5 | )% | | (18.7 | )% | Delaware Basin | | 2.81 | | | 0.28 | | | 0.57 | | | * | | (51) | % |
| Utica Shale (1) | | 2.68 |
| | 2.40 |
| | 1.58 |
| | 11.7 | % | | 51.9 | % | |
| Weighted-average price | | 1.85 |
| | 2.21 |
| | 1.77 |
| | (16.3 | )% | | 24.9 | % | |
| Weighted average price | | Weighted average price | | 2.96 | | | 1.08 | | | 1.30 | | | 174 | % | | (17) | % |
| NGLs (per Bbl) | | | | | | | | | | | NGLs (per Bbl) | |
| Wattenberg Field | | 20.58 |
| | 17.75 |
| | 11.59 |
| | 15.9 | % | | 53.1 | % | Wattenberg Field | | 24.77 | | | 8.84 | | | 11.51 | | | 180 | % | | (23) | % |
| Delaware Basin | | 27.06 |
| | 22.64 |
| | 17.87 |
| | 19.5 | % | | 26.7 | % | Delaware Basin | | 35.72 | | | 11.32 | | | 15.12 | | | 216 | % | | (25) | % |
| Utica Shale (1) | | 24.29 |
| | 25.06 |
| | 15.11 |
| | (3.1 | )% | | 65.9 | % | |
| Weighted-average price | | 22.14 |
| | 18.59 |
| | 11.80 |
| | 19.1 | % | | 57.5 | % | |
| Weighted average price | | Weighted average price | | 25.94 | | | 9.21 | | | 12.41 | | | 182 | % | | (26) | % |
| Crude oil equivalent (per Boe) | | | | | | | | | | | Crude oil equivalent (per Boe) | |
| Wattenberg Field | | 34.13 |
| | 28.55 |
| | 22.38 |
| | 19.5 | % | | 27.6 | % | Wattenberg Field | | 34.95 | | | 16.84 | | | 26.31 | | | 108 | % | | (36) | % |
| Delaware Basin | | 36.25 |
| | 29.80 |
| | 31.50 |
| | 21.6 | % | | (5.4 | )% | Delaware Basin | | 41.25 | | | 16.94 | | | 26.95 | | | 144 | % | | (37) | % |
| Utica Shale (1) | | 30.98 |
| | 27.36 |
| | 21.88 |
| | 13.2 | % | | 25.0 | % | |
| Weighted-average price | | 34.61 |
| | 28.69 |
| | 22.43 |
| | 20.6 | % | | 27.9 | % | |
| Weighted average price | | Weighted average price | | 35.78 | | | 16.86 | | | 26.46 | | | 112 | % | | (36) | % |
|
| |
* | Percentage change is not meaningful or equal to or greater than 300 percent. |
| Amounts may not recalculate due to rounding. |
(1) | In March 2018, we completed the disposition of our Utica Shale properties. |
* Percent change is not meaningful.
Crude oil, natural gas and NGLs revenues are recognized when we have transferredtransfer control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurredoccur 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. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and actual prices received.
Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross"“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 proceeds based on a percent of the proceeds or have fixed oura 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 indices forindex 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 purchaserspurchaser 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 transporttransportation 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 expenses.(“TGP”) expense.
Under the New Revenue Standard, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard are recognized using the net-back method. If we had adopted the New Revenue Standard on January 1, 2017, we estimate that the average realization percentages before transportation, gathering and processing expenses for 2017 would not have differed materially from the average realization percentages shown for the periods shown below. Further, the net realized price after transportation, gathering and processing expenses would not have changed. See the footnote titled Revenue Recognition to our consolidated financial statements included elsewhere in this report for a more detailed discussion.
As discussed above, we enter into agreements for the sale and transportation, gathering and processing of our production, the terms of which can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications inof TGP expense on the consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based uponon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based uponon 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 respectiverelevant 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 transportation, gathering and processing expensesTGP expense shown in the table below represents our approximate composite per barrel price for NGLs.NGLs for the periods presented.
| | | 2018 | | Average NYMEX Price | | Average Realized Price Before Transportation, Gathering and Processing Expenses | | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | | Average Transportation, Gathering and Processing Expenses | | Average Realized Price After Transportation, Gathering and Processing Expenses | | Average Realization Percentage After Transportation, Gathering and Processing Expenses | |
| 2021 | | 2021 | | Average NYMEX Price | | Average Realized Price Before TGP Expense | | Average Realization Percentage Before TGP Expense | | Average TGP Expense(1) | | Average Realized Price After TGP Expense | | Average Realization Percentage After TGP Expense |
| Crude oil (per Bbl) | | $ | 64.77 |
| | $ | 61.19 |
| | 94 | % | | $ | 0.94 |
| | $ | 60.25 |
| | 93 | % | Crude oil (per Bbl) | | $ | 67.92 | | | $ | 67.49 | | | 99 | % | | $ | 3.10 | | | $ | 64.39 | | | 95 | % |
| Natural gas (per MMBtu) | | 3.09 |
| | 1.85 |
| | 60 | % | | 0.22 |
| | 1.63 |
| | 53 | % | Natural gas (per MMBtu) | | 3.76 | | | 2.96 | | | 79 | % | | 0.13 | | | 2.83 | | | 75 | % |
| NGLs (per Bbl) | | 64.77 |
| | 22.14 |
| | 34 | % | | 0.21 |
| | 21.93 |
| | 34 | % | NGLs (per Bbl) | | 67.92 | | | 25.94 | | | 38 | % | | — | | | 25.94 | | | 38 | % |
| Crude oil equivalent (per Boe) | | 47.87 |
| | 34.61 |
| | 72 | % | | 0.93 |
| | 33.68 |
| | 70 | % | Crude oil equivalent (per Boe) | | 49.29 | | | 35.78 | | | 73 | % | | 1.30 | | | 34.48 | | | 70 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | Average NYMEX Price | | Average Realized Price Before TGP Expense | | Average Realization Percentage Before TGP Expense | | Average TGP Expense(1) | | Average Realized Price After TGP Expense | | Average Realization Percentage After TGP Expense |
| Crude oil (per Bbl) | | $ | 39.40 | | | $ | 34.44 | | | 87 | % | | $ | 2.34 | | | $ | 32.10 | | | 81 | % |
| Natural gas (per MMBtu) | | 2.08 | | | 1.08 | | | 52 | % | | 0.12 | | | 0.96 | | | 46 | % |
| NGLs (per Bbl) | | 39.40 | | | 9.21 | | | 23 | % | | — | | | 9.21 | | | 23 | % |
| Crude oil equivalent (per Boe) | | 28.52 | | | 16.86 | | | 59 | % | | 1.10 | | | 15.76 | | | 55 | % |
|
| | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | Average NYMEX Price | | Average Realized Price Before Transportation, Gathering and Processing Expenses | | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | | Average Transportation, Gathering and Processing Expenses | | Average Realized Price After Transportation, Gathering and Processing Expenses | | Average Realization Percentage After Transportation, Gathering and Processing Expenses |
| Crude oil (per Bbl) | | $ | 50.95 |
| | $ | 48.45 |
| | 95 | % | | $ | 1.41 |
| | $ | 47.04 |
| | 92 | % |
| Natural gas (per MMBtu) | | 3.11 |
| | 2.21 |
| | 71 | % | | 0.17 |
| | 2.04 |
| | 66 | % |
| NGLs (per Bbl) | | 50.95 |
| | 18.59 |
| | 36 | % | | 0.30 |
| | 18.29 |
| | 36 | % |
| Crude oil equivalent (per Boe) | | 38.83 |
| | 28.69 |
| | 74 | % | | 1.04 |
| | 27.65 |
| | 71 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2019 | | Average NYMEX Price | | Average Realized Price Before TGP Expense | | Average Realization Percentage Before TGP Expense | | Average TGP Expense(1) | | Average Realized Price After TGP Expense | | Average Realization Percentage After TGP Expense |
| Crude oil (per Bbl) | | $ | 57.03 | | | $ | 53.26 | | | 93 | % | | $ | 1.24 | | | $ | 52.02 | | | 91 | % |
| Natural gas (per MMBtu) | | 2.63 | | | 1.30 | | | 49 | % | | 0.17 | | | 1.13 | | | 43 | % |
| NGLs (per Bbl) | | 57.03 | | | 12.41 | | | 22 | % | | 0.10 | | | 12.31 | | | 22 | % |
| Crude oil equivalent (per Boe) | | 40.95 | | | 26.46 | | | 65 | % | | 0.90 | | | 25.56 | | | 62 | % |
____________
(1) Average TGP expense excludes unutilized firm transportation fees of $0.11, $0.04, and $0.04 per Boe for the years ended December 31, 2021, 2020, and 2019, respectively. |
| | | | | | | | | | | | | | | | | | | | | | |
| 2016 | | Average NYMEX Price | | Average Realized Price Before Transportation, Gathering and Processing Expenses | | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | | Average Transportation, Gathering and Processing Expenses | | Average Realized Price After Transportation, Gathering and Processing Expenses | | Average Realization Percentage After Transportation, Gathering and Processing Expenses |
| Crude oil (per Bbl) | | $ | 43.32 |
| | $ | 39.96 |
| | 92 | % | | $ | 1.51 |
| | $ | 38.45 |
| | 89 | % |
| Natural gas (per MMBtu) | | 2.46 |
| | 1.77 |
| | 72 | % | | 0.07 |
| | 1.70 |
| | 69 | % |
| NGLs (per Bbl) | | 43.32 |
| | 11.80 |
| | 27 | % | | 0.28 |
| | 11.52 |
| | 27 | % |
| Crude oil equivalent (per Boe) | | 32.22 |
| | 22.43 |
| | 70 | % | | 0.83 |
| | 21.60 |
| | 67 | % |
Our average realization percentages for crude oil, natural gas and NGLs for 2018 are consistent with those for 2017. The realization percentage for our natural gas sales has decreasedincreased in 2021 as compared to 2017,2020 primarily due to the widening ofoverall increase in commodity prices between periods driven by the basis between NYMEXimprovement in oil and the indices upon whichgas product demand that occurred throughout 2021. Additionally, we sell our natural gas production.realized improved differentials resulting from 2021 sales contracts.
Commodity Price Risk Management Net
We use commodity derivative instruments to manage fluctuations in crude oil and natural gas and NGLs prices, including collars, fixed-price swapsexchanges, and basis swapsprotection exchanges on a portion of our estimated crude oil and natural gas and propane production. For our commodity swaps,exchanges, we ultimately realize the fixed price value related to the swaps. See the footnote titled Note 7 - Commodity Derivative Financial Instruments to our consolidated financial statements in Item 8.Financial Statements and Supplementary Data included elsewhere in this report for a detailed presentationsummary of our derivative positions as of December 31, 2018.2021.
Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, as well asand the change in the fair value of unsettled commodity derivatives related to our crude oil and natural gas and propane production. Commodity price risk management, net, does not include derivative transactions related to our gas marketing, which are included in other income and other expenses.
Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas and propane index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlementssettlement 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 value 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 net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas and NGLs forward price curves and changes in certain differentials.
The following table presents net settlements and net change in fair value of unsettled commodity derivatives included in commodity price risk management, net:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in millions) |
| Commodity price risk management gain (loss), net: | | | | | |
| Net settlements of commodity derivative instruments: | | | | | |
| Crude oil fixed price swaps and collars | $ | (139.7 | ) | | $ | (2.7 | ) | | $ | 165.2 |
|
| Crude oil basis protection swaps | 15.2 |
| | — |
| | — |
|
| Natural gas fixed price swaps and collars | (7.0 | ) | | 19.5 |
| | 41.9 |
|
| Natural gas basis protection swaps | 21.0 |
| | 3.8 |
| | 1.0 |
|
| NGLs (propane portion) fixed price swaps | (5.0 | ) | | (7.3 | ) | | — |
|
| Total net settlements of commodity derivative instruments | (115.5 | ) | | 13.3 |
| | 208.1 |
|
| Change in fair value of unsettled commodity derivative instruments: | | | | | |
| Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments | 64.9 |
| | 44.8 |
| | (220.0 | ) |
| Crude oil fixed price swaps, collars and rollfactors | 197.0 |
| | (77.9 | ) | | (78.6 | ) |
| Natural gas fixed price swaps and collars | 1.4 |
| | 14.7 |
| | (37.1 | ) |
| Natural gas basis protection swaps | (2.6 | ) | | 5.7 |
| | 1.9 |
|
| NGLs (propane portion) fixed price swaps | — |
| | (4.6 | ) | | — |
|
| Net change in fair value of unsettled commodity derivative instruments | 260.7 |
| | (17.3 | ) | | (333.8 | ) |
| Total commodity price risk management gain (loss), net | $ | 145.2 |
| | $ | (4.0 | ) | | $ | (125.7 | ) |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (in millions) |
| Commodity price risk management gain (loss), net: | | | | | |
| Net settlements of commodity derivative instruments: | | | | | |
| Crude oil collars and fixed price exchanges | $ | (289.1) | | | $ | 294.4 | | | $ | (18.3) | |
| Natural gas collars and fixed price exchanges | (120.1) | | | (1.4) | | | 8.8 | |
| Natural gas basis protection exchanges | (1.0) | | | (13.7) | | | (8.1) | |
| Total net settlements of commodity derivative instruments | (410.2) | | | 279.3 | | | (17.6) | |
| Change in fair value of unsettled commodity derivative instruments: | | | | | |
| Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments | 49.3 | | | (19.9) | | | (81.1) | |
| Crude oil collars and fixed price exchanges | (269.3) | | | (49.8) | | | (62.1) | |
| Natural gas collars and fixed price exchanges | (61.7) | | | (7.8) | | | 0.1 | |
| Natural gas basis protection exchanges | (9.6) | | | (21.5) | | | (2.1) | |
| Net change in fair value of unsettled commodity derivative instruments | (291.3) | | | (99.0) | | | (145.2) | |
| Total commodity price risk management gain (loss), net | $ | (701.5) | | | $ | 180.3 | | | $ | (162.8) | |
The significant increase in commodity prices during 2021 had an overall unfavorable impact on the fair value and settlements of our commodity derivatives.
Lease Operating ExpensesExpense
Lease operating expenses(“LOE”) expense increased 46by 12 percent to $131.0$180.7 million in 20182021 compared to $89.6$161.3 million in 2017.2020. The period-over-period increase in LOE was primarily due to increases(i) increased activities and payroll costs at our well locations from the COVID-19 induced downturn in 2020, (ii) $5.6 million of $8.3 million for workover projects relatedadditional environmental and regulatory costs in 2021, and (iii) fewer vendor concessions experienced in 2021 as compared to increased costs to plug and abandon wells in2020 as the Wattenberg Field, $5.7 million related to additional compressor and equipment rentals to combat high line pressures, $5.4 million in environmental remediation expense, $4.9 million related to midstream expense in the Delaware Basin, $4.9 million for payroll and employee benefits related to increases in headcount, $2.6 million related to produced water disposal expense and $1.2 million related to expense for non-operated wells. Lease operating expenseprice of commodities has improved. LOE per Boe increased by 167 percent to $3.26 for 2018$2.53 in 2021 from $2.82 for 2017.$2.36 in 2020.
Lease operating expenses were $89.6 million in 2017 compared to $60.0 million in 2016. The $29.6 million increase in lease operating expenses in 2017 as compared to 2016 was primarily due to increases of $9.4 million for payroll and employee benefits related to increases in headcount, $5.6 million for produced water disposal, $5.6 million for increased workover projects, $3.9 million related to additional compressor rentals and $2.2 million for equipment rentals. The increases were slightly offset by a $1.5 million decrease in environmental remediation costs. Lease operating expense per Boe increased by four percent to $2.82 for 2017 from $2.70 for 2016.
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 from year-to-year.prices.
Production taxes increased 49178 percent to $90.4$165.2 million in 20182021 compared to $60.7$59.4 million in 2017,2020. Production taxes per Boe increased 167 percent to $2.32 in 2021 compared to $0.87 in 2020. The increase in production taxes was primarily due to the 52 percentan increase in crude oil, natural gas and NGLs sales for 2018 compared to 2017, as well as an increase in the ad valorem tax rate in the Delaware Basin related to an increase in assessed property values.prices between periods.
Production taxes increased 93 percent to $60.7 million in 2017 compared to $31.4 million in 2016, primarily due to the 84 percent increase in crude oil, natural gas and NGLs sales for 2017 compared to 2016, as well as an increase in tax rates.
Transportation, Gathering and Processing ExpensesExpense
Transportation, gathering and processing expensesTGP expense increased 1329 percent to $37.4$100.4 million in 20182021 compared to 2017 and$77.8 million in 2020. TGP per Boe increased 80 percent in 2017 to $33.2 million$1.41 for 2021 compared to 2016. Transportation, gathering and processing expenses are primarily impacted$1.14 for 2020. The overall increase in TGP expense for 2021 compared to 2020 was driven by thea $14.4 million increase relating to transportation of our crude oil volumes delivered through pipelines and for natural gas gathering anda $5.1 million increase in unutilized transportation operations. The change in 2018 as comparedfees relating to 2017 is further impacted by decreases resulting from the adoption of the New Revenue Standard and the disposition of the Utica Shale properties. As discussed in Crude Oil, Natural Gas and NGLs Pricing, whether transportation, gathering and processing costs are presented separately or are reflected as a reduction to net revenue is a function of the terms of the relevant marketing contract.
Exploration, Geologic and Geophysical Expense
The following table presents the major components of exploration, geologic and geophysical expense:
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | (in millions) |
| | | | | | | |
| Exploratory dry hole costs | | $ | 0.1 |
| | $ | 41.3 |
| | $ | — |
|
| Geological and geophysical costs | | 3.4 |
| | 3.9 |
| | 3.5 |
|
| Operating, personnel and other | | 2.7 |
| | 2.1 |
| | 1.2 |
|
| Total exploration expense | | $ | 6.2 |
| | $ | 47.3 |
| | $ | 4.7 |
|
Exploratory dry hole costs. During 2017, two exploratory dry holes, associated lease costs and related infrastructure assetsour delivery commitment in the Delaware Basin were expensed at a cost of $41.3 million. The conclusion to expense these items was based on our determination that the acreage on which these wells was drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable.Basin.
Geological and geophysical costs. Geological and geophysical costs in 2018, 2017 and 2016 were primarily related to the portion of the purchase of seismic data related to unproved acreage in the Delaware Basin.
Impairment of Properties and Equipment
The following table sets forth the major components of our impairmentsimpairment of properties and equipment expense:for the periods presented:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (in millions) |
| Impairment of proved and unproved properties | $ | 0.4 | | | $ | 881.2 | | | $ | 10.6 | |
| Impairment of infrastructure and other | — | | | 1.2 | | | 27.9 | |
| Total impairment of properties and equipment | $ | 0.4 | | | $ | 882.4 | | | $ | 38.5 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in millions) |
| | | | | |
| Impairment of proved and unproved properties | $ | 458.4 |
| | $ | 285.5 |
| | $ | 5.6 |
|
| Amortization of individually insignificant unproved properties | — |
| | 0.4 |
| | 1.4 |
|
| Land and buildings | — |
| | — |
| | 3.0 |
|
| Total impairment of properties and equipment | $ | 458.4 |
| | $ | 285.9 |
| | $ | 10.0 |
|
Impairment ofThere were no significant impairment charges recognized related to our proved and unproved properties. Amounts represent the retirementoil and gas properties in 2021. If crude oil prices decline, or expiration of certain leases that are no longer part ofwe change other estimates impacting future net cash flows (e.g. reserves, price differentials, future operating and/or development costs), our development plan or that we do not planproved and unproved oil and gas properties could be subject to extend and will allow to expire. Deterioration of commodity prices or other operating circumstances could resultadditional impairments in additional impairment charges.future periods.
During 2018,the first quarter of 2020, we recorded impairment charges totaling $458.4of $881.1 million as we identified currentto our proved and anticipated leasehold expirations within the Western Culberson County area of the Delaware Basin and made the determination that we would no longer pursue plans to develop these properties. The impaired non-focus leaseholds typically have a higher gas to oil ratio and a greater degree of geologic complexity than our other Delaware Basin properties. In 2019, we expect that we will allow approximately 18,300 gross (17,900 net) acres of our leaseholds in the Delaware Basin to expire. Of these leaseholds, we expect that approximately 9,500 gross and net acres and 8,600 gross (8,000 net) acres will expire in the first and third quarters, respectively, of 2019. Taking all expected 2019 expirations into account, we anticipate ending 2019 with approximately 40,100 gross (33,500 net) acresunproved properties in the Delaware Basin. In 2020, we expect that we will allow approximately 3,400 gross (1,800 net)
acres of our leaseholds in the Delaware Basin to expire. We are currently exploring strategic alternatives with respect to the acres expected to expire in 2019 and 2020 and believe that we may be able to monetize a portion of this acreage.
During 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin, as referenced previously. We then assessed the impact of the dry holes and various factors related thereto, including the operational and geologic data obtained, the current increased cost environment for drilling and completion services in the Delaware Basin, our future commodity price outlook and the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during 2017. The amount of the impairment was based on the value assigned to individual lease acres in the final purchase price allocation of our Delaware Basin acquisition. This allocation included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. We recorded approximately $29 million of additional lease impairments in the Delaware Basin and an impairment charge of $2.1 million related to the Utica Shale Divestiture. Due to the aforementioned events and circumstances, we also evaluated our proved property for possible impairment and concluded that no further impairments were necessary at that time.
Impairment of Goodwill
During 2017, we recorded goodwillThese impairment charges of $75.1 million resulting from the purchase price allocation of the assets acquired in the Delaware Basin. The impairment was primarilywere due to a combination of increasessignificant decline in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin subsequent to the acquisition. In conjunction with our then-current lower future commodity price outlook, we determined thatcrude oil prices, which was considered a triggering event had occurred in the quarter ended September 30, 2017.that required us to assess our crude oil and natural gas properties for possible impairment.
General and Administrative Expense
General and administrative expense increased 42 percentdecreased to $170.5$127.7 million in 20182021 compared to 2017. The increase was$161.1 million in 2020 primarily attributabledue to a $16.1$30.0 million increase in payrolltransaction and employee benefits, a $14.0 million increasetransition costs incurred in legal related costs, a $9.2 million increase in government relations expenses and a $6.3 million increase2020 related to professional services. These increases were partially offset by a $0.9 million decrease related to environmental matters.
Generalthe SRC Acquisition and administrative expense increased seven percent to $120.4 million in 2017 compared to 2016. The increase was primarily attributable to an $8.1 million increase in payroll and employee benefits, a $4.4 million increase related to professional services, a $4.2 million increase in legal related costs, a $1.4 million increase in software licenses and subscriptions and a $1.3 million increase for the rental of additional office space. The increases were partially offset by the $12.2 million of legal and professionalconsultant fees related to the acquisition in the Delaware Basin that were incurred in 2016.our ERP implementation of $5.3 million.
Depreciation, Depletion and Amortization Expense
Crude oil and natural gas properties. During 2018, 20172021 and 2016,2020, we invested $982.7 million, $788.0$583.6 million and $396.4$522.3 million, netrespectively, exclusive of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties, respectively.DD&Aproperties. 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 $551.3 million, $462.5$627.5 million and $413.1$611.0 million in 2018, 20172021 and 2016,2020, respectively. The increase in total DD&A expense was primarily due to an increase in production volumes as our weighted average depletion rate between periods was comparable. The decrease in weighted average depletion rate during 2021 compared to 2020 was driven by an increase in proved reserves in our Wattenberg Field as a result of improved commodity prices during 2021.
The year-over-year changeschange in DD&A expense for related to crude oil and natural gas properties werewas primarily due to the following:
| | | | | | | | |
| | Year Ended December 31, |
| | 2021 |
| | (in millions) |
| Increase in production | | $ | 24.8 | |
| Decrease in weighted average depreciation, depletion and amortization rates | | (8.3) | |
| Total decrease in DD&A expense related to crude oil and natural gas properties | | $ | 16.5 | |
|
| | | | | | | | |
| | | Year Ended December 31, |
| | | 2018 - 2017 | | 2017 - 2016 |
| | | (in millions) |
| Increase in production | | $ | 127.9 |
| | $ | 144.7 |
|
| Decrease in weighted-average depreciation, depletion and amortization rates | | (39.1 | ) | | (95.3 | ) |
| Total increase in DD&A expense related to crude oil and natural gas properties | | $ | 88.8 |
| | $ | 49.4 |
|
The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties:properties for the periods presented:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| | (per Boe) |
| Operating Region/Area | | | | | | |
| Wattenberg Field | | $ | 8.68 | | | $ | 8.80 | | | $ | 11.77 | |
| Delaware Basin | | 9.59 | | | 9.68 | | | 16.76 | |
| Total weighted average DD&A expense rate | | 8.80 | | | 8.94 | | | 12.92 | |
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| Operating Region/Area | | 2018 | | 2017 | | 2016 |
| | (per Boe) |
| Wattenberg Field | | $ | 12.58 |
| | $ | 14.67 |
| | $ | 19.11 |
|
| Delaware Basin (1) | | 17.70 |
| | 14.89 |
| | 8.34 |
|
| Utica Shale (2) | | — |
| | 8.09 |
| | 10.66 |
|
| Total weighted-average | | 13.73 |
| | 14.53 |
| | 18.63 |
|
____________
(1) The 2016 Delaware Basin rate represents one month of DD&A expense. Accordingly,Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $7.7 million for the comparisons of the 2018 and 2017
rates to the 2016 rate are not meaningful.
(2) The Utica Shale properties were classified as held-for-sale during the third quarter of 2017; therefore, we did not record
DD&A expense on these properties in 2018. In March 2018, we completed the disposition of our Utica Shale properties.
Provision for Uncollectible Notes Receivable
In 2016, we recorded a provision for uncollectible notes receivable of $44.0 million to impair two third-party notes receivable whose collection was not reasonably assured. In April 2017, we signed a definitive agreement and simultaneously closed on the sale of one of the associated notes receivable to an unrelated third-party for $40.2 million. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during 2017.
Accretion of Asset Retirement Obligations
Accretion of asset retirement obligations for 2018 decreased 20 percent to $5.1 millionyear ended December 31, 2021, compared to 2017, and decreased 11 percent in 2017 to $6.3$8.7 million compared to 2016. The decreases in 2018 and 2017 were due tofor the replacement of vertical wells that have been plugged and abandoned with horizontal wells, which have a longer expected life.year ended December 31, 2020.
Interest Expense, net
Interest expense, net decreased by $8.0$6.0 million to $70.7$82.7 million in 20182021 compared to $78.7$88.7 million in 2017.2020. The decrease was primarily related to reduced borrowings under our revolving credit facility, a $38.1 million decrease in interest expense relating to the net settlementfull redemption of previously outstanding senior notes in December 2017our 2025 Senior Notes and a $4.2 million increase in capitalized interest. Thepartial redemption of our 2024 Senior Notes. These decreases were partially offset by a $32.2$6.1 million increase in interest expense related to the issuance of ouran additional $150 million aggregate principal amount of the 2026 Senior Notes in November 2017September 2020 and a $1.7$6.9 million increase in interest related to our revolving credit facility.
Interest expense increased by approximately $16.7 million to $78.7 million in 2017 compared to $62.0 million in 2016. The increase is primarily attributable to an $18.0 million increase in interest for the issuanceloss on extinguishment from partial redemption of our 2024 Senior Notes a $7.4 million increase in interest expense for the issuance of $200 million principal amountand full redemption of our 1.125% convertible notes due 2021 (the "2021 Convertible Notes") in September 2016, a $3.1 million increase in interest expense for the issuance of our 2026 Notes in November 2017 and a $3.0 million increase in the utilization fee of our revolving credit facility. The increases were partially offset by a $9.3 million charge for a bridge loan commitment related to the 2016 acquisition of properties in the Delaware Basin, a $3.5 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016 and a $1.8 million decrease in interest expense resulting from the net settlement of our 2022 Notes in December 2017.2025 Senior Notes.
Interest costs capitalized in 2018, 2017 and 2016 were $9.2 million, $5.0 million and $4.5 million, respectively.
Loss on Extinguishment of Debt
The $24.7 million loss on extinguishment of debt relates to the redemption of the 2022 Senior Notes during the fourth quarter of 2017. The loss consists of a $19.4 million make-whole premium and the write-off of unamortized debt issuance costs of $5.4 million.
Provision for Income Taxes
CurrentWe recorded income tax (expense)expense of $26.6 million for 2021 and an income tax benefit of $7.9 million for 2020, resulting in 2018, 2017effective tax rates of 4.8 percent and 2016 was $0.7 million, $8.2 million and $9.9 million, respectively. Current1.1 percent on the respective pre-tax income taxes generally relateor loss. 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 cashpre-tax loss due to the effect of a valuation allowance against our deferred income tax assets at December 31, 2021 and 2020.
The ultimate realization of deferred tax assets (“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 scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. The oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to continue to provide a valuation allowance against our DTAs as of December 31, 2021 and 2020 since we cannot conclude that it is paidmore likely than not that our DTAs will be fully realized in future periods.
Future events or recovered for income taxes associated withnew evidence which may lead us to conclude that it is more likely than not that our DTAs will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. Given recent improvements in oil and gas prices and improvements in our current earnings, we believe there is a reasonable possibility that, if oil and natural gas prices remain similar to December 31, 2021 pricing levels, sufficient positive evidence may become available within the applicable period. The remainingnext 12 months to allow us to reach a conclusion that all or a significant portion of the totalvaluation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax provisionexpense in
the period the release is comprisedrecorded. However, the exact timing and amount of deferredthe valuation allowance release are subject to change based on the level of profitability that we actually achieve.
Given recent improvements in oil and gas prices and assumptions based on our current production forecasts, we estimate that we will begin to incur cash federal and state income taxes which are a result of differencesagain in the timing of deductions from our U.S. GAAP presentation of financial statements2022 and the income tax regulations.2023.
Our effective income tax rates for 2018, 2017 and 2016 were 72.8 percent, 62.4 percent and 37.4 percent, respectively, on income (loss) from operations.
The 2018 rate differs from the federal statutory tax rate primarily due to state taxes, federal tax credits, valuation allowance for state tax attributes and nondeductible expenses that consist primarily of officers' compensation cost and government lobbying expenses.
The 2017 rate differs from the federal statutory rate primarily due to the reduction in the federal corporate income tax rate resulting from the 2017 Tax Cuts & Jobs Act ("The 2017 Act"), which increased the tax benefit rate by 33.7 percent. Additionally, the nondeductible goodwill impairment charge in 2017 reduced the 2017 tax rate by 7.7 percent. The 2017 tax rate was also impacted by state taxes.
The 2016 rate differs from the federal statutory tax rate, primarily due to state taxes and excess tax benefit from stock compensation, offset by nondeductible expenses that consist primarily of officers' compensation and government lobbying expenses.
As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions. We continue to voluntarily participate in the Internal Revenue Service’s ("IRS") Compliance Assurance Program (the "CAP Program") for the 2018 and 2019 tax years. We have received a partial acceptance notice from the IRS for our filed 2017 federal tax return and the IRS's post filing review is currently ongoing.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors resulting in changes inimpacting net income in 2018of $522.3 million and net loss of $724.3 million in 20172021 and 20162020, respectively, are discussed above. These same reasons similarly impacted adjusted
Adjusted net income, (loss), a non-U.S. GAAP financial measure, with the exception of the net
change in fair value of unsettled derivatives, adjusted for taxes, of $198.3 million, $13.1was $799.6 million and $208.9 million in 2018, 2017for the year ended December 31, 2021 and 2016, respectively. Adjustedadjusted net loss, a non-U.S. GAAP financial measure, was $196.3$625.3 million $114.4 million and $37.0 millionfor the year ended December 31, 2020. With the exception of the tax-affected (when applicable) net change in 2018, 2017 and 2016 respectively.fair value of unsettled derivatives, the same factors impacted adjusted net income (loss). See Reconciliation of Non-U.S. GAAP Financial Measures, below for a more detailed discussion of thisthese non-U.S. GAAP financial measure.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 fromraised in debt and equity capital market transactions and other sources, such as asset sales. In 2018, our net cash flows from operating activities were $889.3 million.
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. Due
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. From time to time, these activities may result in a decreasing leverage ratioworking capital deficit; however, we do not believe that we have recently experienced,our working capital deficit as of December 31, 2021 is an indication of a lack of liquidity. We had working capital deficits of $461.5 million and $471.6 million at December 31, 2021 and 2020, respectively. We intend to continue to manage our liquidity position by a variety of means, including through the percentagegeneration of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our expected future production that we currently have hedged is lower than we have historically maintained and we anticipate that this may remainanticipated sales through the case in the near future.
Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair valueuse of ouran active commodity derivative instruments and changes in our cash and cash equivalents due to our practicehedging program, utilization of utilizing excess cash to reduce the outstanding borrowingsborrowing capacity under our revolving credit facility. At December 31, 2018,facility and, if warranted, capital markets transactions from time to time.
From time to time, we had a working capital deficitmay seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of $166.6 million compared to a working capital deficit of $16.4 million at December 31, 2017. The decreaseother debt or equity securities, in working capital as of December 31, 2018 is primarily the result of a decrease in cash and cash equivalents of $179.3 million related to the Bayswater Asset Acquisition, partially offset by an increase in accounts payable of $31.8 million related to increased development and exploration activity.open market purchases, privately negotiated transactions or otherwise.
Liquidity
Our cash and cash equivalents were $1.4$33.8 million at December 31, 20182021 and availability under our revolving credit facility was $1.3$1.48 billion, providing for total liquidity of $1.3$1.51 billion as of December 31, 2018. Assuming a NYMEX2021. 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 and working capital obligations. As commodity prices improve, 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.
On February 26, 2022, we entered into the Acquisition Agreement to acquire Great Western for approximately $1.3 billion, inclusive of Great Western’s net debt. Under the terms of the Acquisition Agreement, the purchase price of $50.00,the Great Western Acquisition will consist of approximately 4.0 million shares of our common stock and approximately $543 million in cash. The cash portion of the purchase price is expected to be funded through a combination of cash on hand and availability under our revolving credit facility. We expect the Great Western Acquisition to be completed in the second quarter of 2022, subject to certain customary closing conditions.
Upon closing the Great Western Acquisition, we will be required to pay off and terminate Great Western’s revolving credit facility, which had an outstanding balance of $242.0 million as of December 31, 2021. At closing, we are also expecting to pay off Great Western’s $311.9 million 12.0% Senior Notes due September 1, 2025, plus a redemption premium. The payments of the debt balances will be funded through the availability under our revolving credit facility.
Based on our current production forecast for 2022, we expect 2022 cash flows from operations, which are net of expected cash federal and state income taxes, to exceed our capital investments in crude oil and natural gas properties in 2019 by approximately $25.0 million. We anticipate that capital investments will exceed cash flows from operations during the first half of 2019 and expect cash flows from operations to exceed capital investment during the remainder of the year. Our leverage ratio, as defined in our revolving credit facility agreement, is currently expected to decrease to approximately 1.3 by the end of 2019$1.1 billion. In addition, based on anticipated production and $50.00 to $55.00 NYMEX crude oil prices.
We are in the process of actively marketing our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets for sale and currently expect to execute agreements for the sales of these assets in the first half of 2019. We anticipate making capital investments for midstream assets during 2019, a portion of which would be made prior to such anticipated sales depending on the timing of the divestitures. We expect that we would recover a portion of these expenditures upon settlement of the final sale prices.
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 revolving credit facility is available for working capitalmaterial cash requirements capital investments, acquisitions, to support letters of creditgreater than twelve months from various contractual and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable obligations include 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 crude oil and natural gas interests. consolidated financial statements included elsewhere in this report.
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 to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:3.5:1.0. 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. Additionally, the current ratio covenant calculation allows us to exclude 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, 2018,2021, we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.3:3.1:1.0 and a leverage ratio of 1.4:0.6:1.0.
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.
The indentures governing our 2024 Senior Notes and 2026 Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt including under our revolving credit facility, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. See the footnote titled Long-Term Debt to the accompanying consolidated financial statements included elsewhere in this report for more information regarding our revolving credit facility.
Cash Flows
Our cash flows from operating, investing and financing activities are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Year ended December 31, |
| | 2021 | | 2020 | | 2019 |
| | (in thousands) |
| Cash flows from operating activities | | $ | 1,547,796 | | | $ | 870,079 | | | $ | 858,226 | |
| Cash flows from investing activities | | (578,804) | | | (687,159) | | | (677,772) | |
| Cash flows from financing activities | | (937,786) | | | (181,260) | | | (188,890) | |
| Net increase (decrease) in cash and cash equivalents | | $ | 31,206 | | | $ | 1,660 | | | $ | (8,436) | |
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 provided byfrom operating activities increased by $291.5$677.7 million to $889.3$1,547.8 million in 20182021 as compared to 2017,$870.1 million in 2020. The increase between periods was primarily due to thea $1.4 billion increase in crude oil, natural gas and NGLs sales, of $476.9a $33.4 million decrease in general and an increase inadministrative expense, and changes in assets and liabilitiesthe timing of $65.1 million. Thevendor payments. These increases were partially offset by $410.2 million in cash settlement losses on commodity derivatives in 2021 compared to $279.3 million in cash receipts from derivative settlements in 2020, a decrease$105.8 million increase in derivative commodity settlements of $128.9 million and increases in general and administrative expense of $50.1 million, lease operating expenses of $41.3 million and production taxes of $29.6 million.
Cash flows provided by operating activities increased by $111.6 million to $597.8 million in 2017 as compared to 2016, primarily due to the increase in crude oil, natural gas, and NGLs sales of $415.7 million. The increase was partially offset
by a decrease in derivative commodity settlements of $194.8 million and increases in lease operating expenses of $29.7 million,
production taxes of $29.3 million, interest expense of $16.7 million, transportation, gathering, and processing expenses of
$14.8 million, and increases in general and administrative expense of $7.9 million as well as a decrease in changes in assetsthe timing of receivable collections between periods.
and liabilities of $13.0 million.
Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $226.3$611.0 million in 20182021 to $808.4$1,532.6 million and increased by $115.3from $921.6 million in 2017 to $582.1 million, when compared to the respective prior years. These changes were2020. The increase was primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to changes intiming of cash payments and receipts of assets and liabilities.
Adjusted EBITDAX,free cash flow, a non-U.S.non-U.S GAAP financial measure, increased by $186.2$549.7 million in 20182021 to $868.3$949.0 million from $682.1$399.3 million in 2017,2020. The increase was primarily as the result ofdue to the increase in crude oil, natural gas and NGLs sales of $476.9 million. This increase was partially offset by a decrease in derivative commodity settlements of $128.9 million, an increase in general and administrative expense of $50.1 million, an increase in leasecash flows from operating expenses of $41.3 million, the sale of the note described below in 2017 to a third-party for $40.2 million, and an increase in production taxes of $29.6 million.activities, as discussed above.
Adjusted EBITDAX, a non-U.S. GAAP financial measure, increased by $222.3 million in 2017 to $682.1 million
from $459.8 million in 2016, primarily as the result of the increase in crude oil, natural gas, and NGLs sales of $415.7 million,
as well as the recording of a provision for a note receivable in 2016 of $44.0 million and the subsequent sale of the note in
2017 to a third-party for $40.2 million. The increase was partially offset by a decrease in derivative commodity settlements of
$194.8 million, and increases in lease operating expenses of $29.7 million, production taxes of $29.3 million, interest expense
of $16.7 million, transportation, gathering, and processing expenses of $14.8 million, and general and administrative expense
of $7.9 million.
See Item 7. 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 ourthese measures to the most comparable U.S. GAAP to non-U.S. GAAP financial measures.
Investing Activities. BecauseAs crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to investcommit significant amounts of capital in order to maintain and grow our production and replace our crude oil and natural reserves. If capital markets areis 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 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 $1.1 billion$578.8 million during 20182021 was primarily related to the purchase price of the Bayswater Asset Acquisition of $179.0 million and our drilling operations, includingand completion activities of $946.4 million. Partially offsetting these investments was$583.1 million, partially offset by $5.1 million in proceeds from the receiptsale of approximately $39.0 million related to the divestiture of our Utica Shale properties.certain properties and equipment.
Net cash used in investing activities of $687.2 million during 2017 of $717.0 million2020 was primarily related to cash utilized for our drilling operations, includingand completion activities of $737.2 million, a $21.0 million deposit toward the Bayswater Asset Acquisition, purchases of short-term investments of $49.9$551.0 million and a $9.3 million deposit with a third-party transportation service provider for surety of an existing firm transportation obligation. Partially offsetting these investments was the receipt of approximately $49.9$139.8 million related to the saleclosing of short-term investments, $40.2the SRC Acquisition.
Financing Activities. Net cash used in financing activities in 2021 of $937.8 million fromwas primarily due to (i) net repayments on our credit facility of $168.0 million, (ii) redemption and retirement of our 2021 Convertible Notes and 2025 Senior Notes for $200 million and $105.5 million, respectively, (iii) partial redemption and retirement of our 2024 Senior Notes for $203.1 million, (iv) the salerepurchase of a promissory note3.8 million shares of our common stock for $156.8 million pursuant to our Stock Repurchase Program and $5.4(v) dividend payments totaling $83.6 million. Repurchases of our common stock may extend into 2023 based on current market conditions, although our board of directors could elect to suspend or terminate the program at any time, including if certain share price parameters are not achieved. As of December 31, 2021, $187.3 million relatedout of the approved $525 million remained available for repurchases under the program. In February 2022, our board of directors increased the size of the program to post-closing settlements$1.25 billion, which we anticipate fully utilizing by December 31, 2023. Future repurchases of properties acquired in 2016.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.
Net cash used in investing activities during 2016 of $1.5 billion was primarily related to cash utilized for our acquisition in the Delaware Basin of $1.1 billion and $436.9 million for our drilling operations.
Financing Activities. Net cash from financing activities in 20182020 of $18.1$181.3 million was comprisedprimarily due to the redemption of a portion of the 2025 Senior Notes totaling $452.2 million, the repurchase and retirement of shares of our common stock totaling $23.8 million pursuant to the Stock Repurchase Program and $9.3 million related to purchases of our stock for employee stock-based compensation tax withholding obligations. These financing cash outflows were financed by our net borrowings from our credit facility of $32.5$164 million, partially offset by $7.7 million of debt issuance costs and $5.1 million related to purchases of our stock.
Net cash from financing activities in 2017 of $65.0 million was primarily related to $592.4 million of net proceeds from issuance of the 2026 Senior Notes, partially offset by the $519.4 million used to redeem our 2022 Senior Notes.
Net cash from financing activities in 2016 of $1.3 billion was primarily related to the $855.1 million of net proceeds received from the issuance of 9.42026 Senior Notes of $148.5 million shares ofand cash flows from operating activities.
Subsidiary Guarantor
PDC Permian, Inc., a Delaware corporation (the “Guarantor”), our common stock, $392.2 million of net proceeds from issuance of thewholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes and $193.9 million of net proceeds from issuance of2026 Senior Notes (collectively, the 2021 Convertible“Senior Notes”). The Guarantor holds our assets located in the Delaware Basin. The Senior Notes partially offsetare fully and unconditionally guaranteed on a joint and several basis by the $115.0 million paymentGuarantor. The guarantees are subject to release in limited circumstances only upon the maturityoccurrence of certain customary conditions.
The indentures governing the 2016 ConvertibleSenior Notes contain customary restrictive covenants that, among other things, limit our ability and net paymentsthe ability of approximately $37.0 million to pay down amounts borrowedour restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility.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.
Contractual Obligations and Contingent Commitments
The following table presents our contractual obligations and contingent commitmentssummarized subsidiary guarantor financial information has been prepared on the same basis of accounting as of December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Payments due by period |
| | | | | Less than | | 1-3 | | 3-5 | | More than |
| Contractual Obligations and Contingent Commitments | | Total | | 1 year | | years | | years | | 5 years |
| | | (in millions) |
| Long-term liabilities reflected on the consolidated balance sheet (1) | | | | | | | | | | |
| Long-term debt (2) | | $ | 1,233 |
| | $ | — |
| | $ | 200 |
| | $ | 33 |
| | $ | 1,000 |
|
| Commodity derivative contracts (3) | | 5 |
| | 3 |
| | 2 |
| | — |
| | — |
|
| Production tax liability | | 122 |
| | 61 |
| | 61 |
| | — |
| | — |
|
| Deferred oil gathering credit | | 24 |
| | 2 |
| | 5 |
| | 5 |
| | 12 |
|
| Asset retirement obligations | | 111 |
| | 26 |
| | 39 |
| | 39 |
| | 7 |
|
| Other liabilities (4) | | 10 |
| | 3 |
| | 5 |
| | 1 |
| | 1 |
|
| | | 1,505 |
| | 95 |
| | 312 |
| | 78 |
| | 1,020 |
|
| | | | | | | | | | | |
| Commitments, contingencies and other arrangements (5) | | | | | | | | | | |
| Interest on long-term debt (6) | | 457 |
| | 67 |
| | 135 |
| | 127 |
| | 128 |
|
| Operating leases | | 28 |
| | 6 |
| | 13 |
| | 7 |
| | 2 |
|
| Firm transportation and processing agreements (7) | | 430 |
| | 107 |
| | 152 |
| | 124 |
| | 47 |
|
| | | 915 |
| | 180 |
| | 300 |
| | 258 |
| | 177 |
|
| Total | | $ | 2,420 |
| | $ | 275 |
| | $ | 612 |
| | $ | 336 |
| | $ | 1,197 |
|
| | | | | | | | | | | |
__________
| |
(1) | Table does not include deferred income tax liability to taxing authorities of $198.1 million due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. |
| |
(2) | Amount presented does not agree with the consolidated balance sheets in that it excludes $22.8 million of unamortized debt discount and $14.9 million of unamortized debt issuance costs. |
| |
(3) | Represents our gross liability related to the fair value of derivative positions. |
| |
(4) | Includes deferred compensation to former executive officers, deferred payments related to firm transportation agreements and capital leases. |
| |
(5) | The table does not include termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. |
| |
(6) | Amounts presented include $276.0 million to the holders of our 2026 Senior Notes, $147.0 million to the holders of our 2024 Senior Notes and $6.8 million payable to the holders of our 2021 Convertible Notes. Amounts also include interest of $21.0 million related to unutilized commitments at a rate of 0.375 percent per annum. |
| |
(7) | Represents our gross commitment which includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. This includes anticipated and estimated commitments associated with two new gas processing facilities by our primarymid-stream provider. The timing of such payments has been estimated and is subject to change based on the completion of construction and the commencement of operations by the midstream provider.
|
From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. Information regarding our legal proceedings can be found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewherestatements. Investments in this report.subsidiaries are accounted for under the equity method.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of/Year Ended December 31, |
| | 2021 | | 2020 |
| | Issuer | | Guarantor | | Issuer | | Guarantor |
| | (in millions) |
| Assets | | | | | | | | |
| Current assets | | $ | 402.6 | | | $ | 56.0 | | | $ | 271.4 | | | $ | (57.8) | |
| Intercompany accounts receivable, guarantor subsidiary | | — | | | 40.8 | | | 107.3 | | | — | |
| Investment in guarantor subsidiary | | 1,767.2 | | | — | | | 1,767.2 | | | — | |
| Properties and equipment, net | | 3,875.0 | | | 939.9 | | | 3,982.1 | | | 877.1 | |
| Other non-current assets | | 58.5 | | | 4.8 | | | 56.6 | | | 4.3 | |
| | | | | | | | |
| Liabilities | | | | | | | | |
| Current liabilities | | $ | 862.5 | | | $ | 57.6 | | | $ | 751.3 | | | $ | 28.5 | |
| Intercompany accounts payable | | 27.9 | | | — | | | — | | | 94.2 | |
| Long-term debt | | 942.1 | | | — | | | 1,409.5 | | | — | |
| Other non-current liabilities | | 392.3 | | | 172.0 | | | 254.9 | | | 178.1 | |
| | | | | | | | |
| Statement of Operations | | | | | | | | |
| Crude oil, natural gas and NGLs sales | | $ | 2,163.1 | | | $ | 389.5 | | | $ | 968.8 | | | $ | 183.7 | |
| Commodity price risk management gain (loss), net | | (701.5) | | | — | | | 180.3 | | | — | |
| Total revenues | | 1,464.5 | | | 391.4 | | | 1,151.5 | | | 182.5 | |
| Production costs | | 892.4 | | | 189.0 | | | 740.7 | | | 177.5 | |
Gross profit (1) | | 1,270.7 | | | 200.4 | | | 228.1 | | | 6.2 | |
| Impairment of properties and equipment | | 0.4 | | | — | | | 2.0 | | | 880.4 | |
| Net income (loss) | | 327.7 | | | 194.9 | | | (49.2) | | | (670.0) | |
____________
(1)Gross profit is calculated as crude oil, natural gas and NGLs sales less production costs.
Critical Accounting Policies and Estimates
We have identified the following policies as critical to business operationsThe discussion and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the presentationanalysis of our financial positioncondition and results of operations and we may use significant judgment in their application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trendsupon our consolidated financial statements, which have been prepared in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the applicationaccordance with U.S. GAAP. The preparation of these statements requires us to make certain assumptions, judgments and otherestimates 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 see the footnote titled are described in Note 2 - Summary of Significant Accounting Policies to our consolidated financial statements 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 Properties. Reserve Quantities
We account for our crude oil and natural gas properties under the successful efforts method of accounting. CostsUnder this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depletedThe successful efforts method inherently relies on the unit-of-production method based on estimatedestimation of proved crude oil, natural gas and NGL reserves.
Annually, we engage independent petroleum engineers to prepare In determining the estimates of reserve and economic evaluations, management utilizes independent petroleum engineers. Reserve quantities and the related estimates of allfuture net cash flows are used as inputs in our calculation of depletion, evaluation of proved
properties on a well-by-well basis asfor impairment, assessment of December 31. We adjustexpected realizability of our crude oildeferred income tax assets and natural gas reserves for major acquisitions, new drilling and divestitures duringcalculation of the year as needed. 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 future production 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 in existingto reserve estimates occur. Although every reasonable effort isas 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 to ensure thatprospectively. In addition, a decline in reserve estimates reported representmay impact the outcome of our most accurate assessments possible,assessment of proved and unproved properties for impairment. Impairments are recorded in the subjective decisions and variancesperiod in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense,which they are identified.
We cannot reasonably predict future commodity prices. However, assuming all other factors are held constant, we performed a change in our estimated reserves could have an effectsensitivity analysis on our net income (loss).
Exploration costs, including geological and geophysical expenses, the acquisitionproved reserve estimates as of seismic data covering unproved acreage and delay rentals, are chargedDecember 31, 2021, to expense as incurred. Exploratory well drilling costs, including the costpresent a decrease of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as longapproximately 10 percent in crude oil price as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as a "suspended well" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is applied.
Acquisition costs of unproved properties are capitalized when incurred until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of crude oil influences the value of our proved reserves and PV-10 most significantly. Our proved reserve quantities would decrease by 4.3 MMBoe (1%) and our PV-10 of our proved reserves would decrease by $1.1 billion (11%). During 2021, we had positive revisions to our proved reserve quantities of 52.9 MMBoe as a result of higher average prices for crude oil, natural gas properties. The amountand NGLs. During 2020 and 2019, we had negative revisions of impairment recognized on unproved properties which are not individually significant is determined by amortizing39.5 and 16.5 MMBoe, respectively, 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 statementsincluded in Item 8. Financial Statements and Supplementary Data included elsewhere in this report.
Impairment of Crude Oil and Natural Gas Properties
Upon a triggering event, we assess the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of properties and equipment. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.
We assess our proved crude oil and natural gas properties for possible impairment annually, or upon a triggering event, 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 reasonably estimate the commoditiescommodity will be sold. Any impairment in value is charged to impairment of properties and equipment. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event, and therefore, a reduction inIf carrying values exceed undiscounted future net cash flows, and anthe measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. We estimate the fair value of ourproved crude oil and natural gas properties. 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, as well as 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 NGLs Sales Revenue Recognition. Crudeunproved properties during the year ended December 31, 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 the significant decline in crude oil natural gasprices.
Valuation of Business Combinations
We follow the acquisition method of accounting for business combinations. Assets acquired and NGLs revenuesliabilities assumed are recognized when we have transferred controlat the date of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially allacquisition at their respective estimated fair values. Any excess of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on
the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded.
Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels ofpurchase price over the fair value hierarchy. The lowest level input that is significantamounts assigned to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability and may affect the valuation of the assets and liabilities and their placement withinis 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 estimating the fair value hierarchy levels. The three levelsvalues of inputs that may be used to measure fair value are defined as:
Level 1 – Quoted prices (unadjusted) for identical assets oracquired and liabilities in active markets.
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable forassumed the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.
Commodity Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based on a pricing model that utilizes market-based inputs, including but not limitedmost significant assumptions relate to the contractual price of the underlying position, current market prices,estimated fair values assigned to proved and unproved crude oil and natural gas forward curves, discount rates suchproperties. To estimate the fair values of these properties as the LIBOR curve for a similar durationpart of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing onacquisition accounting, we estimate the fair value of commodity derivative liabilitiesproved crude oil and the effect of our counterparties' credit standings on the fair value of commodity derivative assets. Bothnatural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the model are based on published credit default swap ratesvaluation of proved crude oil and the duration of each outstanding commodity derivative position.
We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions.
Net settlements on our commodity derivative instruments are initially recorded to accounts receivable or payable, as applicable, and may not be received from or paid to counterparties to our commodity derivative contracts within the same accounting period. Such settlements typically occur the month following the maturity of the commodity derivative instrument. We have evaluated the credit risk of the counterparties holding our commodity derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding commodity derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our commodity derivative instruments is not significant.
Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments andnatural gas properties include estimates of both amountreserves volumes, future operating and timing. The judgments used in applying these policies aredevelopment costs, future commodity prices, and a market based on our evaluationweighted average cost of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates.
Accounting for Business Combinations. We utilize the purchase method to accountcapital rate. Additionally, for acquisitions of businesses and assets. The value of the purchase consideration takes into account the degree to which the consideration is objective and measurable such as cash consideration paid to a seller. With the issuance of equity, restrictions upon the sale of the issued stock are taken into consideration. Pursuant to purchase method accounting,with significant unproved properties, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, wemay 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.
In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value.
If applicable, we record deferred taxes for any differences between theEstimated fair values assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis ofto assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may changecan have a significant effect on results of operations in the future as additional information becomes known.
Acreage Exchanges. From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achievefuture. A higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value withassigned to a related gainproperty results in a higher depletion expense, which results in lower net earnings. This increases the likelihood of impairment if future commodity prices or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement.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. There were no business combinations during the year ended December 31, 2021.
Recent Accounting StandardsPronouncements
See the footnote titled SummaryThere were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of Significant Accounting Policies - Recently Adopted Accounting Standards to our consolidated financial statements included elsewhere in this report.December 31, 2021.
Reconciliation of Non-U.S. GAAP Financial Measures
We use "adjusted“adjusted cash flows from operations," "adjustedoperations”, “adjusted free cash flow (deficit)”, “adjusted net income (loss)"” and "adjusted EBITDAX,"“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. Also, inIn 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. operations and adjusted free cash flow (deficit). We definebelieve adjusted cash flows from operations ascan provide additional transparency into the drivers of trends in our operating cash flows, earned or incurred fromsuch as production, realized sales prices and operating activities, without regard to changes incosts, as it disregards the timing of settlement of operating assets and liabilities. We believe itadjusted 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 important to consider adjusteda supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations as well asbecause it excludes certain required cash flowsexpenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from operations, as wethe 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 it oftenthat 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 moreadditional transparency into what drives the changes in our operating trends, such as production, realized sales prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has generally been a timing issue from one period to the next as we have not had significant accounts receivable collection problems, nor been unable to purchase assets or pay our obligations.
Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effect. We
believederivative contracts, because it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard todisregards changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of our unsettled derivatives. Additionally, other items whichcommodity derivative contracts, and these changes are not indicativedirectly reflective of future results may be excluded to clearly identifyour operating trends.performance.
Adjusted EBITDAX. We definebelieve that adjusted EBITDAX as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of properties and equipment, exploration, geologic and geophysical expense, depreciation, depletion and amortization expense, accretion of asset retirement obligations and non-cash stock-based compensation, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDAX is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), and should not be considered an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDAX includes certain non-cash costs incurred by us and does not takeprovides additional transparency into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDAX differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDAX is relevanttrends because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts, and others to analyze such things as:
operating performance and return on capital as compared to our peers;
reflects the financial performance of our assets and our valuation without regard to financing methods, capital structure, accounting methods or historical cost basis;
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; andobligations.
the viability of acquisition opportunities and capital expenditure projects, including the related rate of return.
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'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:measure for the periods presented:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (thousands) |
| Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow: | | | | | |
| Net cash from operating activities | $ | 1,547.8 | | | $ | 870.1 | | | $ | 858.2 | |
| Changes in assets and liabilities | (15.2) | | | 51.5 | | | (32.8) | |
| Adjusted cash flows from operations | 1,532.6 | | | 921.6 | | | 825.4 | |
| Capital expenditures for development of crude oil and natural gas properties | (583.1) | | | (551.0) | | | (855.9) | |
| Change in accounts payable related to capital expenditures for oil and gas development activities | (0.5) | | | 28.7 | | | 68.2 | |
| Adjusted free cash flow | $ | 949.0 | | | $ | 399.3 | | | $ | 37.7 | |
| | | | | |
| Net income (loss) to adjusted net income (loss): | | | | | |
| Net income (loss) | $ | 522.3 | | | $ | (724.3) | | | $ | (56.7) | |
| Loss (gain) on commodity derivative instruments | 701.5 | | | (180.3) | | | 162.8 | |
| Net settlements on commodity derivative instruments | (410.2) | | | 279.3 | | | (17.6) | |
Tax effect of above adjustments (1) | (14.0) | | | — | | | (35.2) | |
| Adjusted net income (loss) | $ | 799.6 | | | $ | (625.3) | | | $ | 53.3 | |
| | | | | |
| Net income (loss) to adjusted EBITDAX: | | | | | |
| Net income (loss) | $ | 522.3 | | | $ | (724.3) | | | $ | (56.7) | |
| Loss (gain) on commodity derivative instruments | 701.5 | | | (180.3) | | | 162.8 | |
| Net settlements on commodity derivative instruments | (410.2) | | | 279.3 | | | (17.6) | |
| Non-cash stock-based compensation | 23.0 | | | 22.2 | | | 23.8 | |
| Interest expense, net | 82.7 | | | 88.7 | | | 71.1 | |
| Income tax expense (benefit) | 26.6 | | | (7.9) | | | (3.3) | |
| Impairment of properties and equipment | 0.4 | | | 882.4 | | | 38.5 | |
| Exploration, geologic and geophysical expense | 1.1 | | | 1.4 | | | 4.1 | |
| Depreciation, depletion and amortization | 635.2 | | | 619.7 | | | 644.2 | |
| Accretion of asset retirement obligations | 12.1 | | | 10.1 | | | 6.1 | |
| Loss (gain) on sale of properties and equipment | (0.9) | | | (0.7) | | | 9.7 | |
| Adjusted EBITDAX | $ | 1,593.8 | | | $ | 990.6 | | | $ | 882.7 | |
| | | | | |
| Cash from operating activities to adjusted EBITDAX: | | | | | |
| Net cash from operating activities | $ | 1,547.8 | | | $ | 870.1 | | | $ | 858.2 | |
Interest expense, net (2) | 75.8 | | | 88.7 | | | 71.1 | |
| Amortization and write-off of debt discount, premium and issuance costs | (13.5) | | | (16.8) | | | (13.6) | |
| Exploration, geologic and geophysical expense | 1.1 | | | 1.4 | | | 4.1 | |
| Other | (2.2) | | | (4.3) | | | (4.3) | |
| Changes in assets and liabilities | (15.2) | | | 51.5 | | | (32.8) | |
| Adjusted EBITDAX | $ | 1,593.8 | | | $ | 990.6 | | | $ | 882.7 | |
| | | | | |
| PV-10: | | | | | |
| Standardized measure of discounted future net cash flows | $ | 7,908.2 | | | $ | 3,282.2 | | | $ | 3,310.3 | |
| Present value of estimated future income tax discounted at 10% | 1,800.6 | | | 172.4 | | | 526.7 | |
| PV-10 | $ | 9,708.8 | | | $ | 3,454.6 | | | $ | 3,837.0 | |
_____________
(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.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in millions) |
| Adjusted cash flows from operations: | | | | | |
| Net cash from operating activities | $ | 889.3 |
| | $ | 597.8 |
| | $ | 486.3 |
|
| Changes in assets and liabilities | (80.9 | ) | | (15.7 | ) | | (19.5 | ) |
| Adjusted cash flows from operations | $ | 808.4 |
| | $ | 582.1 |
| | $ | 466.8 |
|
| | | | | | |
| Adjusted net loss: | | | | | |
| Net income (loss) | $ | 2.0 |
| | $ | (127.5 | ) | | $ | (245.9 | ) |
| (Gain) loss on commodity derivative instruments | (145.2 | ) | | 3.9 |
| | 125.7 |
|
| Net settlements on commodity derivative instruments | (115.5 | ) | | 13.3 |
| | 208.1 |
|
| Tax effect of above adjustments | 62.4 |
| | (4.1 | ) | | (124.9 | ) |
| Adjusted net loss | $ | (196.3 | ) | | $ | (114.4 | ) | | $ | (37.0 | ) |
| | | | | | |
| Net income (loss) to adjusted EBITDAX: | | | | | |
| Net income (loss) | $ | 2.0 |
| | $ | (127.5 | ) | | $ | (245.9 | ) |
| (Gain) loss on commodity derivative instruments | (145.2 | ) | | 3.9 |
| | 125.7 |
|
| Net settlements on commodity derivative instruments | (115.5 | ) | | 13.3 |
| | 208.1 |
|
| Non-cash stock-based compensation | 21.8 |
| | 19.4 |
| | 19.5 |
|
| Interest expense, net | 70.3 |
| | 76.4 |
| | 61.0 |
|
| Income tax expense (benefit) | 5.4 |
| | (211.9 | ) | | (147.2 | ) |
| Impairment of properties and equipment | 458.4 |
| | 285.9 |
| | 10.0 |
|
| Impairment of goodwill | — |
| | 75.1 |
| | — |
|
| Exploration, geologic and geophysical expense | 6.2 |
| | 47.3 |
| | 4.7 |
|
| Depreciation, depletion and amortization | 559.8 |
| | 469.1 |
| | 416.9 |
|
| Accretion of asset retirement obligations | 5.1 |
| | 6.4 |
| | 7.0 |
|
| Loss on extinguishment of debt | — |
| | 24.7 |
| | — |
|
| Adjusted EBITDAX | $ | 868.3 |
| | $ | 682.1 |
| | $ | 459.8 |
|
| | | | | | |
| Cash from operating activities to adjusted EBITDAX: | | | | | |
| Net cash from operating activities | $ | 889.3 |
| | $ | 597.8 |
| | $ | 486.3 |
|
| Interest expense, net | 70.3 |
| | 76.4 |
| | 61.0 |
|
| Amortization of debt discount and issuance costs | (12.8 | ) | | (12.9 | ) | | (16.2 | ) |
| Gain (loss) on sale of properties and equipment | (0.4 | ) | | 0.7 |
| | — |
|
| Exploration, geologic and geophysical expense | 6.2 |
| | 47.3 |
| | 4.7 |
|
| Exploratory dry hole expense | (0.1 | ) | | (41.3 | ) | | — |
|
| Other | (3.3 | ) | | 29.8 |
| | (56.5 | ) |
| Changes in assets and liabilities | (80.9 | ) | | (15.7 | ) | | (19.5 | ) |
| Adjusted EBITDAX | $ | 868.3 |
| | $ | 682.1 |
| | $ | 459.8 |
|
| | | | | | |
| PV-10: | | | | | |
| PV-10 | $ | 5,321.3 |
| | $ | 3,212.0 |
| | $ | 1,675.0 |
|
| Present value of estimated future income tax discounted at 10% | (873.6 | ) | | (331.9 | ) | | (254.4 | ) |
| Standardized measure of discounted future net cash flows | $ | 4,447.7 |
| | $ | 2,880.1 |
| | $ | 1,420.6 |
|
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market-Sensitive Instruments and Risk Management
We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks.
Interest Rate Risk
Changes in interest rates affect the amount of interest we earn on our interest bearing cash, and cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes and 2026 Senior Notes have fixed rates, and therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.
As of December 31, 2018, our interest-bearing deposit accounts included money market accounts and checking accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2018 was $0.6 million, with a weighted-average interest rate of one percent. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2018 and assuming2021, we had $0.6 millionno outstanding throughout the period, we estimate that a one percent increase in interest rates would not have a material impact on interest income for the twelve months ended December 31, 2018.
As of December 31, 2018, we had $32.5 million outstanding balance onborrowings under our revolving credit facility. If market interest rates would have decreased by one percent, our interest expense for the twelve months ended December 31, 2018 would have decreased by approximately $0.3 million. If market interest rates would have increased by one percent, our interest expense for the twelve months ended December 31, 2018 would have increased by approximately $0.2 million.
Commodity Price Risk
We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, natural gas basis and NGLs. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas and propane prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives.
Our realized prices vary regionally based on local market differentials andAs of December 31, 2021, we had a net liability derivative position of $367.3 million related to our transportation agreements. The following table presents average market index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas and NGLs production:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 |
| Average NYMEX Index Price: | | | |
| Crude oil (per Bbl) | | | |
| NYMEX | $ | 64.77 |
| | $ | 50.95 |
|
| Natural gas (per MMBtu) | | | |
| NYMEX | $ | 3.09 |
| | $ | 3.11 |
|
| | | | |
| Average Sales Price Realized: | | | |
| Excluding net settlements on commodity derivatives | | | |
| Crude oil (per Bbl) | $ | 61.19 |
| | $ | 48.45 |
|
| Natural gas (per Mcf) | 1.85 |
| | 2.21 |
|
| NGLs (per Bbl) | 22.14 |
| | 18.59 |
|
commodity price risk derivatives. Based on a sensitivity analysis as of December 31, 2018,2021, we estimate that a 10 percent increase in
natural gas, crude oil prices and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in a decreasean increase in the fair value of our net derivative positionsliabilities of $63.1$85.1 million, whereas a 10 percent decrease in prices would have resulted in an increasea decrease in fair value of $63.9our net derivatives liabilities of $82.5 million. The potential increase in the fair value of our net derivative liabilities would be recorded our consolidated statements of operations as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties.exposure. When exposed to significant credit risk, we analyze the counterparties’counterparty’s financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure financial performance by our counterparties.
Our oil and gas exploration and production business's crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers.
Amounts due to our gas marketing business are from a diverse group of entities. The underlying operations of these entities are geographically concentrated in the same region, which increases the credit risk associated with this business. As natural gas prices continue to remain depressed, certain third-party producers committed to providing natural gas to our gas marketing business continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. We have initiated several legal actions for breach of contract and collection claims against certain third-party producers that are delinquent in their payment obligations. We expect this trend to continue for this business segment.
We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. See
Our crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. We do not require our customers to post collateral, and the footnote titled Commodity Derivative Financial Instrumentsinability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our consolidated financial statements included elsewhere in this reportresults. For the year ended December 31, 2021, three customers each accounted for more detail onthan 10% of our commodity derivative financial instruments.sales. For each of the years ended December 31, 2020 and 2019, four customers each accounted for more than 10%
of our sales. No other customer accounted for more than 10% of our sales during these periods. Our allowances for credit losses were insignificant as of December 31, 2021.
Disclosure of Limitations
Because the information above included only those exposures that existed at December 31, 2018,2021, it does not consider those exposures or positions which could arise after that date. OurAs a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
| | | | | | | |
| Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information |
| | |
| Financial Statements: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Supplemental Information - Unaudited: | | |
| | |
| | |
| | |
| Financial Statement Schedule: | | |
| | |
| | |
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and ShareholdersStockholders of PDC Energy, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of PDC Energy, Inc. and its subsidiaries (the “Company”) as of December 31, 20182021 and 2017,2020, and the related consolidated statements of operations, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2018,2021, including the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018,2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20182021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company did not maintain,maintained, in all material respects, effective internal control over financial reporting as of December 31, 20182021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO because material weaknesses in internal control over financial reporting existed as of that date related to not maintaining a sufficient complement of personnel within the Land Department as a result of an increased volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of land administrative records associated with unproved leases.COSO.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses referred to above are described in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. We considered these material weaknesses in determining the nature, timing, and extent of audit tests applied in our audit of the 2018 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.
Change in Accounting Principle
As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for revenues from contracts with customers in 2018.
Basis for Opinions
The Company'sCompany’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in management's report referred to above.Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company'sCompany’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil and Natural Gas Reserves on Proved Crude Oil and Natural Gas Properties, Net
As described in Notes 2 and 8 to the consolidated financial statements, the Company’s proved crude oil and natural gas properties balance was $8,310 million as of December 31, 2021, and depreciation, depletion, and amortization (DD&A) expense for the period ended December 31, 2021 was $635.2 million. As disclosed by management, 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 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, revisions in existing reserve estimates occur. The Company accounts for crude oil and natural gas properties under the successful efforts method of accounting. 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. Reserve estimates are prepared by internal and external engineers (collectively “specialists”).
The principal considerations for our determination that performing procedures relating to the impact of proved crude oil and natural gas reserves on proved crude oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved crude oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved crude oil and natural gas reserves related to reserves volumes and the assumptions applied to the data related to future operating and development costs, and commodity prices.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved crude oil and natural gas reserves. The work of specialists was used in performing the procedures to evaluate the reasonableness of the reserve volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ results. These procedures also included, among others, testing the completeness and accuracy of data related to reserves volumes, future operating and development costs, and commodity prices. Additionally, these procedures included evaluating whether the assumptions applied to the aforementioned data were reasonable considering the past performance of the Company.
/s/PricewaterhouseCoopers LLP
Denver, Colorado
February 27, 201928, 2022
We have served as the Company’s auditor since 2007.
PDC ENERGY, INC.
Consolidated Balance Sheets
(in thousands, except share and per share data)
| | | | | | | | | | | | | | |
| | December 31, |
| | 2021 | | 2020 |
| Assets | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 33,829 | | | $ | 2,623 | |
| Accounts receivable, net | | 398,605 | | | 244,251 | |
| Fair value of derivatives | | 17,909 | | | 48,869 | |
| Prepaid expenses and other current assets | | 8,230 | | | 12,505 | |
| Total current assets | | 458,573 | | | 308,248 | |
| Properties and equipment, net | | 4,814,865 | | | 4,859,199 | |
| Fair value of derivatives | | 15,177 | | | 9,565 | |
| Other assets | | 48,051 | | | 60,961 | |
| Total Assets | | $ | 5,336,666 | | | $ | 5,237,973 | |
| | | | |
| Liabilities and Stockholders’ Equity | | | | |
| Liabilities | | | | |
| Current liabilities: | | | | |
| Accounts payable | | $ | 127,891 | | | $ | 90,635 | |
| Production tax liability | | 99,583 | | | 124,475 | |
| Fair value of derivatives | | 304,870 | | | 98,152 | |
| Funds held for distribution | | 285,861 | | | 177,132 | |
| Accrued interest payable | | 10,482 | | | 14,734 | |
| Other accrued expenses | | 91,409 | | | 81,715 | |
| Current portion of long-term debt | | — | | | 193,014 | |
| Total current liabilities | | 920,096 | | | 779,857 | |
| Long-term debt | | 942,084 | | | 1,409,548 | |
| Asset retirement obligations | | 127,526 | | | 132,637 | |
| | | | |
| Fair value of derivatives | | 95,561 | | | 36,359 | |
| Deferred income taxes | | 26,383 | | | — | |
| Other liabilities | | 314,769 | | | 264,034 | |
| Total liabilities | | 2,426,419 | | | 2,622,435 | |
| | | | |
| Commitments and contingent liabilities | | 0 | | 0 |
| | | | |
| Stockholders’ equity | | | | |
| Common shares - par value $0.01 per share, 150,000,000 authorized, 96,468,071 and 99,758,720 issued as of December 31, 2021 and 2020, respectively | | 965 | | | 998 | |
| Additional paid-in capital | | 3,161,941 | | | 3,387,754 | |
| Accumulated deficit | | (249,954) | | | (772,265) | |
| Treasury shares - at cost, 54,960 and 37,510 as of December 31, 2021 and 2020, respectively | | (2,705) | | | (949) | |
| Total stockholders’ equity | | 2,910,247 | | | 2,615,538 | |
| Total Liabilities and Stockholders’ Equity | | $ | 5,336,666 | | | $ | 5,237,973 | |
See accompanying Notes to Consolidated Financial Statements
68
|
| | | | | | | | |
| As of December 31, | | 2018 | | 2017 |
| Assets | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 1,398 |
| | $ | 180,675 |
|
| Accounts receivable, net | | 181,434 |
| | 197,598 |
|
| Fair value of derivatives | | 84,492 |
| | 14,338 |
|
| Prepaid expenses and other current assets | | 7,136 |
| | 8,613 |
|
| Total current assets | | 274,460 |
| | 401,224 |
|
| Properties and equipment, net | | 4,002,862 |
| | 3,933,467 |
|
| Assets held-for-sale | | 140,705 |
| | 40,583 |
|
| Fair value of derivatives | | 93,722 |
| | — |
|
| Other assets | | 32,396 |
| | 45,116 |
|
| Total Assets | | $ | 4,544,145 |
| | $ | 4,420,390 |
|
| | | | | |
| Liabilities and Stockholders' Equity | | | | |
| Liabilities | | | | |
| Current liabilities: | | | | |
| Accounts payable | | $ | 181,864 |
| | $ | 150,067 |
|
| Production tax liability | | 60,719 |
| | 37,654 |
|
| Fair value of derivatives | | 3,364 |
| | 79,302 |
|
| Funds held for distribution | | 105,784 |
| | 95,811 |
|
| Accrued interest payable | | 14,150 |
| | 11,815 |
|
| Other accrued expenses | | 75,133 |
| | 42,987 |
|
| Total current liabilities | | 441,014 |
| | 417,636 |
|
| Long-term debt | | 1,194,876 |
| | 1,151,932 |
|
| Deferred income taxes | | 198,096 |
| | 191,992 |
|
| Asset retirement obligations | | 85,312 |
| | 71,006 |
|
| Liabilities held-for-sale | | 4,111 |
| | 499 |
|
| Fair value of derivatives | | 1,364 |
| | 22,343 |
|
| Other liabilities | | 92,664 |
| | 57,333 |
|
| Total liabilities | | 2,017,437 |
| | 1,912,741 |
|
| | | | | |
| Commitments and contingent liabilities | | | | |
| | | | | |
| Stockholders' equity | | | | |
| Common shares - par value $0.01 per share, 150,000,000 authorized, 66,148,609 and 65,955,080 issued as of December 31, 2018 and 2017, respectively | | 661 |
| | 659 |
|
| Additional paid-in capital | | 2,519,423 |
| | 2,503,294 |
|
| Retained earnings | | 8,727 |
| | 6,704 |
|
| Treasury shares - at cost, 45,220 and 55,927 as of December 31, 2018 and 2017, respectively | | (2,103 | ) | | (3,008 | ) |
| Total stockholders' equity | | 2,526,708 |
| | 2,507,649 |
|
| Total Liabilities and Stockholders' Equity | | $ | 4,544,145 |
| | $ | 4,420,390 |
|
| | | | | |
PDC ENERGY, INC.
Consolidated Statements of Operations
(in thousands, except per share data)
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| Revenues | | | | | | |
| Crude oil, natural gas and NGLs sales | | $ | 2,552,558 | | | $ | 1,152,555 | | | $ | 1,307,275 | |
| Commodity price risk management gain (loss), net | | (701,456) | | | 180,270 | | | (162,844) | |
| Other income | | 4,808 | | | 6,401 | | | 11,692 | |
| Total revenues | | 1,855,910 | | | 1,339,226 | | | 1,156,123 | |
| Costs, expenses and other | | | | | | |
| Lease operating expense | | 180,659 | | | 161,346 | | | 142,248 | |
| Production taxes | | 165,209 | | | 59,368 | | | 80,754 | |
| Transportation, gathering and processing expense | | 100,403 | | | 77,835 | | | 46,353 | |
| Exploration, geologic and geophysical expense | | 1,064 | | | 1,376 | | | 4,054 | |
| General and administrative expense | | 127,733 | | | 161,087 | | | 161,753 | |
| Depreciation, depletion and amortization | | 635,184 | | | 619,739 | | | 644,152 | |
| Accretion of asset retirement obligations | | 12,086 | | | 10,072 | | | 6,117 | |
| Impairment of properties and equipment | | 402 | | | 882,393 | | | 38,536 | |
| Loss (gain) on sale of properties and equipment | | (912) | | | (724) | | | 9,734 | |
| | | | | | |
| Other expense | | 2,490 | | | 10,272 | | | 11,317 | |
| Total costs, expenses and other | | 1,224,318 | | | 1,982,764 | | | 1,145,018 | |
| Income (loss) from operations | | 631,592 | | | (643,538) | | | 11,105 | |
| | | | | | |
| Interest expense, net | | (82,698) | | | (88,684) | | | (71,099) | |
| Income (loss) before income taxes | | 548,894 | | | (732,222) | | | (59,994) | |
| Income tax benefit (expense) | | (26,583) | | | 7,902 | | | 3,322 | |
| Net income (loss) | | $ | 522,311 | | | $ | (724,320) | | | $ | (56,672) | |
| | | | | | |
| Earnings (loss) per share | | | | | | |
| Basic | | $ | 5.30 | | | $ | (7.37) | | | $ | (0.89) | |
| Diluted | | 5.22 | | | (7.37) | | | (0.89) | |
| | | | | | |
| Weighted-average common shares outstanding | | | | | | |
| Basic | | 98,546 | | | 98,251 | | | 64,032 | |
| Diluted | | 100,154 | | | 98,251 | | | 64,032 | |
| | | | | | |
| | | | | | |
See accompanying Notes to Consolidated Financial Statements
69
|
| | | | | | | | | | | | |
| Year Ended December 31, | | 2018 | | 2017 | | 2016 |
| Revenues | | | | | | |
| Crude oil, natural gas and NGLs sales | | $ | 1,389,961 |
| | $ | 913,084 |
| | $ | 497,353 |
|
| Commodity price risk management gain (loss), net | | 145,237 |
| | (3,936 | ) | | (125,681 | ) |
| Other income | | 13,461 |
| | 12,468 |
| | 11,243 |
|
| Total revenues | | 1,548,659 |
| | 921,616 |
| | 382,915 |
|
| Costs, expenses and other | | | | | | |
| Lease operating expenses | | 130,957 |
| | 89,641 |
| | 59,950 |
|
| Production taxes | | 90,357 |
| | 60,717 |
| | 31,410 |
|
| Transportation, gathering and processing expenses | | 37,403 |
| | 33,220 |
| | 18,415 |
|
| Exploration, geologic and geophysical expense | | 6,204 |
| | 47,334 |
| | 4,669 |
|
| Impairment of properties and equipment | | 458,397 |
| | 285,887 |
| | 9,973 |
|
| Impairment of goodwill | | — |
| | 75,121 |
| | — |
|
| General and administrative expense | | 170,504 |
| | 120,370 |
| | 112,470 |
|
| Depreciation, depletion and amortization | | 559,793 |
| | 469,084 |
| | 416,874 |
|
| Accretion of asset retirement obligations | | 5,075 |
| | 6,306 |
| | 7,080 |
|
| (Gain) loss on sale of properties and equipment | | 394 |
| | (766 | ) | | (43 | ) |
| Provision for uncollectible notes receivable | | — |
| | (40,203 | ) | | 44,038 |
|
| Other expenses | | 11,829 |
| | 13,157 |
| | 10,193 |
|
| Total costs, expenses and other | | 1,470,913 |
| | 1,159,868 |
| | 715,029 |
|
| Income (loss) from operations | | 77,746 |
| | (238,252 | ) | | (332,114 | ) |
| Loss on extinguishment of debt | | — |
| | (24,747 | ) | | — |
|
| Interest expense | | (70,730 | ) | | (78,694 | ) | | (61,972 | ) |
| Interest income | | 413 |
| | 2,261 |
| | 963 |
|
| Income (loss) before income taxes | | 7,429 |
| | (339,432 | ) | | (393,123 | ) |
| Income tax (expense) benefit | | (5,406 | ) | | 211,928 |
| | 147,195 |
|
| Net income (loss) | | $ | 2,023 |
| | $ | (127,504 | ) | | $ | (245,928 | ) |
| | | | | | | |
| Earnings per share: | | | | | | |
| Basic | | $ | 0.03 |
| | $ | (1.94 | ) | | $ | (5.01 | ) |
| Diluted | | $ | 0.03 |
| | $ | (1.94 | ) | | $ | (5.01 | ) |
| | | | | | | |
| Weighted-average common shares outstanding: | | | | | | |
| Basic | | 66,059 |
| | 65,837 |
| | 49,052 |
|
| Diluted | | 66,303 |
| | 65,837 |
| | 49,052 |
|
| | | | | | | |
PDC ENERGY, INC.
Consolidated Statements of Cash Flows
(in thousands)
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| Cash flows from operating activities: | | | | | | |
| Net income (loss) | | $ | 522,311 | | | $ | (724,320) | | | $ | (56,672) | |
| Adjustments to net income (loss) to reconcile to net cash from operating activities: | | | | | | |
| Net change in fair value of unsettled commodity derivatives | | 291,268 | | | 99,001 | | | 145,246 | |
| Depreciation, depletion and amortization | | 635,184 | | | 619,739 | | | 644,152 | |
| Impairment of properties and equipment | | 402 | | | 882,393 | | | 38,536 | |
| Accretion of asset retirement obligations | | 12,086 | | | 10,072 | | | 6,117 | |
| Non-cash stock-based compensation | | 23,023 | | | 22,200 | | | 23,837 | |
| (Gain) loss on sale of properties and equipment | | (912) | | | (724) | | | 9,734 | |
| Amortization and write-off of debt discount, premium and issuance costs | | 13,468 | | | 16,772 | | | 13,575 | |
| Loss from extinguishment of debt | | 6,927 | | | — | | | — | |
| Deferred income taxes | | 26,383 | | | (6,530) | | | (2,256) | |
| Other | | 2,451 | | | 3,004 | | | 3,155 | |
| Changes in assets and liabilities: | | | | | | |
| Accounts receivable | | (153,717) | | | 139,664 | | | (88,304) | |
| Other assets | | 24,678 | | | (5,341) | | | (11,560) | |
| Production tax liability | | 41,381 | | | (50,803) | | | 22,240 | |
| Accounts payable and accrued expenses | | 40,183 | | | (66,183) | | | (29,578) | |
| Funds held for distribution | | 108,729 | | | (23,621) | | | (7,298) | |
| Asset retirement obligations | | (28,595) | | | (27,491) | | | (21,511) | |
| Other liabilities | | (17,454) | | | (17,753) | | | 168,813 | |
| Net cash from operating activities | | 1,547,796 | | | 870,079 | | | 858,226 | |
| Cash flows from investing activities: | | | | | | |
| Capital expenditures for development of crude oil and natural gas properties | | (583,108) | | | (550,964) | | | (855,908) | |
| Capital expenditures for other properties and equipment | | (894) | | | (1,634) | | | (20,839) | |
| Acquisition of crude oil and natural gas properties | | — | | | (139,812) | | | (13,207) | |
| Proceeds from sale of properties and equipment | | 5,073 | | | 1,641 | | | 2,105 | |
| Proceeds from divestitures | | 125 | | | 3,610 | | | 202,076 | |
| Restricted cash | | — | | | — | | | 8,001 | |
| Net cash from investing activities | | (578,804) | | | (687,159) | | | (677,772) | |
| Cash flows from financing activities: | | | | | | |
| Proceeds from revolving credit facility and other borrowings | | 802,800 | | | 1,799,350 | | | 1,577,000 | |
| Repayment of revolving credit facility and other borrowings | | (970,800) | | | (1,635,350) | | | (1,605,500) | |
| | | | | | |
| Proceeds from senior notes | | — | | | 148,500 | | | — | |
| Redemption of senior notes | | (308,584) | | | (452,153) | | | — | |
| Repayment of convertible notes | | (200,000) | | | — | | | — | |
| Payment of debt issuance costs | | (13,066) | | | (6,538) | | | (72) | |
| Purchase of treasury shares for employee stock-based compensation tax withholding obligations | | (6,038) | | | (9,345) | | | (4,003) | |
| Purchase of treasury shares under stock repurchase program | | (156,795) | | | (23,819) | | | (154,363) | |
| Dividends paid | | (83,615) | | | — | | | — | |
| Principal payments under financing lease obligations | | (1,688) | | | (1,905) | | | (1,952) | |
| Net cash from financing activities | | (937,786) | | | (181,260) | | | (188,890) | |
| Net change in cash and cash equivalents | | 31,206 | | | 1,660 | | | (8,436) | |
| Cash and cash equivalents, beginning of year | | 2,623 | | | 963 | | | 9,399 | |
| Cash and cash equivalents, end of year | | $ | 33,829 | | | $ | 2,623 | | | $ | 963 | |
See accompanying Notes to Consolidated Financial Statements
70
|
| | | | | | | | | | | | |
| Year Ended December 31, | | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities: | | | | | | |
| Net income (loss) | | $ | 2,023 |
| | $ | (127,504 | ) | | $ | (245,928 | ) |
| Adjustments to net income (loss) to reconcile to net cash from operating activities: | | | | | | |
| Net change in fair value of unsettled commodity derivatives | | (260,775 | ) | | 17,260 |
| | 333,770 |
|
| Depreciation, depletion and amortization | | 559,793 |
| | 469,084 |
| | 416,874 |
|
| Impairment of properties and equipment | | 458,397 |
| | 285,887 |
| | 9,973 |
|
| Impairment of goodwill | | — |
| | 75,121 |
| | — |
|
| Exploratory dry hole costs | | 113 |
| | 41,297 |
| | — |
|
| Provision for uncollectible notes receivable | | — |
| | (40,203 | ) | | 44,038 |
|
| Loss on extinguishment of debt | | — |
| | 24,747 |
| | — |
|
| Accretion of asset retirement obligations | | 5,075 |
| | 6,306 |
| | 7,080 |
|
| Non-cash stock-based compensation | | 21,782 |
| | 19,353 |
| | 19,502 |
|
| (Gain) loss on sale of properties and equipment | | 394 |
| | (766 | ) | | (43 | ) |
| Amortization of debt discount and issuance costs | | 12,769 |
| | 12,907 |
| | 16,167 |
|
| Deferred income taxes | | 6,105 |
| | (203,685 | ) | | (137,249 | ) |
| Other | | 2,763 |
| | 2,265 |
| | 2,603 |
|
| Total adjustments to net income (loss) to reconcile to net cash from operating activities: | | 806,416 |
| | 709,573 |
| | 712,715 |
|
| Changes in assets and liabilities: | | | | | | |
| Accounts receivable | | 12,025 |
| | (60,546 | ) | | (32,627 | ) |
| Other assets | | (81 | ) | | 3,364 |
| | 2,303 |
|
| Production tax liability | | 35,225 |
| | 31,316 |
| | 9,223 |
|
| Accounts payable and accrued expenses | | 16,261 |
| | 31,378 |
| | (162 | ) |
| Funds held for future distribution | | 9,973 |
| | 24,472 |
| | 36,510 |
|
| Asset retirement obligations | | (13,341 | ) | | (10,176 | ) | | (4,109 | ) |
| Other liabilities | | 20,801 |
| | (4,064 | ) | | 8,338 |
|
| Total changes in assets and liabilities | | 80,863 |
| | 15,744 |
| | 19,476 |
|
| Net cash from operating activities | | 889,302 |
| | 597,813 |
| | 486,263 |
|
| Cash flows from investing activities: | | | | | | |
| Capital expenditures for development of crude oil and natural gas properties | | (946,350 | ) | | (737,208 | ) | | (436,884 | ) |
| Capital expenditures for other properties and equipment | | (11,055 | ) | | (5,094 | ) | | (3,464 | ) |
| Acquisition of crude oil and natural gas properties | | (180,026 | ) | | (15,628 | ) | | (1,073,723 | ) |
| Proceeds from sale of properties and equipment | | 3,562 |
| | 9,991 |
| | 4,945 |
|
| Proceeds from divestiture | | 44,693 |
| | — |
| | — |
|
| Sale of promissory note | | — |
| | 40,203 |
| | — |
|
| Restricted cash | | 1,249 |
| | (9,250 | ) | | — |
|
| Sale of short-term investments | | — |
| | 49,890 |
| | — |
|
| Purchase of short-term investments | | — |
| | (49,890 | ) | | — |
|
| Net cash from investing activities | | (1,087,927 | ) | | (716,986 | ) | | (1,509,126 | ) |
| Cash flows from financing activities: | | | | | | |
| Proceeds from revolving credit facility | | 1,072,500 |
| | — |
| | 85,000 |
|
| Repayment of revolving credit facility | | (1,040,000 | ) | | — |
| | (122,000 | ) |
| Proceeds from issuance of equity, net of issuance costs | | — |
| | — |
| | 855,074 |
|
| Proceeds from issuance of senior notes | | — |
| | 592,366 |
| | 392,172 |
|
| Proceeds from issuance of convertible senior notes | | — |
| | — |
| | 193,935 |
|
| Redemption of senior notes | | — |
| | (519,375 | ) | | — |
|
| Redemption of convertible notes | | — |
| | — |
| | (115,000 | ) |
| Payment of debt issuance costs | | (7,704 | ) | | (50 | ) | | (15,556 | ) |
| Purchase of treasury shares | | (5,147 | ) | | (6,672 | ) | | (6,935 | ) |
| Other | | (1,550 | ) | | (1,271 | ) | | (577 | ) |
| Net cash from financing activities | | 18,099 |
| | 64,998 |
| | 1,266,113 |
|
| Net change in cash, cash equivalents and restricted cash | | (180,526 | ) | | (54,175 | ) | | 243,250 |
|
| Cash, cash equivalents and restricted cash, beginning of year | | 189,925 |
| | 244,100 |
| | 850 |
|
| Cash, cash equivalents and restricted cash, end of year | | $ | 9,399 |
| | $ | 189,925 |
| | $ | 244,100 |
|
PDC ENERGY, INC.
Consolidated Statements of Stockholders’ Equity
(in thousands, except share data)thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Additional Paid-in Capital | | Treasury Stock | | Retained Earnings (Accumulated Deficit) | | Total Stockholders’ Equity |
| | Shares | | Amount | | | Shares | | Amount | | |
| Balance at January 1, 2019 | | 66,149 | | | $ | 661 | | | $ | 2,519,423 | | | (45) | | | $ | (2,103) | | | $ | 8,727 | | | $ | 2,526,708 | |
| Net income (loss) | | — | | | — | | | — | | | — | | | — | | | (56,672) | | | (56,672) | |
| Stock-based compensation | | 213 | | | 2 | | | 23,835 | | | — | | | — | | | — | | | 23,837 | |
| Purchase of treasury shares for employee stock-based compensation tax withholding obligations | | — | | | — | | | — | | | (106) | | | (4,003) | | | — | | | (4,003) | |
| Retirement of treasury shares for employee stock-based compensation tax withholding obligations | | (4) | | | — | | | (127) | | | 4 | | | 127 | | | — | | | — | |
| Retirement of treasury shares | | (4,706) | | | (46) | | | (154,317) | | | 4,706 | | | 154,363 | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Issuance of treasury shares | | — | | | — | | | (4,505) | | | 112 | | | 4,505 | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Purchase of treasury shares under stock repurchase program | | — | | | — | | | — | | | (4,706) | | | (154,363) | | | — | | | (154,363) | |
| Balance at December 31, 2019 | | 61,652 | | | 617 | | | 2,384,309 | | | (35) | | | (1,474) | | | (47,945) | | | 2,335,507 | |
| Net income (loss) | | — | | | — | | | — | | | — | | | — | | | (724,320) | | | (724,320) | |
| Issuance pursuant to acquisition | | 39,182 | | | 391 | | | 1,014,921 | | | — | | | — | | | — | | | 1,015,312 | |
| Stock-based compensation | | 530 | | | 5 | | | 19,738 | | | — | | | 2,457 | | | — | | | 22,200 | |
| Purchase of treasury shares for employee stock-based compensation tax withholding obligations | | — | | | — | | | — | | | (457) | | | (9,345) | | | — | | | (9,345) | |
| Retirement of treasury shares for employee stock-based compensation tax withholding obligations | | (339) | | | (3) | | | (7,407) | | | 339 | | | 7,413 | | | — | | | 3 | |
| Retirement of treasury shares | | (1,266) | | | (12) | | | (23,807) | | | 1,266 | | | 23,819 | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Issuance of treasury shares | | — | | | — | | | — | | | 115 | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Purchase of treasury shares under stock repurchase program | | — | | | — | | | — | | | (1,266) | | | (23,819) | | | — | | | (23,819) | |
| Balance at December 31, 2020 | | 99,759 | | | 998 | | | 3,387,754 | | | (38) | | | (949) | | | (772,265) | | | 2,615,538 | |
| Net income (loss) | | — | | | — | | | — | | | — | | | — | | | 522,311 | | | 522,311 | |
| Stock-based compensation | | 531 | | | 5 | | | 20,831 | | | — | | | 2,187 | | | — | | | 23,023 | |
| Purchase of treasury shares for employee stock-based compensation tax withholding obligations | | — | | | — | | | — | | | (181) | | | (6,038) | | | — | | | (6,038) | |
| Retirement of treasury shares for employee stock-based compensation tax withholding obligations | | (117) | | | (1) | | | (4,156) | | | 117 | | | 4,157 | | | — | | | — | |
| Retirement of treasury shares | | (3,705) | | | (37) | | | (157,058) | | | 3,711 | | | 157,401 | | | — | | | 306 | |
| Issuance of treasury shares | | — | | | — | | | — | | | 89 | | | — | | | — | | | — | |
| Purchase of treasury shares under stock repurchase program | | — | | | — | | | — | | | (3,753) | | | (159,463) | | | — | | | (159,463) | |
| Dividends declared ($0.86 per share) | | — | | | — | | | (85,430) | | | — | | | — | | | — | | | (85,430) | |
| Balance at December 31, 2021 | | 96,468 | | | $ | 965 | | | $ | 3,161,941 | | | (55) | | | $ | (2,705) | | | $ | (249,954) | | | $ | 2,910,247 | |
See accompanying Notes to Consolidated Financial Statements
71
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | | | Treasury Stock | | | | |
| | Shares | | Amount | | Additional Paid-in Capital | | Shares | | Amount | | Retained Earnings | | Total Stockholders' Equity |
| | | | | | | | | | | | | | |
| Balances, January 1, 2016 | 40,174,776 |
| | $ | 402 |
| | $ | 907,382 |
| | (20,220 | ) | | $ | (1,009 | ) | | $ | 380,422 |
| | $ | 1,287,197 |
|
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | (245,928 | ) | | (245,928 | ) |
| Issuance pursuant to acquisition | 9,386,768 |
| | 94 |
| | 690,608 |
| | — |
| | — |
| | — |
| | 690,702 |
|
| Issuance pursuant to sale of equity | 15,007,500 |
| | 150 |
| | 854,933 |
| | — |
| | — |
| | — |
| | 855,083 |
|
| Convertible debt discount, net of issuance costs and tax | — |
| | — |
| | 23,518 |
| | — |
| | — |
| | — |
| | 23,518 |
|
| Purchase of treasury shares | — |
| | — |
| | — |
| | (116,085 | ) | | (6,935 | ) | | — |
| | (6,935 | ) |
| Issuance pursuant to note conversion | 792,406 |
| | 8 |
| | (8 | ) | | — |
| | — |
| | — |
| | — |
|
| Issuance of treasury shares | (114,697 | ) | | — |
| | (6,661 | ) | | 114,697 |
| | 6,661 |
| | — |
| | — |
|
| Non-employee directors' deferred compensation plan | — |
| | — |
| | — |
| | (7,155 | ) | | (385 | ) | | — |
| | (385 | ) |
| Issuance of stock awards, net of forfeitures | 411,731 |
| | 3 |
| | (3 | ) | | — |
| | — |
| | — |
| | — |
|
| Exercise of stock options | 46,084 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Stock-based compensation expense | — |
| | — |
| | 19,502 |
| | — |
| | — |
| | — |
| | 19,502 |
|
| Other | — |
| | — |
| | 286 |
| | — |
| | — |
| | (286 | ) | | — |
|
| Balances, December 31, 2016 | 65,704,568 |
| | $ | 657 |
| | $ | 2,489,557 |
| | (28,763 | ) | | $ | (1,668 | ) | | $ | 134,208 |
| | $ | 2,622,754 |
|
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | (127,504 | ) | | (127,504 | ) |
| Purchase of treasury shares | — |
| | — |
| | — |
| | (107,357 | ) | | (6,672 | ) | | — |
| | (6,672 | ) |
| Issuance of treasury shares | — |
| | | | (5,517 | ) | | 83,228 |
| | 5,517 |
| | — |
| | — |
|
| Non-employee directors' deferred compensation plan | — |
| | — |
| | — |
| | (3,035 | ) | | (185 | ) | | — |
| | (185 | ) |
| Issuance of stock awards, net of forfeitures | 250,512 |
| | 2 |
| | (2 | ) | | — |
| | — |
| | — |
| | — |
|
| Stock-based compensation expense | — |
| | — |
| | 19,353 |
| | — |
| | — |
| | — |
| | 19,353 |
|
| Other | — |
| | — |
| | (97 | ) | | — |
| | — |
| | — |
| | (97 | ) |
| Balances, December 31, 2017 | 65,955,080 |
| | $ | 659 |
| | $ | 2,503,294 |
| | (55,927 | ) | | $ | (3,008 | ) | | $ | 6,704 |
| | $ | 2,507,649 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 2,023 |
| | 2,023 |
|
| Purchase of treasury shares | — |
| | — |
| | — |
| | (102,647 | ) | | (5,147 | ) | | — |
| | (5,147 | ) |
| Issuance of treasury shares | — |
| | — |
| | (5,561 | ) | | 104,068 |
| | 5,561 |
| | — |
| | — |
|
| Non-employee directors' deferred compensation plan | — |
| | — |
| | — |
| | 9,286 |
| | 491 |
| | — |
| | 491 |
|
| Issuance of stock awards, net of forfeitures | 193,529 |
| | 2 |
| | (2 | ) | | — |
| | — |
| | — |
| | — |
|
| Stock-based compensation expense | — |
| | — |
| | 21,782 |
| | — |
| | — |
| | — |
| | 21,782 |
|
| Other | — |
| | — |
| | (90 | ) | | — |
| | — |
| | — |
| | (90 | ) |
| Balance, December 31, 2018 | 66,148,609 |
| | $ | 661 |
| | $ | 2,519,423 |
| | (45,220 | ) | | $ | (2,103 | ) | | $ | 8,727 |
| | $ | 2,526,708 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the rural areas of the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of December 31, 2018,2021, we owned an interest in approximately 2,9003,500 gross productive gross wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented.
The accompanying audited consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries andsubsidiaries. Pursuant to the proportionate consolidation method, our proportionateaccompanying consolidated financial statements include our pro rata share of our affiliated partnerships.assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.
The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased and exchanged businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets.
Certain immaterial reclassifications have been made to our prior period balance sheet to conform to the current period presentation. The reclassifications had no impact on previously reported results.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates in the Preparation of Financial Statements. The preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires us to make estimates and assumptions that affect the amounts reported on our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of proved oil and natural gas reserves used in calculating depletion; estimates of unpaid revenues and unbilled costs; future cash flows from proved oil and natural gas reserves on proved oil and natural gas properties used in impairment assessment; valuation of commodity derivative instruments; the estimation of future abandonment obligations used in asset retirement obligations; valuation of proved and unproved crude oil and natural gas properties from purchased and exchanged businesses and assets; and valuation of deferred income tax assets.
Cash and Cash Equivalents. We considerThe Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of federal deposit insurance limits as of December 31, 2021 and 2020. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our revolving credit facility.
Commodity Derivative Financial Instruments.We Our results of operations and operating cash flows are exposed to the effect ofaffected by changes in market fluctuations in the prices offor crude oil, natural gas and NGLs. We employ established policies and procedures toTo manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use ofexposure to price volatility from producing crude oil and natural gas we enter into commodity derivative instruments for speculative purposes.
Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value.contracts to protect against price declines in future periods. We have elected not to designate any of our commodity derivative instruments as cash flow hedges.hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the consolidated balance sheet. We have electedmeasure the normal purchase, normal sale exception forfair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assetsforward curves, discount rates, volatility factors and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. Net settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of commodity derivative instruments related to our Gas Marketing segment are recorded in other income and other expenses. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows.nonperformance risk.
The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Properties and Equipment.Significant accounting polices related to our properties and equipment are discussed below.
Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. CostsUnder this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. 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. 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
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
changing economic conditions. As a result, revisions in existing reserve estimates occur. Capitalized development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statement of operations as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A.
Exploration costs, including geologicgeological and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are charged to expenseexpensed as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have foundidentified a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded.
Unproved property costs not subject to depletion primarily include leasehold costs, broker and legal expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Leasehold costs are transferred into costs subject to depletion on an ongoing basis as these properties are evaluated and proved reserves are established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed.
Proved Property Impairment.Annually, or upon a triggering event, we assess the valuation of our producingproved 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 reasonably estimate the commoditiescommodity will be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. 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. The impairment recorded is the amount by which the carrying values exceed the fair value. Impairments are includedIn the impairment assessment 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 future production volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Certain events, including but not limited to downward revisions in the consolidated statementsestimates of operations line itemour reserve quantities, expectations of falling commodity prices or rising capital and operating costs, could result in a triggering event, and may result to a possible impairment of propertiesour proved crude oil and equipment, with a corresponding impact on accumulated DD&A.natural gas properties.
Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to impairment expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment.periodically, or if a triggering event is identified.
Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets'assets’ estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $7.7 million, $8.7 million and $5.7 million for the years ended December 31, 2021, 2020 and 2019, respectively.
We review these long-lived assetsother property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized infor the amount by which the carrying value of the asset exceeds theits fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment.value.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $8.5 million, $6.6 million and $3.8 million in 2018, 2017 and 2016, respectively.
Internal-Use Software. Certain internal-useInternal-use software costs incurred during the development stage of our enterprise resource planning software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensesexpensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2018, capitalized costs for internal-use software were not material.
Capitalized Interest. We did not have any capitalized internal-use software costs at December 31, 2017.
Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investmentscapitalize interest on expenditures made in unproved crude oilconnection with exploration and natural gas properties and major development projects on which DD&A expensethat are not subject to current depletion. Interest is not currently recorded and on which exploration or developmentcapitalized only for the period that activities are in progress qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs.bring unevaluated properties to its intended use. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $9.2$17.8 million, $5.0$19.7 million and $4.5$13.4 million in 2018, 2017during the year ended December 31, 2021, 2020 and 2016,2019, respectively.
Assets Held-for-Sale.Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considersWe consider historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected inon the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year.
Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property taxes, to be paid to the states and counties in which we produce crude oil, natural gas and NGLs. These taxes are expensed and included in the statements of operations line item production taxes. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $61.3 million and $50.5 million in December 31, 2018 and 2017, respectively.
Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred income tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred income tax assets and liabilities are measured using enacted tax rates.rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred income tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred income tax assets to what we consider realizable.
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Our policy is to recognize interest and penalties related to uncertain tax positions in interest expense.
Debt Issuance Costs. Costs and Discounts. Debt issuance costs and discounts are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt on the consolidated balance sheets and the debt issuance costs for the revolving credit facility are included in other assets on the consolidated balance sheets.assets.
Asset Retirement Obligations. We recognize the estimated liability for future costs associated with the plugging and abandonment of our oil and gas properties resulting from acquisition, construction or normal operation. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value.value (accretion expense). The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.cost (presented as part of properties and equipment). Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets.equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"(“APIC”), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred 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. We record sales revenuerevenues based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2018, 2017the years ending December 31, 2021, 2020 and 2016,2019, the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded.
Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross"“gross” method of accounting, depending upon the related 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 proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for 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 transport 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 expenses.
Credit Risk and Allowance for Doubtful Accounts. InherentFor our product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606 which states the Company is not required to our industrydisclose the transaction price allocated to the remaining performance obligations if the variable consideration is the concentration of crude oil, natural gas and NGLs salesallocated entirely to a limited numberwholly unsatisfied performance obligation. Under these sales contracts, monthly sales of customers. This concentration hasa product generally represent a separate performance obligation; therefore, future commodity volumes to be delivered and sold are wholly unsatisfied and disclosure of the potentialtransaction price allocated to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. Further, considerationsuch unsatisfied performance obligations is given to well production data for receivables related to well operations.not required.
Accounting for Business Combinations. We utilize the purchaseacquisition method to account for acquisitions of businesses. Pursuant to purchasethe acquisition method, accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respectiveon fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review recent 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; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties.
In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair value of these properties as part of acquisition accounting, we prepare estimatesestimate the fair value of proved crude oil and natural gas reserves. We estimateproperties using valuation techniques that convert future prices by usingcash flows to a single discounted amount. Significant inputs and assumptions to the applicable forward pricing strip to apply to our estimatevaluation of reserve quantities acquiredproved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted usingcommodity prices, and a market-based weighted-averagemarket based weighted average cost of capital rate determined appropriate at the time of the acquisition.rate. The market-based weighted-averagemarket based weighted average cost of capital rate is subject to additional project-specific riskrisking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of recent comparable purchased properties to determine an estimation of fair value.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill.liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Acreage Exchanges. From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providingprovide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement.
Stock-Based Compensation. Stock-based compensation is recognized inwithin our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vestingrequisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To
Fair Value of Assets and Liabilities. The Company follows the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the developmentauthoritative accounting guidance for measuring fair value of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations.
Recently Adopted Accounting Standards.
In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when or as each performance obligation is satisfied. We adopted the standard effective January 1, 2018 under the modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard had on our consolidated financial statements, we performed a comprehensive review of our significant revenue streams. The focus of this review included, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations and factors affecting the determination of the transaction price. We also reviewed our current accounting policies, procedures and controls with respect to these contracts and arrangements to determine what changes, if any, would be required by the adoption of the revenue standard. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. See the footnote below titled Revenue Recognition for further details regarding the changes in our revenue recognition resulting from the adoption of this standard.
In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that the statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Adoption of this standard impacted our consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the consolidated balance sheets at December 31, 2018 and 2017, which sum to the total of cash, cash equivalents and restricted cash in the consolidated statements of cash flows:
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| | (in thousands) |
| Cash and cash equivalents | $ | 1,398 |
| | $ | 180,675 |
|
| Restricted cash | 8,001 |
| | 9,250 |
|
| Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows | $ | 9,399 |
| | $ | 189,925 |
|
Restricted cash is included in other assets on the consolidated balance sheets at December 31, 2018 and December 31, 2017. We did not have any cash classified as restricted cash at December 31, 2016.
In August 2018, the FASB issued an accounting update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the third quarter of 2018. As of December 31, 2018, capitalized costs for internal-use software were not material.
In November 2018, the FASB issued an accounting update and amendments to clarify the interaction between collaborative contractual arrangements and the revenue recognition standard. The amendments in this update specify that transactions between participants in a collaborative arrangement should be accounted for under the revenue recognition standard when the counterparty is a customer and the guidance precludes entities from presenting consideration from a transaction in a collaborative arrangement as revenue from contracts with customers if the counterparty is not a customer for that transaction. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal periods, with early adoption permitted. We have elected to early adopt this standard in the fourth quarter of 2018. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary as adoption of this standard did not have an impact on our consolidated financial statements.
Recently Issued Accounting Standards
In February 2016, the FASB issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities onin its financial statements. Fair value is defined as the balance sheetprice that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and disclosing key information about related leasing arrangements (the “New Lease Standard”)minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). For leases with termsIn some cases, the inputs used to measure fair value might fall in different levels of morethe fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:
Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 – Inputs other than 12 months,quoted prices included within Level 1 that are either directly or indirectly observable for the accounting update requires lessees to recognizeasset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.
Leases. We determine if an arrangement is representative of a right-of-use ("ROU"lease at contract inception. Right-of-use (“ROU”) asset and lease liability for itsassets represent our right to use the underlying assetassets for the lease term and the corresponding lease obligation. Bothliabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assetassets and corresponding liability will initially be measuredliabilities are recognized at the commencement date based on the present value of the future minimumexpected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms of our leases include options to extend or terminate the lease only when we can ascertain that it is reasonably certain we will exercise that option. Leases with an initial term of one year or less are not recorded on the consolidated balance sheets.
We will make accounting policy elections to not recognize ROU assets and lease liabilitiesapply the practical expedient that arise from short-term leases and to not separatepermits combining lease and non-lease components for any class of underlying asset, as provided by practical expedients. In January 2018, the FASB also issued anin a contract and accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that if elected, would not require an organization to reconsider accounting for existing land easements that are not accounted for under the previouscombination as a single lease accounting standard. We will elect this practical expedient and accordingly, existing land easements will not be assessed. All new or modified land easementscomponent (applied by asset class).
NOTE 3 - PENDING ACQUISITION
On February 26, 2022, we entered into after January 1, 2019a definitive purchase agreement under which we will be evaluated underacquire Great Western Petroleum, LLC (“Great Western”) for approximately $1.3 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western is an independent oil and gas company focused on the New Lease Standard. The New Lease Standard does not apply to leasesexploration, production and development of mineral rights to explore for or use crude oil and natural gas. Wegas in Colorado. The purchase consideration for the Great Western Acquisition will adoptbe made through the New Lease standard and subsequent amendments effective January 1, 2019 under the modified retrospective approach for all active contracts as of December 31, 2018. Based upon our implementation progress to date, we expect the adoption of the New Lease Standard to result in increases to total assets and total liabilitiestransfer of approximately $20.04.0 million at January 1, 2019, with no adjustmentshares of our common stock and approximately $543 million in cash, pursuant to the opening balance of retained earnings.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Membership Interest Purchase Agreement that we entered into with Great Western (“Acquisition Agreement”). We expect the Great Western Acquisition to be completed in the second quarter of 2022, subject to certain customary closing conditions, including diligence.
NOTE 34 - BUSINESS COMBINATIONSCOMBINATION
In January 2018,2020, we closedmerged with SRC Energy, Inc. (“SRC”) in a transaction valued at $1.7 billion, inclusive of SRC’s net debt (the “SRC Acquisition”). SRC was an independent oil and natural gas company engaged in the exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in Weld County, Colorado. The acquisition added approximately 83,000 net acres which are located on large, contiguous acreage blocks in the core of properties from Bayswater Explorationthe Wattenberg Field.
Upon closing, we issued approximately 38.9 million shares of our common stock to SRC shareholders and Production LLC (the "Bayswater Asset Acquisition")holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for approximately $200.0 million in cash, after post-closing adjustments, including $21.0 million depositedeach outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the terms of the merger agreement that we entered into an escrow account in 2017. The $21.0 million deposit was included in other assetswith SRC. We finalized the purchase price allocation on our December 31, 2017 consolidated balance sheet. We acquired approximately 7,400 net acres, approximately 220 gross drilling locations2020, and 24 operated horizontal wells that were either DUCs or in-process wells atwe recognized total transaction costs of $19.9 million for the time of closing.year ended December 31, 2020.
The following table details our final purchase price, and allocation of the assets acquired and the liabilities assumed in the acquisition are presented below. Adjustments made subsequent to the preliminary purchase price stem from final settlement of the proceeds from operating activities and additional information we obtained about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and liabilities assumed. Such adjustments primarily relate to sales, operating expenses and capital costs from the effective date through closing.
The details of the final purchase pricevaluation and allocation of the purchase price forto the transaction, are presented below (in thousands):assets acquired and liabilities assumed as a result of the SRC Acquisition:
| | | | | | | | |
| | (in thousands) |
| Consideration: | | |
| Cash | | $ | 40 | |
| Retirement of seller’s credit facility | | 166,238 | |
| Total cash consideration | | 166,278 | |
| Common stock issued | | 1,009,015 | |
| Shares withheld in lieu of taxes | | 6,299 | |
| | |
| Total consideration | | $ | 1,181,592 | |
| | |
| Recognized amounts of identifiable assets acquired and liabilities assumed: | | |
| Assets acquired: | | |
| Current assets | | $ | 145,792 | |
| Properties and equipment, net - proved | | 1,613,674 | |
| Properties and equipment, net - unproved | | 109,615 | |
| Properties and equipment, net - other | | 16,242 | |
| Deferred tax asset | | 189,311 | |
| Other assets | | 11,810 | |
| Total assets acquired | | $ | 2,086,444 | |
| Liabilities assumed: | | |
| Current liabilities | | $ | (253,967) | |
| Senior notes | | (555,500) | |
| Asset retirement obligations | | (42,417) | |
| Other liabilities | | (52,968) | |
| Total liabilities assumed | | (904,852) | |
| Total identifiable net assets acquired | | $ | 1,181,592 | |
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | |
| | December 31, 2018 |
| Acquisition costs: | |
| Cash | $ | 168,560 |
|
| Deposit made in prior period | 21,000 |
|
| Total cash consideration | 189,560 |
|
| Other purchase price adjustments | 10,422 |
|
| Total acquisition costs | $ | 199,982 |
|
| | |
| Recognized amounts of identifiable assets acquired and liabilities assumed: | |
| Assets acquired: | |
| Current assets | $ | 468 |
|
| Crude oil and natural gas properties - proved | 205,834 |
|
| Other assets | 2,796 |
|
| Total assets acquired | 209,098 |
|
| Liabilities assumed: | |
| Current liabilities | (4,429 | ) |
| Asset retirement obligations | (4,687 | ) |
| Total liabilities assumed | (9,116 | ) |
| Total identifiable net assets acquired | $ | 199,982 |
|
This transactionacquisition was accounted for under the acquisition method.method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved and unproved crude oil and natural gas properties include estimates of reserves,reserve volumes, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations and a market-based weighted-average cost of capital rate. The allocationrate of the value to the underlying leases also requires significant judgment and is based on a combination of comparable market transactions, the term and conditions associated with the individual leases, our ability and intent to develop specific leases and our initial assessment of the underlying relative value of the leases given our knowledge of the geology at the time of closing.10 percent. These inputs require significant judgments and estimates by management at the time of the valuation.
The results of operations for the Bayswater AssetSRC Acquisition forsince the year ended December 31, 2018closing date have been included in our consolidated financial statements, including approximately $70.8 million of total revenue, $39.3 million of income from operations and $0.59 of dilutedearnings per share. Pro forma results of operations for the Bayswater Asset Acquisition showing results as if the acquisition had been completed as of January 1, 2017 would not have been material toon our consolidated financial statements for the year ended December 31, 2017.2020 and include approximately $320.9 million of total revenue, and $46.5 million of income from operations.
Pro Forma Information. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2020, and 2019, assuming the acquisition had been completed as of January 1, 2019. The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on available information and certain assumptions that we believe are reasonable, including (i) the Company’s common stock issued to convert SRC’s outstanding shares of common stock and equity awards, (ii) the depletion of SRC’s fair-valued proved oil and gas properties using the successful efforts method of accounting and (iii) the estimated tax impacts of the pro forma adjustments, if any. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company and SRC totaling approximately $38.0 million and $15.9 million for the years ended December 31, 2020 and 2019, respectively. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.
| | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2020 | | 2019 |
| | (in thousands, except per share data) |
| Total revenue | | $ | 1,361,051 | | | $ | 1,761,498 | |
| Net income (loss) | | (695,663) | | | 139,578 | |
| | | | |
| Earnings (loss) per share: | | | | |
| Basic | | $ | (6.97) | | | $ | 1.36 | |
| Diluted | | (6.97) | | | 1.35 | |
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 45 - REVENUE RECOGNITION
On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018, we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the New Revenue Standard to have a significant impact on our net income going forward.
Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the New Revenue Standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method.
As discussed above, we enter into agreements for the sale, transportation, gathering and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.
Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2018, 2017 and 2016 (in thousands):the periods presented:
| | | | | | | | | | | | | | | | Year Ended December 31, |
| | | Year Ended December 31, | |
| Revenue by Commodity and Operating Region | | 2018 | | 2017 (1) | | 2016 (1) | Revenue by Commodity and Operating Region | | | 2021 | | 2020 | | 2019 |
| | | | | (in thousands) |
| Crude oil | | | | | | | Crude oil | | | |
| Wattenberg Field | | $ | 783,158 |
| | $ | 529,562 |
| | $ | 329,168 |
| Wattenberg Field | | | $ | 1,275,666 | | | $ | 668,948 | | | $ | 767,760 | |
| Delaware Basin | | 252,107 |
| | 82,677 |
| | 3,918 |
| Delaware Basin | | | 255,135 | | | 147,902 | | | 252,929 | |
| Utica Shale (2) | | 2,696 |
| | 12,814 |
| | 15,769 |
| |
| Total | | $ | 1,037,961 |
| | $ | 625,053 |
| | $ | 348,855 |
| Total | | | 1,530,801 | | | 816,850 | | | 1,020,689 | |
| Natural gas | | | | | | | Natural gas | | | |
| Wattenberg Field | | $ | 130,073 |
| | $ | 131,792 |
| | $ | 86,633 |
| Wattenberg Field | | | 458,870 | | | 171,755 | | | 137,143 | |
| Delaware Basin | | 32,010 |
| | 21,251 |
| | 1,039 |
| Delaware Basin | | | 60,733 | | | 6,997 | | | 13,877 | |
| Utica Shale (2) | | 1,109 |
| | 5,216 |
| | 3,904 |
| |
| Total | | $ | 163,192 |
| | $ | 158,259 |
| | $ | 91,576 |
| Total | | | 519,603 | | | 178,752 | | | 151,020 | |
| NGLs | | | | | | | NGLs | | | |
| Wattenberg Field | | $ | 132,820 |
| | $ | 104,298 |
| | $ | 52,919 |
| Wattenberg Field | | | 428,570 | | | 128,126 | | | 94,347 | |
| Delaware Basin | | 55,148 |
| | 20,756 |
| | 645 |
| Delaware Basin | | | 73,584 | | | 28,827 | | | 41,219 | |
| Utica Shale (2) | | 840 |
| | 4,718 |
| | 3,358 |
| |
| Total | | $ | 188,808 |
| | $ | 129,772 |
| | $ | 56,922 |
| Total | | | 502,154 | | | 156,953 | | | 135,566 | |
| Revenue by Operating Region | | | | | | | |
| Crude oil, natural gas and NGLs | | Crude oil, natural gas and NGLs | | | |
| Wattenberg Field | | $ | 1,046,051 |
| | $ | 765,652 |
| | $ | 468,720 |
| Wattenberg Field | | | 2,163,106 | | | 968,829 | | | 999,250 | |
| Delaware Basin | | 339,265 |
| | 124,684 |
| | 5,602 |
| Delaware Basin | | | 389,452 | | | 183,726 | | | 308,025 | |
| Utica Shale (2) | | 4,645 |
| | 22,748 |
| | 23,031 |
| |
| Total | | $ | 1,389,961 |
| | $ | 913,084 |
| | $ | 497,353 |
| Total | | | $ | 2,552,558 | | | $ | 1,152,555 | | | $ | 1,307,275 | |
|
| | | | |
________________________________________ |
(1) | As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 |
| and 2016 have not been restated. Such changes would not have been material. |
(2) | In March 2018, we completed the disposition of our Utica Shale properties. |
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Contract Assets.Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. Generally, theThe intent of the payments is primarily to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are classified as long-term assets and included in other assets on ourthe consolidated balance sheet.sheets. The contract assets will beare amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer.
The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for year ended December 31, 2018:the periods presented:
|
| | | |
| | Amount |
| | (in thousands) |
| | |
| Beginning balance, January 1, 2018 | $ | 3,746 |
|
| Additions | 2,884 |
|
| Amortized as a reduction to crude oil, natural gas and NGLs sales | (3,096 | ) |
| Ending balance, December 31, 2018 | $ | 3,534 |
|
| | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| (in thousands) |
| Beginning balance | $ | 25,872 | | | $ | 11,494 | |
| Additions (Net reduction to additions previously recognized) | (7,705) | | | 16,739 | |
| Amortized as a reduction to crude oil, natural gas and NGLs sales | (2,695) | | | (2,361) | |
| Ending balance | $ | 15,472 | | | $ | 25,872 | |
Customer Accounts Receivable. Our accounts receivable include amounts billed and currently due from sales of our crude oil, natural gas and NGLs production. Our gross accounts receivable balance from crude oil, natural gas and NGLs sales at December 31, 2018 and 2017 was $155.8 million and $154.3 million, respectively. We did not record an allowance for doubtful accounts for these receivables at December 31, 2018 or 2017.
NOTE 56 - FAIR VALUE OF FINANCIAL INSTRUMENTSMEASUREMENTS
Determination ofRecurring Fair Value Measurements
Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:
Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.
Derivative Financial Instruments
Instruments. We measure the fair value of our commodity derivative instruments based onupon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties'counterparties’ credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swapexchange rates and the duration of each outstanding derivative position.
We validateuse our counterparties’ valuations to assess reasonableness of our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions.measurement.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Our crude oil and natural gas fixed-price swapsexchanges and basis exchanges are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:basis as of the dates indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 |
| | Significant Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total | | Significant Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (in thousands) |
| Total assets | $ | 118,521 |
| | $ | 59,693 |
| | $ | 178,214 |
| | $ | 12,949 |
| | $ | 1,389 |
| | $ | 14,338 |
|
| Total liabilities | (3,364 | ) | | (1,364 | ) | | (4,728 | ) | | (90,569 | ) | | (11,076 | ) | | (101,645 | ) |
| Net asset (liability) | $ | 115,157 |
| | $ | 58,329 |
| | $ | 173,486 |
| | $ | (77,620 | ) | | $ | (9,687 | ) | | $ | (87,307 | ) |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2021 | | December 31, 2020 |
| Consolidated Balance Sheet Line Item | | Significant Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total | | Significant Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | | (in thousands) |
| Derivative assets | | | | | | | | | | | | | |
| Current | Fair value of derivatives | | $ | — | | | $ | 17,909 | | | $ | 17,909 | | | $ | 36,580 | | | $ | 12,289 | | | $ | 48,869 | |
| Non-current | Fair value of derivatives | | 605 | | | 14,572 | | | 15,177 | | | 315 | | | 9,250 | | | 9,565 | |
| Total | | | $ | 605 | | | $ | 32,481 | | | $ | 33,086 | | | $ | 36,895 | | | $ | 21,539 | | | $ | 58,434 | |
| | | | | | | | | | | | | |
| Derivative liabilities | | | | | | | | | | | | | |
| Current | Fair value of derivatives | | $ | (230,695) | | | $ | (74,175) | | | $ | (304,870) | | | $ | (76,420) | | | $ | (21,732) | | | $ | (98,152) | |
| Non-current | Fair value of derivatives | | (74,715) | | | (20,846) | | | (95,561) | | | (28,125) | | | (8,234) | | | (36,359) | |
| Total | | | $ | (305,410) | | | $ | (95,021) | | | $ | (400,431) | | | $ | (104,545) | | | $ | (29,966) | | | $ | (134,511) | |
The following table presents a reconciliation of our Level 3 commodity derivative instrumentsassets and liabilities measured at fair value:value for the periods presented:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| | (in thousands) |
| Fair value of Level 3 instruments, net asset (liability) beginning of period | | $ | (8,427) | | | $ | 8,414 | | | $ | 58,329 | |
| Changes in fair value included in consolidated statements of operations line item: | | | | | | |
| Commodity price risk management gain (loss), net | | (206,109) | | | 37,821 | | | (41,749) | |
| Settlements included in consolidated statements of operations line items: | | | | | | |
| Commodity price risk management gain (loss), net | | 151,996 | | | (54,662) | | | (8,166) | |
| Fair value of Level 3 instruments, net asset (liability) end of period | | $ | (62,540) | | | $ | (8,427) | | | $ | 8,414 | |
| | | | | | |
| Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: | | | | | | |
| Commodity price risk management gain (loss), net | | $ | (35,108) | | | $ | — | | | $ | (22,694) | |
| Total | | $ | (35,108) | | | $ | — | | | $ | (22,694) | |
|
| | | | | | | | | | | | |
| | | Year Ended December 31,
|
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
| | | | | | |
| Fair value of Level 3 instruments, net asset (liability) beginning of period | | $ | (9,687 | ) | | $ | (9,574 | ) | | $ | 91,288 |
|
| Changes in fair value included in consolidated statements of operations line item: | | | | | | |
| Commodity price risk management gain (loss), net | | 63,257 |
| | 6,241 |
| | (28,550 | ) |
| Settlements included in consolidated statements of operations line items: | | | | | | |
| Commodity price risk management (loss), net | | 4,759 |
| | (6,354 | ) | | (72,312 | ) |
| Fair value of Level 3 instruments, net asset (liability) end of period | | $ | 58,329 |
| | $ | (9,687 | ) | | $ | (9,574 | ) |
| | | | | | | |
| Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: | | | | | | |
| Commodity price risk management gain (loss), net | | $ | — |
| | $ | (866 | ) | | $ | (12,905 | ) |
| Total | | $ | — |
| | $ | (866 | ) | | $ | (12,905 | ) |
| | | | | | | |
The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements.
Non-DerivativeNonrecurring Fair Value Measurements
Acquisitions and Impairment of Long-lived Assets. We measure fair value using inputs that are not observable in the market, and are therefore designated as Level 3 within the valuation hierarchy, on a nonrecurring basis for any acquired assets or businesses and to review our proved and unproved crude oil and natural gas properties for possible impairment.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Asset Retirement Obligations. We measure the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy.
Other Financial Assets and LiabilitiesInstruments
The carrying value of the financial instruments included in current assets and current liabilities approximateapproximates fair value due to the short-term maturities of these instruments.
We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties and goodwill for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The fair value of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a Level 3 input, in the derivation of the value estimation.
Long-term Debt. The portion of our long-term debt related to our revolving credit facility approximates fair value, due toas the applicable interest rates are variable natureand reflective of related interestmarket rates. We have not elected to account for the portion of our debt related to our senior notes under the
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of the dates indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, |
| | | 2021 | | 2020 |
| Nominal Interest | | Estimated Fair Value | | Percent of Par | | Estimated Fair Value | | Percent of Par |
| | | (in millions) | | | | (in millions) | | |
2021 Convertible Notes (1) | 1.125 | % | | $ | — | | | — | % | | $ | 196.2 | | | 98.1 | % |
| 2024 Senior Notes | 6.125 | % | | 202.8 | | | 101.4 | % | | 410.8 | | | 102.7 | % |
2025 Senior Notes (2) | 6.25 | % | | — | | | — | % | | 102.8 | | | 100.5 | % |
| 2026 Senior Notes | 5.75 | % | | 775.5 | | | 103.4 | % | | 775.5 | | | 103.4 | % |
_______________
(1)Our 2021 Convertible Notes were redeemed and retired on September 15, 2021.
(2)Our 2025 Senior Notes were redeemed and retired on December 31, 2018 and 2017:1, 2021.
|
| | | | | | | | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 |
| | Estimated Fair Value | | Percent of Par | | Estimated Fair Value | | Percent of Par |
| | (in millions) |
| Senior notes: | | | | | | | |
| 2021 Convertible Notes | $ | 175.4 |
| | 87.7 | % | | $ | 195.6 |
| | 97.8 | % |
| 2024 Senior Notes | 370.2 |
| | 92.5 | % | | 416.0 |
| | 104.0 | % |
| 2026 Senior Notes | 532.4 |
| | 88.7 | % | | 616.5 |
| | 102.8 | % |
The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease.
NOTE 67 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS
Objective and Strategy. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas and propane, which is an element of our NGLs, we enter into commodity derivative contracts such as collars, fixed-price exchanges and basis protection exchanges, to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases.We do not enter into derivative contracts for speculative or trading purposes.
We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of December 31, 2018,2021, we had commodity derivatives positions covering approximately 11.0 MMBbls and 8.6 MMBblsderivative instruments in place for a portion of crude oilour anticipated production for 2019 and 2020, respectively. As of the same date, we had hedged approximately 26.4 Bcf of natural gas for 2019.in 2022 through 2024. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount.
As of December 31, 2018,2021 and 2020, our derivative instruments were comprised of collars, fixed-price commodity swaps, collars and basis protection swaps.
•Fixed-price swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty;
•Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty;
Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty;
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
•Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If
Effect of Derivative Instruments on the market price and contract price areConsolidated Statements of Operations. The following table presents the same, no payment is due to or fromimpact of our derivative instruments on our consolidated statements of operations for the counterparty.periods presented:
PDC ENERGY, INC. | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| Consolidated Statements of Operations Line Item | | 2021 | | 2020 | | 2019 |
| | (in thousands) |
| Commodity price risk management gain (loss), net | | | | | | |
| Net settlements | | $ | (410,188) | | | $ | 279,271 | | | $ | (17,598) | |
| Net change in fair value of unsettled derivatives | | (291,268) | | | (99,001) | | | (145,246) | |
| Total commodity price risk management gain (loss), net | | $ | (701,456) | | | $ | 180,270 | | | $ | (162,844) | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Commodity Derivative Contracts.As of December 31, 2018,2021, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.presented:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Collars | | Fixed-Price Swaps | | |
Commodity/ Index/
Maturity Period | | Quantity (Crude oil - MBbls Natural Gas - BBtu) | | Weighted Average Contract Price | | Quantity (Crude Oil - MBbls Gas and Basis- BBtu) | | Weighted Average Contract Price | | Fair Value December 31, 2021 (in thousands) |
| Floors | | Ceilings | | | |
| Crude Oil | | | | | | | | | | | | |
| NYMEX | | | | | | | | | | | | |
| 2022 | | 5,472 | | | $ | 53.18 | | | $ | 67.33 | | | 6,744 | | | $ | 44.42 | | | $ | (235,146) | |
| 2023 | | 2,775 | | | 55.00 | | | 70.00 | | | 5,502 | | | 56.83 | | | (58,299) | |
| 2024 | | 225 | | | 55.00 | | | 75.12 | | | 1,500 | | | 61.27 | | | (2,276) | |
| Total Crude Oil | | 8,472 | | | | | | | 13,746 | | | | | (295,721) | |
| | | | | | | | | | | | |
| Natural Gas | | | | | | | | | | | | |
| NYMEX | | | | | | | | | | | | |
| 2022 | | 35,460 | | | 3.14 | | | 4.78 | | | 33,600 | | | 2.70 | | | (41,165) | |
| 2023 | | 3,000 | | | 3.00 | | | 4.42 | | | 30,398 | | | 2.68 | | | (19,171) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Total Natural Gas | | 38,460 | | | | | | | 63,998 | | | | | (60,336) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Basis Protection - Natural Gas | | | | | | | | | | | | |
| CIG | | | | | | | | | | | | |
| 2022 | | — | | | — | | | — | | | 69,060 | | | (0.25) | | | (10,650) | |
| 2023 | | — | | | — | | | — | | | 29,438 | | | (0.27) | | | (638) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Total Basis Protection - Natural Gas | | — | | | | | | | 98,498 | | | | | (11,288) | |
| | | | | | | | | | | | |
| Commodity Derivatives Fair Value | | | | | | | | | | | | $ | (367,345) | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Collars | | Fixed-Price Swaps | | |
Commodity/ Index/ Maturity Period | | Quantity (Crude oil - MBls Natural Gas - BBtu) | | Weighted-Average Contract Price | | Quantity (Crude Oil - MBbls Gas and Basis- BBtu) | | Weighted- Average Contract Price | | Fair Value December 31, 2018 (1) (in thousands) |
| | Floors | | Ceilings | | | |
| Crude Oil | | | | | | | | | | | | |
| NYMEX | | | | | | | | | | | | |
| 2019 | | 2,600 |
| | $ | 56.54 |
| | $ | 68.13 |
| | 8,400 |
| | $ | 53.86 |
| | $ | 82,305 |
|
| 2020 | | 3,600 |
| | 55.00 |
| | 71.68 |
| | 5,000 |
| | 62.07 |
| | 92,359 |
|
| Total Crude Oil | | 6,200 |
| | | | | | 13,400 |
| | | | $ | 174,664 |
|
| Natural Gas | | | | | | | | | | | | |
| NYMEX | | | | | | | | | | | | |
| 2019 | | — |
| | — |
| | — |
| | 26,008 |
| | 2.91 |
| | 1,408 |
|
| Dominion South | | | | | | | | | | | | |
| 2019 | | — |
| | — |
| | — |
| | 372 |
| | 3.13 |
| | 30 |
|
| Columbia | | | | | | | | | | | | |
| 2019 | | — |
| | — |
| | — |
| | 3 |
| | 2.40 |
| | — |
|
| Total Natural Gas | | — |
| | | | | | 26,383 |
| | | | $ | 1,438 |
|
| Basis Protection - Natural Gas | | | | | | | | | | | | |
| CIG | | | | | | | | | | | | |
| 2019 | | — |
| | — |
| | — |
| | 25,924 |
| | (0.78 | ) | | (2,616 | ) |
| Total Basis Protection - Natural Gas | | — |
| | | | | | 25,924 |
| | | | $ | (2,616 | ) |
| Commodity Derivatives Fair Value | | | | | | | | $ | 173,486 |
|
| |
(1) | Approximately 33.5 percent of the fair value of our commodity derivative assets and 28.9 percentof the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).
|
The following table presents the balance sheet location and fair value amounts of our commodity derivative instruments on the consolidated balance sheets as of December 31, 2018 and 2017:
|
| | | | | | | | | | | |
| Derivative instruments: | | Consolidated balance sheet line item | | 2018 | | 2017 |
| | | | | | (in thousands) |
| Derivative assets: | Current | | | | | | |
| | Commodity derivative contracts | | Fair value of derivatives | | $ | 84,492 |
| | $ | 7,340 |
|
| | Basis protection derivative contracts | | Fair value of derivatives | | — |
| | 6,998 |
|
| | | | | | 84,492 |
| | 14,338 |
|
| | Non-current | | | | | | |
| | Commodity derivative contracts | | Fair value of derivatives | | 93,722 |
| | — |
|
| | | | | | 93,722 |
| | — |
|
| Total derivative assets | | | | | $ | 178,214 |
| | $ | 14,338 |
|
| | | | | | | | |
| Derivative liabilities: | Current | | | | | | |
| | Commodity derivative contracts | | Fair value of derivatives | | $ | 748 |
| | 77,999 |
|
| | Basis protection derivative contracts | | Fair value of derivatives | | 2,616 |
| | 234 |
|
| | Rollfactor derivative contracts | | Fair value of derivatives | | — |
| | 1,069 |
|
| | | | | | 3,364 |
| | 79,302 |
|
| | Non-current | | | | | | |
| | Commodity derivative contracts | | Fair value of derivatives | | 1,364 |
| | 22,343 |
|
| Total derivative liabilities | | | | | $ | 4,728 |
| | $ | 101,645 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Subsequent to December 31, 2021, we entered into the following commodity derivative positions covering our crude oil and natural gas production:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Collars | | Fixed-Price Swaps |
Commodity/ Index/
Maturity Period | | | | | | Quantity (Crude oil - MBbls Natural Gas - BBtu) | | Weighted Average
Contract Price | | Quantity (Crude oil - MBbls Natural Gas - BBtu) | | Weighted-
Average
Contract
Price |
| | | Floors | | Ceilings | | |
| Crude Oil - NYMEX | | | | | | | | | | | | | | |
| 2023 | | | | | | 1,050 | | | $ | 55.00 | | | $ | 79.14 | | | — | | | $ | — | |
| 2024 | | | | | | — | | | — | | | — | | | 2,208 | | 70.25 |
| Natural Gas - NYMEX | | | | | | | | | | | | | | |
| 2023 | | | | | | 12,060 | | | 3.08 | | | 4.35 | | | — | | | — | |
| Natural Gas Basis Protection - CIG | | | | | | | | | | | | | | |
| 2023 | | | | | | — | | | — | | | — | | | 12,060 | | | (0.29) | |
Effect of Derivative Instruments on the Consolidated Balance Sheet.The following table presents the impactbalance sheet line items and fair value amounts of our derivative instruments on our consolidated statements of operations:are disclosed in Note 6 - Fair Value Measurements.
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| Consolidated statements of operations line item | | 2018 | | 2017 | | 2016 |
| | (in thousands) |
| Commodity price risk management gain (loss), net | | | | | | |
| Net settlements | | $ | (115,538 | ) | | $ | 13,324 |
| | $ | 208,103 |
|
| Net change in fair value of unsettled derivatives | | 260,775 |
| | (17,260 | ) | | (333,784 | ) |
| Total commodity price risk management gain (loss), net | | $ | 145,237 |
| | $ | (3,936 | ) | | $ | (125,681 | ) |
| | | | | | |
All of ourOur financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets.
The following table reflects the impact of netting agreements on gross derivative assets and liabilities:
|
| | | | | | | | | | | | |
| As of December 31, 2018 | | Derivative instruments, gross | | Effect of master netting agreements | | Derivative instruments, net |
| | | (in thousands) |
| Asset derivatives: | | | | | | |
| Derivative instruments, at fair value | | $ | 178,214 |
| | $ | (3,985 | ) | | $ | 174,229 |
|
| | | | | | | |
| Liability derivatives: | | | | | | |
| Derivative instruments, at fair value | | $ | 4,728 |
| | $ | (3,985 | ) | | $ | 743 |
|
| | | | | | | | | | | | | | | | | | | | |
| | Total Gross Amount Presented on the Balance Sheet | | Effect of Master Netting Agreements | | Total Net Amount |
| As of December 31, 2021 | | (in thousands) |
| Derivative asset instruments, at fair value | | $ | 33,086 | | | $ | (33,086) | | | $ | — | |
| Derivative liability instruments, at fair value | | $ | 400,431 | | | $ | (33,086) | | | $ | 367,345 | |
| | | | | | |
| As of December 31, 2020 | | | | | | |
| Derivative asset instruments, at fair value | | $ | 58,434 | | | $ | (39,691) | | | $ | 18,743 | |
| Derivative liability instruments, at fair value | | $ | 134,511 | | | $ | (39,691) | | | $ | 94,820 | |
|
| | | | | | | | | | | | |
| As of December 31, 2017 | | Derivative instruments, gross | | Effect of master netting agreements | | Derivative instruments, net |
| | | (in thousands) |
| Asset derivatives: | | | | | | |
| Derivative instruments, at fair value | | $ | 14,338 |
| | $ | (14,173 | ) | | $ | 165 |
|
| | | | | | | |
| Liability derivatives: | | | | | | |
| Derivative instruments, at fair value | | $ | 101,645 |
| | $ | (14,173 | ) | | $ | 87,472 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 7 - CONCENTRATION OF RISK
Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts:
|
| | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 |
| | (in thousands) |
| | | | |
| Crude oil, natural gas and NGLs sales | $ | 155,756 |
| | $ | 154,260 |
|
| Joint interest billings | 19,580 |
| | 34,576 |
|
| Derivative counterparties | 3,937 |
| | (18 | ) |
| Income tax receivable | — |
| | 6,015 |
|
| Other | 6,542 |
| | 5,893 |
|
| Allowance for doubtful accounts | (4,381 | ) | | (3,128 | ) |
| Accounts receivable, net | $ | 181,434 |
| | $ | 197,598 |
|
| | | | |
Our accounts receivable primarily relate to sales of our crude oil, natural gas and NGLs production, receivable balances from other third parties that own working interests in the properties we operate, and derivative counterparties. For the years ended December 31, 2018 and 2017, amounts written off to allowance for doubtful accounts were not material. As of December 31, 2018, two of our customers represent 10 percent or greater of our accounts receivable balance. As of December 31, 2017, none of our customers represented 10 percent or greater of our accounts receivable balance.
Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues:
|
| | | | | | | | | |
| | | Year Ended December 31, |
| Customer | | 2018 | | 2017 | | 2016 |
| | | | | | | |
| DCP Midstream, LP | | 12.5 | % | | 19.6 | % | | 20.2 | % |
| Suncor Energy Marketing, Inc. | | — | % | | 16.4 | % | | 22.3 | % |
| Aka Energy Group, LLC | | — | % | | — | % | | 13.4 | % |
| Concord Energy, LLC | | — | % | | — | % | | 13.4 | % |
| Bridger Energy, LLC | | — | % | | — | % | | 11.5 | % |
Derivative Counterparties.A portion of our liquidity relates toOur commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil, natural gas and NGLs. These arrangements expose us to creditthe risk of nonperformancenon-performance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2018.2021; however, this determination may change.
Note Receivable. Note Receivable.In 2014, we sold our entire 50 percent ownership interest in PDC Mountaineer, LLC to an unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of $39.0 million. We regularly analyzed the Promissory Note for evidence of collectibility, evaluating factors such as the creditworthiness of the issuer of the Promissory Note and the value of the issuer's assets. Based upon this analysis, during the quarter ended March 31, 2016, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million accumulated outstanding balance, including interest. In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $40.2 million in cash. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Other Accrued Expenses. The following table presents the components of other accrued expenses:
|
| | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 |
| | (in thousands) |
| | | | |
| Employee benefits | $ | 25,811 |
| | $ | 22,383 |
|
| Asset retirement obligations | 25,598 |
| | 15,801 |
|
| Environmental expenses | 3,038 |
| | 1,374 |
|
| Other | 20,686 |
| | 3,429 |
|
| Other accrued expenses | $ | 75,133 |
| | $ | 42,987 |
|
Other Liabilities. The following table presents the components of other liabilities as of:
|
| | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 |
| | (in thousands) |
| | | | |
| Production taxes | $ | 61,310 |
| | $ | 50,476 |
|
| Deferred oil gathering credit | 22,710 |
| | — |
|
| Other | 8,644 |
| | 6,857 |
|
| Other liabilities | $ | 92,664 |
| | $ | 57,333 |
|
Deferred Oil Gathering Credit. In January 2018, we received a payment of $24.1 million from a midstream service provider for the execution of an amendment to an existing crude oil purchase and sale agreement signed in December 2017. The amendment was effective contingent upon certain events which occurred in late January 2018. The amendment, among other things, dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The payment will be amortized using the straight-line method over the life of the amendment. Amortization charges totaling approximately $1.4 million for 2018 related to the deferred oil gathering credit are included as a reduction to transportation, gathering and processing expenses in our consolidated statements of operations.
NOTE 8 - PROPERTIES AND EQUIPMENT, NET
The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization (“DD&A:
|
| | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 |
| | (in thousands) |
| Properties and equipment, net: | | | |
| Crude oil and natural gas properties | | | |
| Proved | $ | 5,452,613 |
| | $ | 4,356,922 |
|
| Unproved | 492,594 |
| | 1,097,317 |
|
| Total crude oil and natural gas properties | 5,945,207 |
| | 5,454,239 |
|
| Infrastructure and other | 60,612 |
| | 109,359 |
|
| Land and buildings | 11,243 |
| | 10,960 |
|
| Construction in progress | 356,095 |
| | 196,024 |
|
| Properties and equipment, at cost | 6,373,157 |
| | 5,770,582 |
|
| Accumulated DD&A | (2,370,295 | ) | | (1,837,115 | ) |
| Properties and equipment, net | $ | 4,002,862 |
| | $ | 3,933,467 |
|
Acreage Exchanges. In November 2018, we completed a nonmonetary acreage exchange that resulted in our acquisition of approximately 12,300 net acres that consolidated our position in the core area&A”), as of the Wattenberg Field. We recognized a gain of approximately $6.0 million related to the exchange based on the fair value of the assets surrendered.dates indicated:
PDC ENERGY, INC. | | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| (in thousands) |
| Properties and equipment, net: | | | |
| Crude oil and natural gas properties | | | |
| Proved | $ | 8,310,018 | | | $ | 7,523,639 | |
| Unproved | 306,181 | | | 350,677 | |
| Total crude oil and natural gas properties | 8,616,199 | | | 7,874,316 | |
| Equipment and other | 63,099 | | | 65,027 | |
| Land and buildings | 19,928 | | | 24,299 | |
| Construction in progress | 371,968 | | | 523,550 | |
| Properties and equipment, at cost | 9,071,194 | | | 8,487,192 | |
| Accumulated DD&A | (4,256,329) | | | (3,627,993) | |
| Properties and equipment, net | $ | 4,814,865 | | | $ | 4,859,199 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Also during 2018, we completed another nonmonetary acreage exchange in the Wattenberg Field, resulting in us acquiring approximately 2,500 net acres and $3.7 million in cash. It was concluded that this transaction lacked commercial substance, and accordingly, the trade was recorded at the previous historical cost of the assets exchanged, less cash received.
In 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transactions, we exchanged leasehold acreage with a limited number of wells that were in the process of being drilled and completed. Upon closing, we received approximately 15,900 net acres in exchange for approximately 16,200 net acres with minimal cash exchanged between the parties. The differences in net acres are primarily due to variances in working and net revenue interests and in midstream contracts. The assets exchanged were all in the same unit-of-production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets we exchanged.
Classification of Assets and Liabilities as Held-for-Sale. During the fourth quarter of 2018, as part of our plan to divest certain of our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets, we began actively marketing the assets for sale; therefore, these assets are classified as held-for-sale as they met the criteria for such classification at December 31, 2018. We currently expect to execute agreements on the sales of these assets in the first half of 2019. Our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets do not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we will not account for it as a discontinued operation. Also included in the assets held-for-sale are certain non-core Delaware Basin crude oil and natural gas properties.
During 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking firm and began actively marketing the properties for sale; therefore, these properties were classified as held-for-sale as they met the criteria for such classification at December 31, 2017. In March 2018, we completed the Utica Shale Divestiture for net cash proceeds of approximately $39.0 million. We recorded a loss on sale of properties and equipment of $1.4 million for 2018, which included post-closing adjustments. The Utica Shale Divestiture did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for it as a discontinued operation.
The following table presents balance sheet data related to assets and liabilities held-for-sale:
|
| | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 |
| | (in thousands) |
| Assets | | | |
| Properties and equipment, net | $ | 137,448 |
| | $ | 40,583 |
|
| Other assets | 3,257 |
| | — |
|
| Total assets | $ | 140,705 |
| | $ | 40,583 |
|
| | | | |
| Liabilities | | | |
| Asset retirement obligation | $ | 4,111 |
| | $ | 499 |
|
| Total liabilities | $ | 4,111 |
| | $ | 499 |
|
Impairment of PropertiesOil and Equipment
Gas Properties. The following table presents impairment charges recorded for properties and equipment:equipment for the periods presented:
| | | | Year Ended December 31, | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | | Year Ended December 31, |
| | (in thousands) | | 2021 | | 2020 | | 2019 |
| | | | | | | (in thousands) |
| Impairment of proved and unproved properties | $ | 458,397 |
| | $ | 285,465 |
| | $ | 5,562 |
| Impairment of proved and unproved properties | $ | 402 | | $ | 881,238 | | $ | 10,599 |
| Amortization of individually insignificant unproved properties | — |
| | 422 |
| | 1,379 |
| |
| Land and buildings | — |
| | — |
| | 3,032 |
| |
| Impairment of infrastructure and other | | Impairment of infrastructure and other | — | | 1,155 | | 27,937 |
| Total impairment of properties and equipment | $ | 458,397 |
| | $ | 285,887 |
| | $ | 9,973 |
| Total impairment of properties and equipment | $ | 402 | | $ | 882,393 | | $ | 38,536 |
| | | | | | | |
PDC ENERGY, INC.Oil and Gas Properties.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In the first quarter of 2020, the significant decline in crude oil prices in addition to the ongoing effects of the COVID-19 pandemic were considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment expense of $881.1 million to our proved and unproved properties. During the year ended December 31, 2021, there were no significant impairments recognized.
Proved Properties. Of the total impairment expense recognized in 2020, approximately $753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. We estimated the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount, a Level 3 input. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of future production volumes, future operating and development costs, future commodity prices, and a discount rate of 17 percent, which was based on a weighted average cost of capital for the area where the assets are located. There were no impairment charges recognized related to our proved properties during the year ended December 31, 2019.
Unproved Properties. We recognized approximately $127.3 million of impairment charges for our unproved properties in the Delaware Basin in 2020. These impairment charges were recognized based on the fair value of the properties, a Level 3 input. The fair value is estimated based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans.
During 2018,the year ended December 31, 2019, we recorded impairment charges totaling $458.4$10.6 million as we identified currentrelated to the divestiture of unproved leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin and made the determination that we would no longer pursue plansdetermined not to develop these properties. The impaired non-focus leasehold typically has a higher gas to oil ratiodevelop.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Other Property and a greater degree of geologic complexity than our other Delaware Basin properties and is further impacted by widening crude oil and natural gas differentials and increased well development costs. We continue to explore options for our non-focus areas and monitor them for possible future impairment based on similar analyses. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold.
The impairment charges noted above include the correction of two errors in the timing of the reporting of certain impairments. In 2018, we corrected an error in our calculation of unproved properties and goodwill originally recorded in 2017, resulting in an additional impairment charge of $6.3 million being recorded during the three months ended March 31, 2018. Further, during the fourth quarter of 2018, we corrected for an additional $8.4 million impairment of unproved properties relating to thethree months ended September 30, 2018. This correction had no impact onEquipment Impairment. During the year ended December 31, 2018. We evaluated these errors under the guidance of Accounting Standards Codification 250, Accounting Changes and Error Corrections ("ASC 250"). Based on the guidance in ASC 250, we determined that the errors did not have a material impact on our previously-issued financial statements or those of the period of correction.
During 2017,2019, we recorded a chargeimpairments of $27.9 million related to two exploratory dry holes we had drilled in the western area of our Culberson County acreagecertain midstream facility infrastructure in the Delaware Basin. We then assessedUpon the impactdivestiture of the dry holes and various factors related thereto, including the operational and geologic data obtained, the current increased cost environment for drilling and completion services in the Delaware Basin, our decreased future commodity price outlook and the terms of the related lease agreements. Based on the results of this assessment, we concludedcertain midstream assets, it was determined that the underlying geologic risk and the challenged economicsnet book value of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during 2017. The amount of the impairmentthese assets was based on the value assigned to individual lease acres in the final purchase price allocation of the Delaware Basin acquisition. This allocation had included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. We recorded approximately $29 million of additional lease impairments in the Delaware Basin and an impairment charge of $2.1 million related to the Utica Shale properties that were classified as held-for-sale during 2017. Due to the aforementioned events and circumstances, we also evaluated our proved property for possible impairment and concluded that no further impairments were necessary. Future deterioration of commodity prices or other operating circumstances could result in additional impairment charges to our properties and equipment.not recoverable.
Suspended Well Costs.The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment for the periods presented:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (in thousands, except for number of wells) |
| Beginning balance | $ | 7,459 | | | $ | 16,078 | | | $ | 12,188 | |
| Additions to capitalized exploratory well costs pending the determination of proved reserves | 5,902 | | | 11,770 | | | 31,901 | |
| Reclassifications to proved properties | (13,361) | | | (20,389) | | | (28,011) | |
| Ending balance | $ | — | | | $ | 7,459 | | | $ | 16,078 | |
| | | | | |
| Number of wells pending determination at period-end | — | | 2 | | 4 |
As of December 31, 2020, our net oncapitalized exploratory well costs that have been capitalized for a period greater than one year was $7.5 million, which consists of the consolidatedentire balance sheets:of our suspended well costs and relates to two gross suspended wells associated with two projects. During the year ended December 31, 2021, both exploratory wells were determined to be successful producing wells and were reclassified into proved properties. We have no remaining exploratory wells pending determination as of December 31, 2021.
NOTE 9 - ACCOUNTS RECEIVABLE, OTHER ACCRUED EXPENSES AND OTHER LIABILITIES
Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts as of the dates indicated:
| | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| (in thousands) |
| Crude oil, natural gas and NGLs sales | $ | 368,991 | | | $ | 178,147 | |
| Joint interest billings | 24,860 | | | 35,396 | |
| Other | 10,809 | | | 37,471 | |
| Allowance for doubtful accounts | (6,055) | | | (6,763) | |
| Accounts receivable, net | $ | 398,605 | | | $ | 244,251 | |
The Company’s accounts receivable consist mainly of receivables from (i) crude oil, natural gas and NGLs purchasers, (ii) joint interest owners in the properties we operate and (iii) derivative counterparties. Most payments for production are received within two months after the production date. For receivables from joint interest owners, we typically have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
Credit and Concentration Risk.Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions.
|
| | | | | | | |
| | As of December 31,
|
| | 2018 | | 2017 |
| | (in thousands, except for number of wells) |
| | | | |
| Beginning balance | $ | 15,448 |
| | $ | — |
|
| Additions to capitalized exploratory well costs pending the determination of proved reserves | 35,127 |
| | 51,776 |
|
| Reclassifications to proved properties | (38,387 | ) | | (36,328 | ) |
| Balance at December 31, | $ | 12,188 |
| | $ | 15,448 |
|
| | | | |
| Number of wells pending determination | 2 |
| | 3 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers in our operating areas. The following major customers accounted for 10 percent or more of our total crude oil, natural gas, and NGLs sales for at least one of the periods presented:
Exploration | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| Major customer #1 | | 32 | % | | 31 | % | | 20 | % |
| Major customer #2 | | 11 | % | | 16 | % | | 16 | % |
| Major customer #3 | | 10 | % | | 13 | % | | 11 | % |
| Major customer #4 | | 9 | % | | 17 | % | | 17 | % |
Other Accrued Expenses. The following table presents the major components of exploration, geologicother accrued expenses as of the dates indicated:
| | | | | | | | | | | | | | |
| | December 31, |
| | 2021 | | 2020 |
| | (in thousands) |
| Employee benefits | | $ | 29,319 | | | $ | 23,304 | |
| Asset retirement obligations | | 32,146 | | | 33,933 | |
| Environmental expenses | | 11,942 | | | 10,139 | |
| Operating and finance leases | | 7,197 | | | 7,986 | |
| Other | | 10,805 | | | 6,353 | |
| Other accrued expenses | | $ | 91,409 | | | $ | 81,715 | |
Other Liabilities. The following table presents the components of other liabilities as of the dates indicated:
| | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| (in thousands) |
| Deferred midstream gathering credits | $ | 159,788 | | | $ | 168,478 | |
| Deferred oil gathering credits | 16,080 | | | 18,090 | |
| Production taxes | 131,865 | | | 65,592 | |
| Operating and finance leases | 6,274 | | | 10,763 | |
| Other | 762 | | | 1,111 | |
| Other liabilities | $ | 314,769 | | | $ | 264,034 | |
Deferred Midstream Gathering Credits. In 2019, we entered into agreements pursuant to which we dedicated the gathering of certain of our production and geophysical expense:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
| | | | | | |
| Exploratory dry hole costs | $ | 113 |
| | $ | 41,297 |
| | $ | — |
|
| Geological and geophysical costs, including seismic purchases | 3,401 |
| | 3,881 |
| | 3,472 |
|
| Operating, personnel and other | 2,690 |
| | 2,156 |
| | 1,197 |
|
| Total exploration, geologic and geophysical expense | $ | 6,204 |
| | $ | 47,334 |
| | $ | 4,669 |
|
| | | | | | |
Exploratory dry hole costs. During 2017, two exploratory dry holes, associated lease costsall water gathering and related infrastructure assetsdisposal volumes in the Delaware Basin were expensed atBasin. The terms of these agreements range from 15 to 22 years. The acreage dedication agreements resulted in initial cash receipts and are being amortized on a cost of $41.3 million.units-of-production basis. The conclusion to expense these items was basedamortization rates are assessed on our determinationan annual basis for changes in estimated future production.
Deferred Oil Gathering Credits. In 2018, we entered into an agreement that the acreage on which these wells were drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable.
NOTE 9 - GOODWILL
Goodwill that resulteddedicates crude oil from the purchase price allocationmajority of a business combination inour Wattenberg Field acreage to the Delaware Basin in December 2016 was determined to be $75.1 million. In 2017, we evaluated goodwill for impairment by performing a quantitative test, which involves comparingmidstream provider’s gathering lines and extends the estimated fair valueterm of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. We determined the fair value of the goodwill by usingagreement through December 2029. The acreage dedication agreement resulted in an estimated after-tax future discountedinitial cash flow analysis, along withreceipt and is being amortized on a combination of market-based pricing factorsunits-of-production basis. The amortization rates are assessed on an annual basis for similar acreage, reserve valuation techniques and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $75.1 million was required; therefore, the charge was recorded in 2017.estimated future production.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents the amortization charges related to our deferred credits recognized on the consolidated statements of operations for the periods indicated: | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 |
| | (in thousands) |
| Crude oil, natural gas and NGLs sales | | $ | — | | | $ | 1,013 | |
| Transportation, gathering and processing expense | | 7,317 | | | 5,618 | |
| Lease operating expense | | 2,422 | | | 2,015 | |
NOTE 10 - LONG-TERM DEBT
Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $7.9 million and $17.8 million as of December 31, 2021 and December 31, 2020, respectively, consists of the following:
|
| | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 |
| | (in thousands) |
| Senior notes: | | | |
| 1.125% Convertible Notes due 2021: | | | |
| Principal amount | $ | 200,000 |
| | $ | 200,000 |
|
| Unamortized discount | (22,766 | ) | | (30,328 | ) |
| Unamortized debt issuance costs | (2,640 | ) | | (3,615 | ) |
| 1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs | 174,594 |
| | 166,057 |
|
| | | | |
| 6.125% Senior Notes due 2024: | | | |
| Principal amount | 400,000 |
| | 400,000 |
|
| Unamortized debt issuance costs | (5,590 | ) | | (6,570 | ) |
| 6.125% Senior Notes due 2024, net of unamortized debt issuance costs | 394,410 |
| | 393,430 |
|
| | | | |
| 5.75% Senior Notes due 2026: | | | |
| Principal amount | 600,000 |
| | 600,000 |
|
| Unamortized debt issuance costs | (6,628 | ) | | (7,555 | ) |
| 5.75% Senior Notes due 2026, net of unamortized debt issuance costs | 593,372 |
| | 592,445 |
|
| | | | |
| Total senior notes | 1,162,376 |
| | 1,151,932 |
|
| | | | |
| Revolving credit facility | 32,500 |
| | — |
|
| Total long-term debt, net of unamortized discount and debt issuance costs | 1,194,876 |
| | 1,151,932 |
|
| Less current portion of long-term debt | — |
| | — |
|
| Long-term debt | $ | 1,194,876 |
| | $ | 1,151,932 |
|
| | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| (in thousands) |
| Revolving credit facility due November 2026 | $ | — | | | $ | 168,000 | |
| 1.125% Convertible Notes due September 2021 | — | | | 193,014 | |
| 6.125% Senior Notes due September 2024 | 198,674 | | | 396,368 | |
| 6.25% Senior Notes due December 2025 | — | | | 103,204 | |
| 5.75% Senior Notes due May 2026 | 743,410 | | | 741,976 | |
| Total debt, net of unamortized discount, premium and debt issuance costs | 942,084 | | | 1,602,562 | |
| Less: Current portion of long-term debt | — | | | 193,014 | |
| Total long-term debt | $ | 942,084 | | | $ | 1,409,548 | |
Senior NotesRevolving Credit Facility
In November 2021, Convertible Notes. In September 2016, we issued $200.0 millionentered into a Fifth Amended and Restated Credit Agreement (the “Restated Credit Agreement”), which provides for a maximum credit amount of 1.125% convertible senior notes due 2021 in a public offering.$2.5 billion, subject to certain limitations, an initial borrowing base of $2.4 billion and an elected commitment of $1.5 billion. The 2021 Convertible Notes are governed by an indenture dated September 14, 2016. The maturity forRestated Credit Agreement matures on the paymentearlier to occur of principal is September 15, 2021. Interest at(i) the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15. The proceeds from the issuanceend of the 2021 Convertible Notes, after deducting offering expenses and underwriting discounts, were usedfive year term on November 2, 2026 or (ii) the date that is 91 days prior to fund a portionthe scheduled maturity of the purchase price2026 Senior Notes if the aggregate outstanding principal amount of those notes exceeds $500 million and our commitment utilization exceeds 50%.
The revolving credit facility is available for working capital requirements, capital investments, acquisitions, in the Delaware Basin, to pay related fees and expensessupport letters of credit and for general corporatebusiness purposes.
The 2021 Convertible Notes are convertible priorborrowing base is based on, among other things, the loan value assigned to March 15, 2021 only upon specified eventsthe proved reserves attributable to our crude oil and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share.natural gas interests. The conversion rateborrowing base is subject to adjustmenta semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Upon conversion,Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility. The Restated Credit Agreement includes an investment grade period election pursuant to which we have an option to remove our borrowing base limitations and terminate the liens securing the Restated Credit Agreement when certain debt ratings are achieved.
As of December 31, 2021, Convertible Notes may be settled,we had a borrowing base of $2.4 billion, an elected commitment of $1.5 billion and availability under our revolving credit facility of $1.5 billion, net of $19.9 million of letters of credit outstanding.
The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the Secured Overnight Financing Rate (“SOFR”) for one month, plus a premium) or, at our sole election, in sharesa rate equal to SOFR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our common stock, cash or a combination thereof. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amountutilization of the facility. As of December 31, 2021, Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares.
We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indentureapplicable interest margin is 0.75 percent for the 2021 Convertible Notes, subject to certain conditions, holdersalternate base rate option or 1.75 percent for the SOFR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the maturity date of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible.revolving credit
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
We allocatedfacility, unless the gross proceedsborrowing base falls below the outstanding balance. The Restated Credit Agreement also includes the ability to add certain sustainability-linked key performance indicators to be agreed upon between us, the administrative agent and a majority of the 2021 Convertible Notes betweenlenders and that may impact the liabilityapplicable margin and equity componentscommitment fee rate.
The revolving credit facility contains various restrictive covenants and compliance requirements, which include, among other things: (i) maintenance of certain financial ratios, as defined per the debt. The initial $160.5 million liability component was determined basedrevolving credit facility, including a minimum current ratio of 1.0:1.0 and a maximum leverage ratio of 3.50:1.0; (ii) restrictions on the fair valuepayment of similar debt instruments excluding the conversion feature for similar terms and pricedcash dividends; (iii) limits on the same day we issuedincurrence of additional indebtedness; (iv) prohibition on the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discountentry into commodity hedges exceeding a specified percentage of our expected production; and was calculated as the difference between the fair value(v) restrictions on mergers and dispositions of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method.assets. As of December 31, 2018, the unamortized debt discount will be amortized over the remaining contractual term2021, we were in compliance with all covenants related to maturityour revolving credit facility.
As of the 2021 Convertible Notes using the effective interest method. Based upon the December 31, 2018 stock price of $29.76 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount.
2024 Senior Notes. In September 2016, we issued $400.0 million aggregate principal amount of 6.125% senior notes due September 2024. The proceeds from the issuance of the 2024 Senior Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin,to pay related fees and expenses, and for general corporate purposes.
Interest is payable semi-annually in arrears on March 15 and September 15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as2020, debt issuance costs related to our revolving credit facility were $16.9 million and $8.1 million, respectively, and are being amortized as interest expense over the life of the notes using the effective interest method.included in other assets on our consolidated balance sheets.
Senior Notes and Convertible Notes
The 2024 Senior Notes are redeemable after September 15, 2019 at fixedfollowing table summarizes the face values, interest rates, maturity dates, semi-annual interest payment dates, and optional redemption prices beginning at 104.594 percentperiods related to our outstanding senior note obligations as of the principal amount redeemed.December 31, 2021:
| | | | | | | | | | | | | | |
| | 2024 Senior Notes | | 2026 Senior Notes |
| Outstanding principal amounts (in thousands) | | $ | 200,000 | | | $ | 750,000 | |
| Interest rate | | 6.125 | % | | 5.75 | % |
| Maturity date | | September 15, 2024 | | May 15, 2026 |
| Interest payment dates | | March 15, September 15 | | May 15, November 15 |
Redemption periods (1) | | September 15, 2022 | | May 15, 2024 |
_____________(1) At any time prior to September 15, 2019,the indicated dates, we may redeem all or part of the 2024 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at September 15, 2019 and remaining interest payments on the 2024 Senior Notes at the time of redemption.
At any time prior to September 15, 2019, we may redeem up to 35 percent of the outstanding 2024 Senior Notes with proceeds from certain equity offerings at a redemption price of 106.125 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2024 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering.
Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes, holders will have the rightoption to require us to repurchaseredeem all or a portion of theour senior notes at a price equal to 101 percent of the aggregate principal amount ofapplicable series at the notes repurchased, together with anyredemption amounts specified in the respective senior note indenture plus accrued and unpaid interest to the date of purchase. In connection with certain asset sales,redemption. On or after the indicated dates, we may under certain circumstances, be required to useredeem all or a portion of the net cash proceeds of such asset sale to make an offer to purchase thesenior notes at 100 percenta redemption amount equal to 100% of the principal amount together with anyof the senior notes being redeemed plus accrued and unpaid interest to the date of purchase.
2026 Senior Notes. In November 2017, we issued $600.0 million aggregate principal amount 5.75% senior notes due May 15, 2026. The 2026 Senior Notes are governed by an indenture dated November 29, 2017. The maturity for the payment of principal is May 15, 2026. Interest at the rate of 5.75% per year is payable in cash semiannually in arrears on each May 15 and November 15. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method.
The 2026 Senior Notes are redeemable after May 15, 2021 at fixed redemption prices beginning at 104.313 percent of the principal amount redeemed. At any time prior to May 15, 2021, we may redeem all or part of the 2026 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15, 2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption.
At any time prior to May 15, 2021 we may redeem up to 35 percentOur wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of the outstanding 2026 Senior Notes with proceeds from certain equity offerings at a redemption price of 105.75 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2026 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering.
Upon the occurrence of a "change of control," as defined in the indenture for the 2026 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may,our obligations under certain circumstances, be required to use the net cash proceeds of such asset sale to make an
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase.
The 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior notesNotes (collectively, the “Senior Notes”).
The Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. Our wholly-owned subsidiary, PDC Permian, Inc.
Upon the occurrence of a “change of control”, is a guarantor of our obligations underas defined in the 2021 Convertible Notes,indentures for the 2024 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with accrued and unpaid interest to the 2026 Senior Notes.date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase.
The indentures governing the 2024 Senior Notes and 2026 Senior Notes contain covenants and restricted payment provisions that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries.
As of December 31, 2018,2021, we were in compliance with all covenants and all restricted payment provisions related to theour Senior Notes.
Retirement of Convertible Notes. On September 15, 2021, we redeemed and retired our 2021 Convertible Notes 2024 Convertible Notes andwith a cash payment for the 2026 Senior Notes.
RevolvingCredit Facility
In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”). The Restated Credit Agreement amends and restates our Third Amended and Restated Credit Agreement dated as of May 21, 2013, as amended. Among other things, the Restated Credit Agreement provides for a maximum creditprincipal amount of $2.5 billion, an initial borrowing base of $1.3 billion$200 million plus accrued and an initial elected commitment amount of $700 million. The amount we may borrow under the Restated Credit Agreement is subject to certain limitations under our Notes. In addition, the Restated Credit Agreement extends the maturity date of the facility to May 2023, reflects improved covenant flexibility and certain reductions in interest rates applicable to borrowings under the facility and includes a $25 million swingline facility. In October 2018, we increased the commitment level on our revolving credit facility to the current borrowing base amount of $1.3 billion.
The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events.
The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium) or, at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2018, the applicable interest margin is 0.25 percent for the alternate base rate option or 1.25 percent for the LIBOR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the revolving credit facility expires in May 2023, unless the borrowing base falls below the outstanding balance.
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 to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of December 31, 2018, we were in compliance with all the revolving credit facility covenants.
As of December 31, 2018 and 2017, debt issuance costs related to our revolving credit facility were $11.5 million and $6.2 million, respectively, and are included in other assets on the consolidated balance sheets. As of December 31, 2018 and 2017, availability under our revolving credit facility was $1.3 billion and $700 million, respectively. As of December 31, 2018, the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was 4.5 percent.
NOTE 11 - CAPITAL LEASES
We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease.
The following table presents leased vehicles under capital leases: unpaid interest.
|
| | | | | | | | |
| | | As of December 31, |
| | 2018 | | 2017 |
| | | (in thousands) |
| Vehicles | | $ | 7,941 |
| | $ | 6,249 |
|
| Accumulated depreciation | | (3,368 | ) | | (1,882 | ) |
| | | $ | 4,573 |
| | $ | 4,367 |
|
Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following:
|
| | | | |
| For the Twelve Months Ending December 31, | | Amount |
| | | (in thousands) |
| 2019 | | $ | 2,111 |
|
| 2020 | | 2,236 |
|
| 2021 | | 698 |
|
| 2022 | | 381 |
|
| 2023 | | 134 |
|
| | | 5,560 |
|
| Less executory cost | | (278 | ) |
| Less amount representing interest | | (603 | ) |
| Present value of minimum lease payments | | $ | 4,679 |
|
| | | |
|
| Short-term capital lease obligations | | $ | 1,779 |
|
| Long-term capital lease obligations | | 2,900 |
|
| | | $ | 4,679 |
|
Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Early Retirement of Senior Notes. In November 2021, we redeemed $200 million in aggregate principal amount of our 2024 Senior Notes at a redemption price of 101.531 percent of the principal plus accrued and unpaid interest, leaving an aggregate principal amount outstanding of $200 million. Additionally, in December 2021, we redeemed the remaining $102.3 million principal amount of our 2025 Senior Notes at a redemption price of 103.125 percent of the principal plus accrued and unpaid interest. We recognized an aggregate loss on extinguishment of $6.9 million from the partial redemption of our 2024 Senior Notes and retirement of our 2025 Senior Notes. The loss on extinguishment was presented as part of interest expense, net on the consolidated statement of operations.
NOTE 11 - LEASES
We have operating leases for office space and well equipment, and finance leases for vehicles. Our leases have remaining lease terms ranging from one to five years. The vehicle leases include an option to renew on a month-to-month basis after the primary term. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee.
The following table presents the components of lease costs for the periods presented:
| | | | | | | | | | | | | | | | |
| | | | | | |
| | Year Ended December 31, | |
| | 2021 | | 2020 | | |
| | (in thousands) | |
Operating lease costs (1) | | $ | 6,125 | | | $ | 7,983 | | | |
| | | | | | |
| Finance lease costs: | | | | | | |
| Amortization of ROU assets | | 1,752 | | | 1,812 | | | |
| Interest on lease liabilities | | 164 | | | 179 | | | |
| Total finance lease costs | | 1,916 | | | 1,991 | | | |
Short-term lease costs (1) | | 203,361 | | | 193,756 | | | |
| | | | | | |
| Total lease costs | | $ | 211,402 | | | $ | 203,730 | | | |
_______________
(1)The majority of our operating leases relate to the operation or completion of our wells. Therefore, the lease costs presented in the table above represent the total gross costs we incur, which are not comparable to our net costs recorded to the consolidated statements of operations, consolidated statements of cash flows or capitalized in the consolidated balance sheets, as amounts therein are reflected net of amounts billed to working interest partners.
Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense. Our short-term lease costs include amounts that are capitalized as part of the cost of assets and are recorded as properties and equipment or recognized as expense.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents the balance sheet classification and other information regarding our leases as of the dates indicated:
| | | | | | | | | | | | | | | | | | | | | | |
| | | | December 31, | | |
| | Consolidated Balance Sheet Line Item | | 2021 | | 2020 | | |
| | | | (in thousands) | | |
| Operating lease ROU assets | | Other assets | | $ | 7,630 | | | $ | 11,722 | | | |
| Finance lease ROU assets | | Properties and equipment, net | | $ | 3,483 | | | $ | 3,189 | | | |
| Total ROU assets | | | | $ | 11,113 | | | $ | 14,911 | | | |
| | | | | | | | |
| Operating lease obligation - short-term | | Other accrued expenses | | 5,937 | | | 6,520 | | | |
| Operating lease obligation - long-term | | Other liabilities | | 4,044 | | | 9,061 | | | |
| Finance lease obligation - short-term | | Other accrued expenses | | 1,260 | | | 1,466 | | | |
| Finance lease obligation - long-term | | Other liabilities | | 2,230 | | | 1,702 | | | |
| Total lease liabilities | | | | $ | 13,471 | | | $ | 18,749 | | | |
| | | | | | | | |
| Weighted average remaining lease term (years) | | | | 2.8 | | 3.0 | | |
| Weighted average discount rate | | | | 4.8 | % | | 4.8 | % | | |
0Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2021 consist of the following:
| | | | | | | | | | | | | | | | | | | | |
| | Operating Leases | | Finance Leases | | Total |
| | (in thousands) |
| 2022 | | $ | 6,214 | | | $ | 1,378 | | | $ | 7,592 | |
| 2023 | | 1,767 | | | 1,119 | | | 2,886 | |
| 2024 | | 950 | | | 612 | | | 1,562 | |
| 2025 | | 950 | | | 473 | | | 1,423 | |
| 2026 | | 747 | | | 148 | | | 895 | |
| | | | | | |
| Total lease payments | | 10,628 | | | 3,730 | | | 14,358 | |
| Less: Interest and discount | | (647) | | | (240) | | | (887) | |
| Present value of lease liabilities | | $ | 9,981 | | | $ | 3,490 | | | $ | 13,471 | |
In January 2022, we entered into a 11-year lease agreement for an office space expected to commence in March 2022 with aggregate lease payments of approximately $32 million.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 12 - ASSET RETIREMENT OBLIGATIONS
The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties and midstream assets:for the periods presented:
| | | | Year Ended December 31, | | | | | | | | | | |
| | 2018 | | 2017 | | Year Ended December 31, |
| | (in thousands) | | 2021 | | 2020 |
| | | | | | (in thousands) |
| Beginning balance | $ | 87,306 |
| | $ | 92,387 |
| Beginning balance | $ | 166,570 | | | $ | 127,251 | |
| Obligations incurred with development activities | 2,793 |
| | 3,638 |
| |
| Obligations incurred with development activities and other | | Obligations incurred with development activities and other | 4,750 | | | 6,494 | |
| Obligations incurred with acquisition | 4,332 |
| | — |
| Obligations incurred with acquisition | — | | | 47,673 | |
| Accretion expense | 5,075 |
| | 6,306 |
| Accretion expense | 12,086 | | | 10,072 | |
| Revisions in estimated cash flows | 30,166 |
| | (2,860 | ) | Revisions in estimated cash flows | 10,609 | | | 4,742 | |
| Obligations discharged with asset retirements | (14,651 | ) | | (12,165 | ) | |
| Balance at December 31 | 115,021 |
| | 87,306 |
| |
| Less liabilities held-for-sale | (4,111 | ) | | (499 | ) | |
| Less current portion | (25,598 | ) | | (15,801 | ) | |
| Obligations discharged with asset retirements and divestitures | | Obligations discharged with asset retirements and divestitures | (34,343) | | | (29,662) | |
| Asset retirement obligations at end of period | | Asset retirement obligations at end of period | 159,672 | | | 166,570 | |
| Current portion(1) | | Current portion(1) | (32,146) | | | (33,933) | |
| Long-term portion | $ | 85,312 |
| | $ | 71,006 |
| Long-term portion | $ | 127,526 | | | $ | 132,637 | |
| | | | | |
_______________
(1)The current portion of the asset retirement obligation is included in other accrued expenses on our consolidated balance sheets.
Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and abandonmentsurface reclamation costs considering federal and state regulatory requirements in effect.effect at that time. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Short-term asset retirement obligations are included in other accrued expenses on the consolidated balance sheets.
The revisions in estimated cash flows during 2018 were primarily due to changes in estimates of costs for materials and services related to the plugging and abandonment of wells and the shortening of the estimated expected lives of wells.
NOTE 13 - COMMITMENTS AND CONTINGENCIES
The following table presents our firm transportation, sales and processing, water delivery and disposal and purchase commitments:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ending December 31, | | | | | | |
| | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total | | Expiration
Date for Thereafter |
| Natural gas (MMcf) | | 82,264 | | | 82,264 | | | 82,489 | | | 70,296 | | | 37,029 | | | 73,050 | | | 427,392 | | | December 31, 2030 |
| Crude oil (MBbls) | | 23,360 | | | 19,685 | | | 9,882 | | | 9,855 | | | 6,561 | | | — | | | 69,343 | | | |
| Water (MBbls) | | 6,207 | | | 6,207 | | | 6,224 | | | — | | | — | | | — | | | 18,638 | | | |
| | | | | | | | | | | | | | | | |
| Purchase obligation (Tons) | | 110,000 | | | 300,000 | | | — | | | 0 | | 0 | | 0 | | 410,000 | | | |
| | | | | | | | | | | | | | | | |
Dollar commitment (in thousands) | | $ | 153,857 | | | $ | 157,370 | | | $ | 92,247 | | | $ | 77,491 | | | $ | 39,631 | | | $ | 37,811 | | | $ | 558,407 | | | |
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us and purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners, whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents gross volume information We may from time to time find ourselves unable to market our commodities at prices acceptable to us, or at all, which could cause us to be unable to meet these obligations. In such cases, we may be subject to fees, minimum margins or other payments. Payments related to our long-term firm transportation sales and processing agreements, net of interests, were $31.3 million, $21.4 million, and $27.3 million for pipeline capacitythe years ended December 31, 2021, 2020, and water delivery and disposal commitments:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ending December 31, | | | | |
| Area | | 2019 | | 2020 | | 2021 | | 2022 | | 2022 and
Through
Expiration | | Total | | Expiration
Date |
| | | | | | | | | | | | | | | |
| Natural gas (MMcf) | | | | | | | | | | | | | | |
| Wattenberg Field | | 23,934 |
| | 31,110 |
| | 31,025 |
| | 31,025 |
| | 90,897 |
| | 207,991 |
| | April 30, 2026 |
| Delaware Basin | | 48,147 |
| | 37,430 |
| | 21,307 |
| | — |
| | — |
| | 106,884 |
| | December 31, 2021 |
| Gas Marketing | | 7,117 |
| | 7,136 |
| | 7,056 |
| | 4,495 |
| | — |
| | 25,804 |
| | August 31, 2022 |
| Total | | 79,198 |
| | 75,676 |
| | 59,388 |
| | 35,520 |
| | 90,897 |
| | 340,679 |
| | |
| | | | | | | | | | | | | | | |
| Crude oil (MBbls) | | | | | | | | | | | | | | |
| Wattenberg Field | | 9,713 |
| | 5,918 |
| | 5,475 |
| | 5,475 |
| | 3,180 |
| | 29,761 |
| | April 30, 2023 |
| Delaware Basin | | 7,359 |
| | 8,784 |
| | 8,030 |
| | 8,030 |
| | 8,030 |
| | 40,233 |
| | December 31, 2023 |
| Total | | 17,072 |
| | 14,702 |
| | 13,505 |
| | 13,505 |
| | 11,210 |
| | 69,994 |
| | |
| | | | | | | | | | | | | | | |
| Water (MBbls) | | | | | | | | | | | | | | |
| Wattenberg Field | | 3,103 |
| | 6,207 |
| | 6,207 |
| | 6,207 |
| | 12,413 |
| | 34,137 |
| | December 31, 2024 |
| Delaware Basin | | 3,650 |
| | 3,660 |
| | 3,650 |
| | 3,650 |
| | 1,770 |
| | 16,380 |
| | June 26, 2023 |
| Total | | 6,753 |
| | 9,867 |
| | 9,857 |
| | 9,857 |
| | 14,183 |
| | 50,517 |
| | |
| | | | | | | | | | | | | | | |
| Dollar commitment (in thousands) | | $ | 106,844 |
| | $ | 78,209 |
| | $ | 74,409 |
| | $ | 67,354 |
| | $ | 102,925 |
| | $ | 429,741 |
| | |
| | | | | | | | | | | | | | | |
Wattenberg Field. In anticipation of our future drilling activities in the Wattenberg Field, we haveFacilities Expansion Agreements. We entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities.facilities in the Wattenberg Field. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018. The second plant is currently scheduled to be completed in the second quarter of2018 and 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments consisting of our gross wellhead volume delivered in November 2016 to this midstream provider, and aggregate incremental wellhead volume commitments of 51.598.1 MMcfd and 33.577.3 MMcfd for the first and second agreements, respectively, for seven years.respectively. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfdaggregate incremental commitments. Any shortfall in these volume commitments may be offset by other producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. The actual net shortfall in target profit margin incurred, which we guaranteed to our midstream provider, was included as part of contract assets as part of other assets on the consolidated balance sheets.
Delaware BasinFirm sales agreement. In May 2018,As of December 31, 2021 we entered intohad a firm sales agreement that is effective from June 2018 through December 2023 with an integrated marketing company for our crude oil production in the Delaware Basin. Contracted volumes are currently 14,600 barrels of crude oil per day and increase over time to 26,400 barrels of crude oil per day. These agreements areBasin through 2023. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices.
Commodity Sales. For 2018, amounts This agreement does not require physical delivery of the minimum volumes of crude oil over the contractual term. However, if we do not sell and deliver at least the minimum contract volume pursuant to the agreement, we are required to pay transportation reservation charges related to long-termthe undelivered volume. For the years ended December 31, 2021 and 2020, we did not incur material transportation volumes, netreservation charges under this agreement.
Purchase Obligation. As of December 31, 2021 we had a purchase agreement to our interest, for Wattenberg Field crude oil and Delaware Basin natural gas were $27.3 million and in accordance with the guidancebuy a minimum volume of frac sand at a fixed sales price effective June 2022 through December 2023. The obligation included in the New Revenue Standard, were netted against our crude oil and natural gas sales in our consolidated statementstable above represents the minimum financial commitments pursuant to the terms of operations. In addition, for 2018, $1.6 million related to long-term transportation volumes were recorded in transportation, gathering and processing expense in our consolidated statementsthe agreement as of operations. For each of 2017 and 2016, amounts related to long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $10.0 million and were recorded in transportation, gathering and processing expense in our consolidated statements of operations. In March 2018, we completed the disposition of our Utica Shale properties.December 31, 2021.
Litigation and Legal Items.We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying consolidated balance
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.
Action Regarding Partnerships. In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al., filed in the United States District Court for the District of Colorado. The complaint states that it is a derivative action brought by a number of limited partner investors seeking to assert claims on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP (collectively, the "Partnerships"), against PDC and includes claims for breach of fiduciary duty and breach of contract. The plaintiffs also included claims against two of our senior officers and three independent members of our Board of Directors for alleged breach of fiduciary duty. The lawsuit accuses PDC, as the managing general partner of the Partnerships, of, among other things, failing to maximize the productivity of the Partnerships’ crude oil and natural gas wells and improperly assigning the Partnerships only interests in the wells, as opposed to leasehold interests in surrounding acreage. In late April 2018, the plaintiffs filed an amendment to their complaint, which alleges additional facts and purports to add direct class action claims in addition to the original derivative claims. We filed a motion to dismiss this amended complaint and the claims against the individuals named as defendants on July 31, 2018. On February 19, 2019, the court granted the motion to dismiss, in part. It dismissed all claims against the individuals named as defendants. It also held that that the plaintiffs were time-barred from using the failure to assign acreage assignments to support their claims for breach of fiduciary duty against PDC. This action has been stayed as a result of the partnership bankruptcy proceedings described in Partnership Bankruptcy Filings below. We are currently unable to estimate any potential damages resulting from this lawsuit.
Partnership Bankruptcy Filings. On October 30, 2018, the Partnerships filed petitions under Chapter 11 of the Bankruptcy Code (the "Chapter 11 Proceedings") in the United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"). The Partnerships intend to enter into a transaction with us, pursuant to which the Partnerships will sell substantially all of their assets to us through a Chapter 11 plan of liquidation (the "Chapter 11 Plan") and provide a release of any claims, including those asserted in Dufresne, et al. v. PDC Energy, et al. (the "Dufresne Case"). The Partnerships remain in possession of their assets and continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. In addition, a third-party (the “Responsible Party”) has been designated for the Partnerships. The Responsible Party is expected to oversee all actions for the Partnerships in connection with the Chapter 11 Proceedings, including actions relating to the anticipated transactions with us and seeking approval of the Chapter 11 Plan. In late November and early December, 2018 the plaintiffs in the Dufresne Case filed several pleadings in the Bankruptcy Court, including one to dismiss the bankruptcy on grounds that PDC had no authority to hire the Responsible Party, the Responsible Party had no authority to cause the Partnerships to file bankruptcy, and the bankruptcy was filed solely for the purpose to gain a litigation advantage in and dismiss the Dufresne Case. The parties have agreed to mediate their disputes with respect to the Dufresne Case and the bankruptcy cases. As a result, on December 17, 2018 the Bankruptcy Court entered an agreed order staying the bankruptcy motions and the Dufresne Case until March 20, 2019 to allow the parties to mediate their disputes. We do not believe that the Partnership's Chapter 11 Proceedings will have a material adverse effect on our financial position, results of operations or liquidity, but we cannot predict the outcome of such proceedings.
Environmental.Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2018 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual.
On October 23, 2018, we agreed to an Administrative Order by Consent ("AOC") with the Colorado Oil and Gas Conservation Commission relating to a historical release discovered during the decommissioning of a location in Weld County, Colorado, pursuant to which, among other things, we agreed to a penalty of approximately $130,000, of which 20 percent would be suspended subject to compliance with certain corrective actions identified in the AOC. In addition to the penalty, we agreed to timely complete certain corrective actions set forth in the AOC relating to procedures for completing future work on buried or partially buried produced water vessels, and to reestablish vegetation and otherwise reclaim the location.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the EPA and a 2015 compliance advisory from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Pollution Control Division, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law.
In October 2017, we entered into a consent decree to resolve the lawsuit and the compliance advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects) of which the cash fines and the full cost of supplemental environmental projects were paid in the first and third quarters of 2018, respectively, (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations and (iii) mitigation with an estimated cost of $1.7 million. We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements.
We are in the process of implementing the consent degree program. Over the course of its execution, we have identified certain immaterial deficiencies in our implementation of the program. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $100,000.
In addition, in December 2018, we were named as a nominal defendant in a derivative action filed in the Delaware chancery court. The complaint, which seeks unspecified monetary damages and various forms of equitable relief, alleges that certain current and former members of our board of directors violated their fiduciary duties, committed waste and were unjustly enriched by, among other things, failing to implement adequate environmental safeguards in connection with the issues that gave rise to the Department of Justice lawsuit and consent decree. We believe that this lawsuit is without merit but cannot predict its outcome.
In addition, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations.
Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space and general office equipment.
The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ending December 31, | | | | |
| | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
| | | (in thousands) |
| | | | | | | | | | | | | | | |
| Minimum Lease Payments | | $ | 6,273 |
| | $ | 6,365 |
| | $ | 6,290 |
| | $ | 5,229 |
| | $ | 1,385 |
| | $ | 2,256 |
| | $ | 27,798 |
|
| | | | | | | | | | | | | | | |
Operating lease expense for 2018, 2017 and 2016 was $26.7 million, $17.2 million and $10.2 million, respectively.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 14 - COMMON STOCK
Stock-Based Compensation Plans
2018 Equity Incentive Plan. In May 2018,2020, our stockholders approved aan amendment to increase the number of shares of our common stock reserved for issuance pursuant to our long-term equity compensation plan for our employees and non-employee directors (the “2018 Plan”). from 1,800,000 to 7,050,000 shares. The 2018 Plan providesexpires in March 2028. The capital stock available for a reserve of 1,800,000 shares of our common stock that may be issued pursuant to awardsissuance under the 2018 Plan and a termconsists of shares of the Company’s authorized but unissued common stock or previously issued common stock that expires in March 2028. As of December 31, 2018, no shares havehas been issuedreacquired by the Company. Additionally, to the extent that an award under the 2018 plan. Shares issued may be either authorized but unissued shares, treasury sharesPlan, in whole or any combination. Additionally, the 2018 Plan permits the reuse or reissuance of shares of common stock which werein part, is canceled, expired, forfeited, settled in cash or paid out in the form of cash. However, shares tendered or withheld to satisfy the exercise price of options or tax withholding obligations, and shares covering the portion of exercised stock-settled stock appreciation rights ("SARs") (regardless of the numberotherwise terminated without delivery of shares, actually delivered), count against the share limit.such shares remain available for issuance. Any shares withheld for taxes cannot be recycled under this plan. Awards may be issued in the form of options, SARs,stock appreciation rights (“SARs”), restricted stock, restricted stock units ("RSUs"(“RSUs”), performance stock units ("PSUs"(“PSUs”) and other stock-based awards. Awards may vest over periods of continued service or upon the satisfaction of performance conditions set at the discretion of the Compensation Committee of our Boardboard of Directorsdirectors (the "Compensation Committee"“Compensation Committee”), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
have a maximum exercisable period of ten years. As of December 31, 2021, there were 4,177,611 shares available for grant under the 2018 Plan.
2010 Long-Term Equity Compensation Plan. Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was most recently approved by stockholders in 2013 (as the same has been amended and restated from time to time, the "2010 Plan"(the “2010 Plan”), will remainremains outstanding and we may continue to use the 2010 Plan to grant awards. However, the share reserve ofNo awards may be granted under the 2010 Plan is nearly depleted.on or after June 5, 2023. As of December 31, 2018,2021, there were 284,152314,413 shares available for grant under the 2010 Plan.
2015 SRC Equity Incentive Plan. Pursuant to the closing of the SRC Acquisition, SRC granted PSUs to certain SRC executives (the “SRC PSUs”) under the 2015 SRC Equity Incentive Plan (the “2015 SRC Plan”). The SRC PSUs were converted into 155,928 PDC PSUs and remained subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the closing of the SRC Acquisition. As of December 31, 2021, all converted SRC PSUs vested and there were no shares available for grant under the 2015 SRC Plan.
The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented:
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | (in thousands) |
| | | | | | | |
| Stock-based compensation expense | | $ | 21,782 |
| | $ | 19,353 |
| | $ | 19,502 |
|
| Income tax benefit | | (5,210 | ) | | (7,372 | ) | | (7,296 | ) |
| Net stock-based compensation expense | | $ | 16,572 |
| | $ | 11,981 |
| | $ | 12,206 |
|
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| | (in thousands) |
| General and administrative expense | | $ | 21,830 | | | $ | 21,182 | | | $ | 22,754 | |
| Lease operating expense | | 1,193 | | | 1,018 | | | 1,083 | |
| Total stock-based compensation expense | | $ | 23,023 | | | $ | 22,200 | | | $ | 23,837 | |
Restricted Stock Appreciation RightsUnits
The SARsCompany grants to executive officers and employees time-based RSUs, which vest ratably over a three-year period and may generally be exercised at any point after vesting through ten years from the dateservice period. The fair value of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess ofthese time-based RSUs is based on the market price of the awardour common stock on the grant date of exercise over the market price of the award on the date of issuance.
The Compensation Committee awarded SARs to our executive officers in 2017 and 2016. There were no SARs awarded to our executive officers in 2018. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 |
| | | | |
| Expected term of award (in years) | 6.0 years |
| | 6.0 years |
|
| Risk-free interest rate | 2.0 | % | | 1.8 | % |
| Expected volatility | 53.3 | % | | 54.5 | % |
| Weighted-average grant date fair value per share | $ | 38.58 |
| | $ | 26.96 |
|
The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents the changes in our SARs for all periods presented (in thousands, except per share data):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | Number of
SARs | | Weighted-Average
Exercise
Price | | Average Remaining Contractual
Term (in years) | | Aggregate Intrinsic
Value | | Number of
SARs | | Weighted-Average
Exercise
Price | | Aggregate Intrinsic
Value | | Number of
SARs | | Weighted-Average
Exercise
Price | | Aggregate Intrinsic
Value |
| Outstanding at January 1, | 298,220 |
| | $ | 47.39 |
| | 6.5 |
| | $ | 2,490 |
| | 244,078 |
| | $ | 41.36 |
| | $ | 7,620 |
| | 326,453 |
| | $ | 38.99 |
| | $ | 4,697 |
|
| Awarded | — |
| | — |
| | — |
| | — |
| | 54,142 |
| | 74.57 |
| | — |
| | 58,709 |
| | 51.63 |
| | — |
|
| Exercised | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (141,084 | ) | | 40.16 |
| | 2,770 |
|
| Modified | 63,969 |
| | 42.83 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Expired | (71,931 | ) | | 46.34 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Outstanding at December 31, | 290,258 |
| | 46.64 |
| | 4.6 |
| | 125 |
| | 298,220 |
| | 47.39 |
| | 2,490 |
| | 244,078 |
| | 41.36 |
| | 7,620 |
|
| Exercisable at December 31, | 260,101 |
| | 44.88 |
| | 4.3 |
| | 125 |
| | 223,865 |
| | 43.28 |
| | 2,267 |
| | 174,919 |
| | 38.72 |
| | 5,924 |
|
We expect all SARs outstanding as of December 31, 2018 to vest. The SARS modified during 2018 were related to one employee and the total compensation cost associated with the modification was not material to our consolidated statement of operations. Total compensation cost related to SARs granted and not yetis recognized in our consolidated statements of operations as of December 31, 2018 was $0.5 million. The cost is expected to be recognized over a weighted-average period of 0.5 years.
Restricted Stock Units
Time-Based Awards. The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years.period. The time-based RSUs generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed.
The following table presents the changes in non-vested time-based RSUs to eligible employees, including executive officers, during 2018:the year ended December 31, 2021:
| | | | | | | | | | | |
| Shares | | Weighted Average Grant-Date Fair Value per Share |
| Non-vested at beginning of period | 1,150,970 | | | $ | 20.14 | |
| Granted | 657,972 | | | 33.64 | |
| Vested | (547,985) | | | 24.86 | |
| Forfeited | (95,770) | | | 22.74 | |
| Non-vested at end of period | 1,165,187 | | | 25.33 | |
|
| | | | | | |
| | Shares | | Weighted-Average
Grant Date
Fair Value per Share |
| | | | |
| Non-vested at December 31, 2017 | 472,132 |
| | $ | 60.23 |
|
| Granted | 446,743 |
| | 50.69 |
|
| Vested | (249,317 | ) | | 58.95 |
|
| Forfeited | (51,151 | ) | | 56.45 |
|
| Non-vested at December 31, 2018 | 618,407 |
| | 54.16 |
|
| | | | |
The following table presents the weighted-average grant dateweighted average grant-date fair value per shareof restricted stock units was $33.64, $11.98 and related information as of/$40.34 for the periods presented:
|
| | | | | | | | | | | |
| | As of/Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands, except per share data) |
| | | | | | |
| Total intrinsic value of time-based awards vested | $ | 12,282 |
| | $ | 16,303 |
| | $ | 18,973 |
|
| Total intrinsic value of time-based awards non-vested | 18,404 |
| | 24,334 |
| | 34,812 |
|
| Market price per common share as of December 31, | 29.76 |
| | 51.54 |
| | 72.58 |
|
| Weighted-average grant date fair value per share | 50.69 |
| | 65.14 |
| | 58.52 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
years ended December 31, 2021, 2020 and 2019, respectively. The total grant-date fair value of restricted stock units that vested for the years ended December 31, 2021, 2020 and 2019 was $13.6 million, $20.4 million and $16.3 million, respectively. Total compensation cost related to non-vested time-based awards and not yet recognized in ouron the consolidated statements of operations as of December 31, 20182021 was $20.7$18.2 million. This cost is expected to be recognized over a weighted-averageweighted average period of 1.81.6 years.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Performance Stock Units
Market-Based Awards. The fair value of theCompany grants to certain executive officers PSUs which are subject to market-based PSUs is amortized ratably over the requisitevesting criteria as well as a three-year service period, primarily three years.period. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting periodachieved. The fair value of three years.the market-based PSUs is amortized ratably over the requisite service period. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
In February 2018, the
The Compensation Committee awarded a total of 90,778207,655 market-based PSUs to our executive officers.officers during 2021. In addition to continuous employment, the vesting of these PSUs is contingent on a combination of absolute stock performance and our total stockholder return ("TSR"(“TSR”), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2020,2023, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between 0 percentzero and 200250 percent of the target PSUs awarded.
The weighted-average grant dategrant-date fair value per PSU granted was computedestimated using thea Monte Carlo pricingvaluation model. The Monte Carlo valuation model using the following assumptions:
|
| | | | | | | | | |
| | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | | | | | |
| Expected term of award (in years) | | 3 years |
| | 3 years |
| | 3 years |
|
| Risk-free interest rate | | 2.4 | % | | 1.4 | % | | 1.2 | % |
| Expected volatility | | 42.3 | % | | 51.4 | % | | 52.3 | % |
is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our common stock historical volatility.
The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the periods presented:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| Expected term of award (in years) | | 3 | | 3 | | 3 |
| Risk-free interest rate | | 0.2 | % | | 1.4 | % | | 2.5 | % |
| Expected volatility | | 84.6 | % | | 46.6 | % | | 41.4 | % |
| Weighted average grant-date fair value per share | | $ | 54.01 | | | $ | 33.52 | | | $ | 56.68 | |
0The expected term of the awards is based on the number of years from the grant date through the end of the performance period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant, extrapolated to approximate the life of the awards. The expected volatility was based on our common stock historical volatility, as well as that of our peer group.
The following table presents the change in non-vested market-based awards during 2018:the year ended December 31, 2021:
|
| | | | | | | |
| | | Shares
| | Weighted-Average
Grant Date
Fair Value per Share
|
| | | | | |
Non-vested at December 31, 2017
| | 52,349 |
| | $ | 84.06 |
|
Granted
| | 90,778 |
| | 69.98 |
|
Vested
| | (18,941 | ) | | 72.54 |
|
Forfeited
| | (21,272 | ) | | 78.65 |
|
Non-vested at December 31, 2018
| | 102,914 |
| | 74.88 |
|
| | | | | | | | | | | | | | |
| | Shares | | Weighted Average Grant-Date Fair Value per Share |
| Non-vested at December 31, 2020 | | 499,547 | | | $ | 38.66 | |
| Granted | | 207,655 | | | 54.01 | |
| Vested | | (267,973) | | | 43.10 | |
| | | | |
| Non-vested at December 31, 2021 | | 439,229 | | | 43.21 | |
The following table presents the weighted-average grant datetotal grant-date fair value per shareof performance stock units that vested in the years ended December 31, 2021, 2020 and related information as of/2019 was $11.6 million, $4.7 million and $2.0 million, respectively. On December 31, 2021, the service period lapsed on 112,045 performance stock units granted in 2019 and 155,928 SRC PSUs that earned 1.90 shares for the periods presented:
|
| | | | | | | | | | | |
| | As of/Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands, except per share data) |
| | | | | | |
| Total intrinsic value of market-based awards vested | $ | 620 |
| | $ | 2,687 |
| | $ | 6,562 |
|
| Total intrinsic value of market-based awards non-vested | 3,063 |
| | 2,698 |
| | 3,514 |
|
| Market price per common share as of December 31, | 29.76 |
| | 51.54 |
| | 72.58 |
|
| Weighted-average grant date fair value per share | 69.98 |
| | 94.02 |
| | 72.54 |
|
each vested award resulting in 503,615 aggregate shares of common stock being issued in January 2022. Total compensation cost related to non-vested market-based awards not yet recognized in ouron the consolidated statements of operations as of December 31, 20182021 was $4.7$10.5 million. This cost is expected to be recognized over a weighted-averageweighted average period of 1.81.5 years.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Preferred Stock
Treasury Share Purchases
In accordance with our stock-based compensation plans, employees may surrender shares of our common stock to settle tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are withheld for reissuance for new grants. For shares reissued for new grants under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2018, we acquired 102,647 shares for payment of tax liabilities and reissued 104,068 shares. As of December 31, 2018, 33,105 shares were available for reissuance pursuant to our 2010 Plan. During the year ended December 31, 2017, we acquired 107,357 shares for payment of tax liabilities and reissued 83,228 shares. As of December 31, 2017, 34,526 shares were available for reissuance pursuant to our 2010 Plan. In addition to the shares available for reissuance as of December 31, 2018 and 2017, we had 12,115 shares and 21,401 shares, respectively, of treasury stock related to a rabbi trust.
Preferred stock
We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Boardboard of Directorsdirectors from time to time. Through December 31, 2021, no shares of preferred stock have been issued.
Stock Repurchase Program
In 2019, our board of directors approved the repurchase of up to $200 million of our outstanding common stock (the “Stock Repurchase Program”). Effective upon the closing of the SRC Acquisition, our board of directors approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million. Repurchases under the Stock Repurchase Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Stock Repurchase Program does not require any specific number of shares to be acquired, is subject to market conditions and can be modified or discontinued by the timeboard of issuance.directors at any time. Pursuant to the Stock Repurchase Program, we repurchased 3.8 million and 1.3 million shares of outstanding common stock at a cost of $159.5 million and $23.8 million during the years ended December 31, 2021 and 2020, respectively. We suspended the program in 2020 due to adverse market conditions but reinstated it in 2021. As of December 31, 2018,2021, $187.3 million remained available under the program for repurchases of our outstanding common stock. In February 2022, our board of directors increased the size of the program to $1.25 billion and extended it through December 31, 2023. The Stock Repurchase Program is being implemented at the discretion of our board of directors and may be suspended, modified, extended or discontinued by our board of directors at any time.
Dividends
In the second quarter of 2021, our board of directors commenced the declaration and payment of quarterly cash dividends of $0.12 per share of our outstanding common stock. In December 2021, our board of directors declared and paid a special dividend of $0.50 per share of our outstanding common stock in addition to the fourth quarter dividend. For the year ended December 31, 2021, our dividends paid totaled $0.86 per share of common stock or $83.6 million. All RSUs and PSUs receive a dividend equivalent per unit, recognized as a liability included in other liabilities on the consolidated balance sheets, until the recipients receive the equivalents upon vesting. Dividends declared were recorded as a reduction of additional paid-in capital as there were no preferred shares had been issued.retained earnings as of the date of declaration. Future dividend payments must be approved by our board of directors and will depend on our liquidity, financial requirements, and other factors considered relevant by our board.
NOTE 15 - INCOME TAXES
The table below presents the components of our provision for income tax (expense) benefit for the yearsperiods presented:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (in thousands) |
| Current: | | | | | |
| Federal | $ | — | | | $ | 1,592 | | | $ | 1,366 | |
| State | (200) | | | (220) | | | (300) | |
| Total current income tax benefit | (200) | | | 1,372 | | | 1,066 | |
| Deferred: | | | | | |
| Federal | (23,790) | | | 5,460 | | | 4,507 | |
| State | (2,593) | | | 1,070 | | | (2,251) | |
| Total deferred income tax (expense) benefit | (26,383) | | | 6,530 | | | 2,256 | |
| Income tax (expense) benefit | $ | (26,583) | | | $ | 7,902 | | | $ | 3,322 | |
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
| Current: | | | | | |
| Federal | $ | 886 |
| | $ | 8,443 |
| | $ | 9,646 |
|
| State | (188 | ) | | (200 | ) | | 300 |
|
| Total current income tax benefit | 698 |
| | 8,243 |
| | 9,946 |
|
| Deferred: | | | | | |
| Federal | (1,986 | ) | | 193,809 |
| | 118,427 |
|
| State | (4,118 | ) | | 9,876 |
| | 18,822 |
|
| Total deferred income tax (expense) benefit | (6,104 | ) | | 203,685 |
| | 137,249 |
|
| Income tax (expense) benefit | $ | (5,406 | ) | | $ | 211,928 |
| | $ | 147,195 |
|
The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes:taxes for the periods presented:
| | | | Year Ended December 31, | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | | Year Ended December 31, |
| | | | | | | | 2021 | | 2020 | | 2019 |
| Federal statutory tax rate | 21.0 | % | | 35.0 | % | | 35.0 | % | Federal statutory tax rate | 21.0 | % | | 21.0 | % | | 21.0 | % |
| State income tax, net | (6.4 | ) | | 1.8 |
| | 2.6 |
| State income tax, net | 3.2 | | | 3.0 | | | 3.6 | |
| Federal tax credits | (52.1 | ) | | — |
| | — |
| Federal tax credits | — | | | — | | | (3.3) | |
| Effect of state income tax rate changes | 6.7 |
| | — |
| | 0.6 |
| Effect of state income tax rate changes | — | | | 0.2 | | | (6.4) | |
| Change in valuation allowance | 45.5 |
| | — |
| | — |
| Change in valuation allowance | (19.8) | | | (22.1) | | | (0.6) | |
| Non-deductible compensation | 21.8 |
| | (0.3 | ) | | (0.5 | ) | Non-deductible compensation | 0.3 | | | (0.6) | | | (5.0) | |
| Non-deductible acquisition costs | | Non-deductible acquisition costs | — | | | (0.1) | | | (2.3) | |
| Non-deductible government relations | 31.8 |
| | — |
| | — |
| Non-deductible government relations | 0.1 | | | (0.1) | | | (1.0) | |
| Other non-deductible items | 4.9 |
| | — |
| | — |
| Other non-deductible items | — | | | — | | | (0.5) | |
| Federal tax reform rate reduction | — |
| | 33.7 |
| | — |
| |
| Non-deductible goodwill impairment | — |
| | (7.7 | ) | | — |
| |
| | Other | (0.4 | ) | | (0.1 | ) | | (0.3 | ) | Other | — | | | (0.2) | | | — | |
| Effective tax rate | 72.8 | % | | 62.4 | % | | 37.4 | % | Effective tax rate | 4.8 | % | | 1.1 | % | | 5.5 | % |
PDC ENERGY, INC.The effective income tax rates for 2021 and 2020 were 4.8 percent and 1.1 percent on the respective pre-tax income or loss. The effective tax rates of 4.8 percent for 2021 and 1.1 percent for 2020 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 or loss due to the valuation allowance in effect at December 31, 2021 and 2020. The effective tax rate of 5.5 percent for 2019 differs from the statutory U.S. federal income tax rate of 21 percent due to state income taxes, non-deductible lobbying expenses, stock-based compensation and nondeductible officers’ compensation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2018 and 2017 are presented below.The 2017 amounts includeas of the reductiondates indicated:
| | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| (in thousands) |
| Deferred tax assets: | | | |
| Deferred compensation | $ | 9,949 | | | $ | 10,472 | |
| Asset retirement obligations | 38,274 | | | 39,371 | |
| Federal NOL carryforward | 97,555 | | | 97,880 | |
| State NOL and tax credit carryforwards, net | 20,266 | | | 21,034 | |
| Federal tax - credit carryforwards | 3,059 | | | 3,059 | |
| | | |
| Net change in fair value of unsettled commodity derivatives | 88,053 | | | 18,351 | |
| Prepaid revenue | 3,854 | | | 4,364 | |
| Other | 4,454 | | | 5,741 | |
| Valuation allowance | (56,634) | | | (165,575) | |
| Total gross deferred tax assets | 208,830 | | | 34,697 | |
| | | |
| Deferred tax liabilities: | | | |
| Properties and equipment | 235,213 | | | 33,183 | |
| | | |
| | | |
| Convertible debt | — | | | 1,514 | |
| Total gross deferred tax liabilities | 235,213 | | | 34,697 | |
| Net deferred tax liability | $ | 26,383 | | | $ | — | |
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
We consider whether a portion, or all, of our deferred tax assets and liabilities to(“DTAs”) will be realized based on a projected combined federal and statemore 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 scheduled reversal of deferred tax rateliabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. The oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to continue to provide a valuation allowance against our DTAs as of 23.9 percent asDecember 31, 2021 and 2020 since we cannot conclude that it is more likely than not that our DTAs will be fully realized in future periods.
Future events or new evidence which may lead us to conclude that it is more likely than not that our DTAs will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. Given recent improvements in oil and gas prices and improvements in our current earnings, we believe there is a resultreasonable possibility that, if oil and natural gas prices remain similar to December 31, 2021 pricing levels, sufficient positive evidence may become available within the next 12 months to allow us to reach a conclusion that all or a significant portion of the 2017 Tax Act.valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense in the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change based on the level of profitability that we actually achieve.
|
| | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 |
| | (in thousands) |
| Deferred tax assets: | | | |
| Deferred compensation | $ | 9,963 |
| | $ | 6,059 |
|
| Asset retirement obligations | 27,166 |
| | 21,760 |
|
| Federal NOL carryforward | 54,736 |
| | 19,386 |
|
| State NOL and tax credit carryforwards, net | 13,223 |
| | 7,815 |
|
| Federal tax - credit carryforwards | 7,756 |
| | 4,366 |
|
| Net change in fair value of unsettled derivatives | — |
| | 20,929 |
|
| Prepaid revenue | 5,288 |
| | — |
|
| Other | 4,647 |
| | 2,453 |
|
| Valuation allowance | (3,380 | ) | | — |
|
| Total gross deferred tax assets | 119,399 |
| | 82,768 |
|
| | | | |
| Deferred tax liabilities: | | | |
| Properties and equipment | 270,565 |
| | 267,498 |
|
| Net change in fair value of unsettled derivatives | 41,496 |
| | — |
|
| Convertible debt | 5,434 |
| | 7,262 |
|
| Total gross deferred tax liabilities | 317,495 |
| | 274,760 |
|
| Net deferred tax liability | $ | 198,096 |
| | $ | 191,992 |
|
During the year endingAs of December 31, 2018,2021, we generated a federalhave estimated net operating loss ("NOL"carryforwards (“NOLs”) for federal income tax purposes of $169.1$464.5 million, of which $304 million was generated before January 1, 2018 and have prior year federal NOL carryforwardsis not subject to the 80 percent limitation of $31.5 million thattaxable income. Such NOLs will begin to expire beginning in 2036. Also,2033. In 2016, we acquired a federal NOL of $60.1 million as a component of our 2016 acquisition in the Delaware Basin that will begin to expire in 20342033. Also, we acquired a federal NOL of $232.5 million as a component of the SRC Acquisition that will begin to expire in 2037. The federal NOLs acquired as part of the Delaware Basin acquisition and isthe SRC Acquisition are subject to an annual limitation of $15.1 million and $16.1 million, respectively, as a result of the acquisition, which constitutesboth acquisitions constitute a change of ownership as defined under IRSInternal Revenue Service (“IRS”) Code Section 382.
We have a marginal gas well credit of $5.1 million that can be carried forward 20 years and we have alternative minimum tax credits of $2.7 million that may be carried forward, and pursuant to the new tax law will be refunded over the next three years.
As of December 31, 2018,2021, we have state NOL carryforwards of $284.6$479.4 million that begin to expire in 20302029 and state credit carryforwards of $3.3$3.9 million that begin to expire in 2022. Due to the potential non-utilization of our state tax credit carryforwards before their expiration, we have recorded a valuation allowance for the future tax benefit of these credit carryforwards.
Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2018. The2021. As of December 31, 2021, there is no liability for unrecognized income tax benefits.
We are subject to the following material taxing jurisdictions: U.S., Colorado, West Virginia, and Texas. As of December 31, 2021, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We are open to federal and state tax audits until the applicable statutes of limitations expire, however, the ability for mostthe tax authority to adjust the NOL will continue until three years after the NOL is utilized. The statute of ourlimitations has expired for all federal and state tax jurisdictions are openreturns filed for tax year 2014 forward.
periods ending before 2016. The IRS partiallyhas accepted our 20172019 federal income tax return.return with no tax adjustments. The 20172020 federal tax return is currently in the IRS CAPCompliance Assurance Program (the “CAP Program”) post-filing review process, with no significant tax adjustments currently proposed.process. We are currently participatingcontinue to voluntarily participate in the IRS CAP Program for the review of our 2018 through 20192021 tax years.year. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. The statutes of limitations for most of our state tax jurisdictions are open for tax years after 2016.
As of December 31, 2018, we were current with our income tax filings in all applicable state jurisdictions.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 16 - EARNINGS PER SHARE
Basic earnings per share is computed by dividing net earnings by the weighted-averageweighted average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options,equity-based employee awards, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents our weighted-averageweighted average basic and diluted shares outstanding:outstanding for the periods presented:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (in thousands) |
| Weighted average common shares outstanding - basic | 98,546 | | | 98,251 | | | 64,032 | |
| Dilutive effect of: | | | | | |
| RSUs and PSUs | 1,596 | | | — | | | — | |
| | | | | |
| Other equity-based awards | 12 | | | — | | | — | |
| Weighted average common shares and equivalents outstanding - diluted | 100,154 | | | 98,251 | | | 64,032 | |
|
| | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
| | | | | | |
| Weighted-average common shares outstanding - basic | 66,059 |
| | 65,837 |
| | 49,052 |
|
| Dilutive effect of: | | | | | |
| RSUs and PSUs | 173 |
| | — |
| | — |
|
| Other equity-based awards | 71 |
| | — |
| | — |
|
| Weighted-average common shares and equivalents outstanding - diluted | 66,303 |
| | 65,837 |
| | 49,052 |
|
For 2017 and 2016, weWe reported a net loss.loss for the years ended December 31, 2020 and 2019. As a result, our basic and diluted weighted-averageweighted average common shares outstanding were the same for those periods because the effect of the common share equivalents was anti-dilutive.
The following table presents the weighted-averageweighted average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect:effect for the periods presented:
| | | | | | | | | Year Ended December 31, |
| | Year Ended December 31, | | 2021 | | 2020 | | 2019 |
| | 2018 | | 2017 | | 2016 | | (in thousands) |
| Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: | | Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: | |
| RSUs and PSUs | | RSUs and PSUs | 28 | | | 1,707 | | | 989 | |
| | (in thousands) | |
| | | | | | | |
| Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: | | | | | | |
| RSUs and PSUs | 145 |
| | 590 |
| | 689 |
| |
| Convertible notes | — |
| | — |
| | 292 |
| |
| Other equity-based awards | 109 |
| | 75 |
| | 109 |
| Other equity-based awards | 116 | | | 229 | | | 302 | |
| Total anti-dilutive common share equivalents | 254 |
| | 665 |
| | 1,090 |
| Total anti-dilutive common share equivalents | 144 | | | 1,936 | | | 1,291 | |
In September 2016, we issuedWhen outstanding, the 2021 Convertible Notes which gave the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes would bewere not included in the diluted earnings per share calculation using the treasury stock method iffor any periods presented as the average market share price had exceededof our common stock did not exceed the $85.39 conversion price duringprice. Further, the periods presented.2021 Convertible Notes were fully retired on the maturity date, September 15, 2021.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 17 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| | (in thousands) |
| Supplemental cash flow information | | | | | | |
| Cash payments (receipts) for | | | | | | |
| Interest, net of capitalized interest | | $ | 66,647 | | | $ | 75,506 | | | $ | 57,439 | |
| Income taxes | | (1,057) | | | 9 | | | (1,167) | |
| Non-cash investing and financing activities | | | | | | |
| | | | | | |
| Change in accounts payable related to capital expenditures | | 519 | | | (28,676) | | | (68,246) | |
| Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals | | 11,673 | | | 54,984 | | | 29,533 | |
| | | | | | |
| | | | | | |
| Issuance of common stock for acquisition of crude oil and natural gas properties, net | | — | | | 1,009,015 | | | — | |
| | | | | | |
| Cash paid for amounts included in the measurement of lease liabilities | | | | | | |
| Operating cash flows from operating leases | | $ | 7,603 | | | $ | 9,246 | | | $ | 5,301 | |
| Operating cash flows from finance leases | | 117 | | | 156 | | | 253 | |
| | | | | | |
| Right-of-use assets obtained in exchange for lease obligations | | | | | | |
| Operating leases | | $ | 1,457 | | | $ | 4,305 | | | $ | 1,428 | |
| Finance leases | | 2,109 | | | 703 | | | 2,323 | |
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | (in thousands) |
| Supplemental cash flow information: | | | | | | |
| | | | | | | |
| Cash payments (receipts) for: | | | | | | |
| Interest, net of capitalized interest | | $ | 55,586 |
| | $ | 69,880 |
| | $ | 43,406 |
|
| Income taxes | | (6,719 | ) | | (13,925 | ) | | 167 |
|
| Non-cash investing activities: | | | | | | |
| Issuance of common stock for acquisition of crude oil and natural gas properties | | — |
| | — |
| | 690,702 |
|
| Change in accounts payable related to capital expenditures | | 36,328 |
| | 50,761 |
| | (40,448 | ) |
| Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal | | 37,136 |
| | 839 |
| | 4,894 |
|
Purchase of properties and equipment under capital leases
| | 1,940 |
| | 3,497 |
| | 1,404 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 18 - SUBSIDIARY GUARANTOR
PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the consolidating financial information separately for:
|
| |
(i) | PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; |
(ii) | PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes; |
(iii) | Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and |
(iv) | Parent and subsidiaries on a consolidated basis ("Consolidated"). |
The Guarantor was 100 percent owned by the Parent beginning in December 2016. The senior notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the consolidating financial information follows the same accounting policies as described in the notes to the consolidated financial statements.
The following consolidating financial statements have been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | | | | | | | | | | |
| | | Consolidating Balance Sheets |
| | | December 31, 2018 |
| | | Parent | | Guarantor | | Eliminations | | Consolidated |
| | | (in thousands) |
| Assets | | | | | | | | |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 1,398 |
| | $ | — |
| | $ | — |
| | $ | 1,398 |
|
| Accounts receivable, net | | 146,529 |
| | 34,905 |
| | — |
| | 181,434 |
|
| Fair value of derivatives | | 84,492 |
| | — |
| | — |
| | 84,492 |
|
| Prepaid expenses and other current assets | | 6,725 |
| | 411 |
| | — |
| | 7,136 |
|
| Total current assets | | 239,144 |
| | 35,316 |
| | — |
| | 274,460 |
|
| Properties and equipment, net | | 2,270,711 |
| | 1,732,151 |
| | — |
| | 4,002,862 |
|
| Assets held-for-sale | | — |
| | 140,705 |
| | — |
| | 140,705 |
|
| Intercompany receivable | | 451,601 |
| | — |
| | (451,601 | ) | | — |
|
| Investment in subsidiaries | | 1,316,945 |
| | — |
| | (1,316,945 | ) | | — |
|
| Fair value of derivatives | | 93,722 |
| | — |
| | — |
| | 93,722 |
|
| Other assets | | 30,084 |
| | 2,312 |
| | — |
| | 32,396 |
|
| Total Assets | | $ | 4,402,207 |
| | $ | 1,910,484 |
| | $ | (1,768,546 | ) | | $ | 4,544,145 |
|
| | | | | | | | | |
| Liabilities and Stockholders' Equity | | | | | | | | |
| Liabilities | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 110,847 |
| | $ | 71,017 |
| | $ | — |
| | $ | 181,864 |
|
| Production tax liability | | 53,309 |
| | 7,410 |
| | — |
| | 60,719 |
|
| Fair value of derivatives | | 3,364 |
| | — |
| | — |
| | 3,364 |
|
| Funds held for distribution | | 90,183 |
| | 15,601 |
| | — |
| | 105,784 |
|
| Accrued interest payable | | 14,143 |
| | 7 |
| | — |
| | 14,150 |
|
| Other accrued expenses | | 73,689 |
| | 1,444 |
| | — |
| | 75,133 |
|
| Total current liabilities | | 345,535 |
| | 95,479 |
| | — |
| | 441,014 |
|
| Intercompany payable | | — |
| | 451,601 |
| | (451,601 | ) | | — |
|
| Long-term debt | | 1,194,876 |
| | — |
| | — |
| | 1,194,876 |
|
| Deferred income taxes | | 162,368 |
| | 35,728 |
| | — |
| | 198,096 |
|
| Asset retirement obligations | | 79,904 |
| | 5,408 |
| | — |
| | 85,312 |
|
| Liabilities held-for-sale | | — |
| | 4,111 |
| | — |
| | 4,111 |
|
| Fair value of derivatives | | 1,364 |
| | — |
| | — |
| | 1,364 |
|
| Other liabilities | | 91,452 |
| | 1,212 |
| | — |
| | 92,664 |
|
| Total liabilities | | 1,875,499 |
| | 593,539 |
| | (451,601 | ) | | 2,017,437 |
|
| | | | | | | | | |
| Stockholders' equity | | | | | | | | |
| Common shares | | 661 |
| | — |
| | — |
| | 661 |
|
| Additional paid-in capital | | 2,519,423 |
| | 1,766,775 |
| | (1,766,775 | ) | | 2,519,423 |
|
| Retained earnings | | 8,727 |
| | (449,830 | ) | | 449,830 |
| | 8,727 |
|
| Treasury shares | | (2,103 | ) | | — |
| | — |
| | (2,103 | ) |
| Total stockholders' equity | | 2,526,708 |
| | 1,316,945 |
| | (1,316,945 | ) | | 2,526,708 |
|
| Total Liabilities and Stockholders' Equity | | $ | 4,402,207 |
| | $ | 1,910,484 |
| | $ | (1,768,546 | ) | | $ | 4,544,145 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | | | | | | | | | | |
| | | Consolidating Balance Sheets |
| | | December 31, 2017 |
| | | Parent | | Guarantor | | Eliminations | | Consolidated |
| | | (in thousands) |
| Assets | | | | | | | | |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 180,675 |
| | $ | — |
| | $ | — |
| | $ | 180,675 |
|
| Accounts receivable, net | | 160,490 |
| | 37,108 |
| | — |
| | 197,598 |
|
| Fair value of derivatives | | 14,338 |
| | — |
| | — |
| | 14,338 |
|
| Prepaid expenses and other current assets | | 8,284 |
| | 329 |
| | — |
| | 8,613 |
|
| Total current assets | | 363,787 |
| | 37,437 |
| | — |
| | 401,224 |
|
| Properties and equipment, net | | 1,891,314 |
| | 2,042,153 |
| | — |
| | 3,933,467 |
|
| Assets held-for-sale | | 40,583 |
| | — |
| | — |
| | 40,583 |
|
| Intercompany receivable | | 250,279 |
| | — |
| | (250,279 | ) | | — |
|
| Investment in subsidiaries | | 1,617,537 |
| | — |
| | (1,617,537 | ) | | — |
|
| Other assets | | 42,547 |
| | 2,569 |
| | — |
| | 45,116 |
|
| Total Assets | | $ | 4,206,047 |
| | $ | 2,082,159 |
| | $ | (1,867,816 | ) | | $ | 4,420,390 |
|
| | | | | | | | | |
| Liabilities and Stockholders' Equity | | | | | | | | |
| Liabilities | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 85,000 |
| | $ | 65,067 |
| | $ | — |
| | $ | 150,067 |
|
| Production tax liability | | 35,902 |
| | 1,752 |
| | — |
| | 37,654 |
|
| Fair value of derivatives | | 79,302 |
| | — |
| | — |
| | 79,302 |
|
| Funds held for distribution | | 83,898 |
| | 11,913 |
| | — |
| | 95,811 |
|
| Accrued interest payable | | 11,812 |
| | 3 |
| | — |
| | 11,815 |
|
| Other accrued expenses | | 42,543 |
| | 444 |
| | — |
| | 42,987 |
|
| Total current liabilities | | 338,457 |
| | 79,179 |
| | — |
| | 417,636 |
|
| Intercompany payable | | — |
| | 250,279 |
| | (250,279 | ) | | — |
|
| Long-term debt | | 1,151,932 |
| | — |
| | — |
| | 1,151,932 |
|
| Deferred income taxes | | 62,857 |
| | 129,135 |
| | — |
| | 191,992 |
|
| Asset retirement obligations | | 65,301 |
| | 5,705 |
| | — |
| | 71,006 |
|
| Liabilities held-for-sale | | 499 |
| | — |
| | — |
| | 499 |
|
| Fair value of derivatives | | 22,343 |
| | — |
| | — |
| | 22,343 |
|
| Other liabilities | | 57,009 |
| | 324 |
| | — |
| | 57,333 |
|
| Total liabilities | | 1,698,398 |
| | 464,622 |
| | (250,279 | ) | | 1,912,741 |
|
| | | | | | | | | |
| Stockholders' equity | | | | | | | | |
| Common shares | | 659 |
| | — |
| | — |
| | 659 |
|
| Additional paid-in capital | | 2,503,294 |
| | 1,766,775 |
| | (1,766,775 | ) | | 2,503,294 |
|
| Retained earnings | | 6,704 |
| | (149,238 | ) | | 149,238 |
| | 6,704 |
|
| Treasury shares | | (3,008 | ) | | — |
| | — |
| | (3,008 | ) |
| Total stockholders' equity | | 2,507,649 |
| | 1,617,537 |
| | (1,617,537 | ) | | 2,507,649 |
|
| Total Liabilities and Stockholders' Equity | | $ | 4,206,047 |
| | $ | 2,082,159 |
| | $ | (1,867,816 | ) | | $ | 4,420,390 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | | | | | | | | | | |
| | | Consolidating Statements of Operations |
| | | Year Ended December 31, 2018 |
| | | Parent | | Guarantor | | Eliminations | | Consolidated |
| | | (in thousands) |
| | | | | | | | | |
| Revenues | | | | | | | | |
| Crude oil, natural gas and NGLs sales | | $ | 1,050,696 |
| | $ | 339,265 |
| | $ | — |
| | $ | 1,389,961 |
|
| Commodity price risk management gain, net | | 145,237 |
| | — |
| | — |
| | 145,237 |
|
| Other income | | 10,744 |
| | 2,717 |
| | — |
| | 13,461 |
|
| Total revenues | | 1,206,677 |
| | 341,982 |
| | — |
| | 1,548,659 |
|
| Costs, expenses and other | | | | | | | | |
| Lease operating expenses | | 92,228 |
| | 38,729 |
| | — |
| | 130,957 |
|
| Production taxes | | 67,819 |
| | 22,538 |
| | — |
| | 90,357 |
|
| Transportation, gathering and processing expenses | | 16,607 |
| | 20,796 |
| | — |
| | 37,403 |
|
| Exploration, geologic and geophysical expense | | 1,234 |
| | 4,970 |
| | — |
| | 6,204 |
|
| Impairment of properties and equipment | | 27 |
| | 458,370 |
| | — |
| | 458,397 |
|
| General and administrative expense | | 152,798 |
| | 17,706 |
| | — |
| | 170,504 |
|
| Depreciation, depletion and amortization | | 389,841 |
| | 169,952 |
| | — |
| | 559,793 |
|
| Accretion of asset retirement obligations | | 4,617 |
| | 458 |
| | — |
| | 5,075 |
|
| (Gain) loss on sale of properties and equipment | | (4,387 | ) | | 4,781 |
| | — |
| | 394 |
|
| Other expenses | | 11,829 |
| | — |
| | — |
| | 11,829 |
|
| Total costs, expenses and other | | 732,613 |
| | 738,300 |
| | — |
| | 1,470,913 |
|
| Income (loss) from operations | | 474,064 |
| | (396,318 | ) | | — |
| | 77,746 |
|
| Interest expense | | (73,251 | ) | | 2,521 |
| | — |
| | (70,730 | ) |
| Interest income | | 413 |
| | — |
| | — |
| | 413 |
|
| Income (loss) before income taxes | | 401,226 |
| | (393,797 | ) | | — |
| | 7,429 |
|
| Income tax (expense) benefit | | (98,611 | ) | | 93,205 |
| | — |
| | (5,406 | ) |
| Equity in loss of subsidiary | | (300,592 | ) | | — |
| | 300,592 |
| | — |
|
| Net income (loss) | | $ | 2,023 |
| | $ | (300,592 | ) | | $ | 300,592 |
| | $ | 2,023 |
|
Net loss for the Guarantor for the year ended 2018 is primarily the result of impairment of certain unproved Delaware Basin leasehold positions.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | | | | | | | | | | |
| | | Consolidating Statements of Operations |
| | | Year Ended December 31, 2017 |
| | | Parent | | Guarantor | | Eliminations | | Consolidated |
| | | (in thousands) |
| | | | | | | | | |
| Revenues | | | | | | | | |
| Crude oil, natural gas and NGLs sales | | $ | 788,400 |
| | $ | 124,684 |
| | $ | — |
| | $ | 913,084 |
|
| Commodity price risk management loss, net | | (3,936 | ) | | — |
| | — |
| | (3,936 | ) |
| Other income | | 11,901 |
| | 567 |
| | — |
| | 12,468 |
|
| Total revenues | | 796,365 |
| | 125,251 |
| | — |
| | 921,616 |
|
| Costs, expenses and other | | | | | | | | |
| Lease operating expenses | | 68,031 |
| | 21,610 |
| | — |
| | 89,641 |
|
| Production taxes | | 53,236 |
| | 7,481 |
| | — |
| | 60,717 |
|
| Transportation, gathering and processing expenses | | 23,301 |
| | 9,919 |
| | — |
| | 33,220 |
|
| Exploration, geologic and geophysical expense | | 1,092 |
| | 46,242 |
| | — |
| | 47,334 |
|
| Impairment of properties and equipment | | 4,951 |
| | 280,936 |
| | — |
| | 285,887 |
|
| Impairment of goodwill | | — |
| | 75,121 |
| | — |
| | 75,121 |
|
| General and administrative expense | | 107,518 |
| | 12,852 |
| | — |
| | 120,370 |
|
| Depreciation, depletion and amortization | | 403,984 |
| | 65,100 |
| | — |
| | 469,084 |
|
| Accretion of asset retirement obligations | | 5,965 |
| | 341 |
| | — |
| | 6,306 |
|
| Gain on sale of properties and equipment | | (766 | ) | | — |
| | — |
| | (766 | ) |
| Provision for uncollectible notes receivable | | (40,203 | ) | | — |
| | — |
| | (40,203 | ) |
| Other expenses | | 13,157 |
| | — |
| | — |
| | 13,157 |
|
| Total costs, expenses and other | | 640,266 |
| | 519,602 |
| | — |
| | 1,159,868 |
|
| Income (loss) from operations | | 156,099 |
| | (394,351 | ) | | — |
| | (238,252 | ) |
| Loss on extinguishment of debt | | (24,747 | ) | | — |
| | — |
| | (24,747 | ) |
| Interest expense | | (79,919 | ) | | 1,225 |
| | — |
| | (78,694 | ) |
| Interest income | | 2,261 |
| | — |
| | — |
| | 2,261 |
|
| Income (loss) before income taxes | | 53,694 |
| | (393,126 | ) | | — |
| | (339,432 | ) |
| Income tax (expense) benefit | | (33,643 | ) | | 245,571 |
| | — |
| | 211,928 |
|
| Equity in loss of subsidiary | | (147,555 | ) | | — |
| | 147,555 |
| | — |
|
| Net loss | | $ | (127,504 | ) | | $ | (147,555 | ) | | $ | 147,555 |
| | $ | (127,504 | ) |
Net loss for the Guarantor for the year ended 2017 is primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions and the impairment of goodwill.
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | | | | | | | | | | |
| | | Consolidating Statements of Operations |
| | | Year Ended December 31, 2016 |
| | | Parent | | Guarantor | | Eliminations | | Consolidated |
| | | (in thousands) |
| | | | | | | | | |
| Revenues | | | | | | | | |
| Crude oil, natural gas, and NGLs sales | | $ | 491,750 |
| | $ | 5,603 |
| | $ | — |
| | $ | 497,353 |
|
| Commodity price risk management loss, net | | (125,681 | ) | | — |
| | — |
| | (125,681 | ) |
| Other income | | 11,241 |
| | 2 |
| | — |
| | 11,243 |
|
| Total revenues | | 377,310 |
| | 5,605 |
| | — |
| | 382,915 |
|
| Costs, expenses and other | | | | | | | | |
| Lease operating expenses | | 58,401 |
| | 1,549 |
| | — |
| | 59,950 |
|
| Production taxes | | 31,132 |
| | 278 |
| | — |
| | 31,410 |
|
| Transportation, gathering and processing expenses | | 18,263 |
| | 152 |
| | — |
| | 18,415 |
|
| Exploration, geologic and geophysical expense | | 1,197 |
| | 3,472 |
| | — |
| | 4,669 |
|
| Impairment of properties and equipment | | 9,973 |
| | — |
| | — |
| | 9,973 |
|
| General and administrative expense | | 112,166 |
| | 304 |
| | — |
| | 112,470 |
|
| Depreciation, depletion and amortization | | 415,321 |
| | 1,553 |
| | — |
| | 416,874 |
|
| Accretion of asset retirement obligations | | 7,070 |
| | 10 |
| | — |
| | 7,080 |
|
| Gain on sale of properties and equipment | | (43 | ) | | — |
| | — |
| | (43 | ) |
| Provision for uncollectible notes receivable | | 44,038 |
| | — |
| | — |
| | 44,038 |
|
| Other expenses | | 10,193 |
| | — |
| | — |
| | 10,193 |
|
| Total costs, expenses and other | | 707,711 |
| | 7,318 |
| | — |
| | 715,029 |
|
| Loss from operations | | (330,401 | ) | | (1,713 | ) | | — |
| | (332,114 | ) |
| Interest expense | | (62,002 | ) | | 30 |
| | — |
| | (61,972 | ) |
| Interest income | | 963 |
| | — |
| | — |
| | 963 |
|
| Loss before income taxes | | (391,440 | ) | | (1,683 | ) | | — |
| | (393,123 | ) |
| Income tax benefit | | 147,195 |
| | — |
| | — |
| | 147,195 |
|
| Equity in loss of subsidiary | | (1,683 | ) | | — |
| | 1,683 |
| | — |
|
| Net loss | | $ | (245,928 | ) | | $ | (1,683 | ) | | $ | 1,683 |
| | $ | (245,928 | ) |
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | | | | | | | | | | |
| | | Consolidating Statements of Cash Flows |
| | | Year Ended December 31, 2018 |
| | | Parent | | Guarantor | | Eliminations | | Consolidated |
| | | (in thousands) |
| | | | | | | | | |
| Cash flows from operating activities | | $ | 625,206 |
| | $ | 264,096 |
| | $ | — |
| | $ | 889,302 |
|
| Cash flows from investing activities: | | | | | | | | |
| Capital expenditures for development of crude oil and natural gas properties | | (482,534 | ) | | (463,816 | ) | | — |
| | (946,350 | ) |
| Capital expenditures for other properties and equipment | | (9,806 | ) | | (1,249 | ) | | — |
| | (11,055 | ) |
| Acquisition of crude oil and natural gas properties | | (179,955 | ) | | (71 | ) | | — |
| | (180,026 | ) |
| Proceeds from sale of properties and equipment | | 1,929 |
| | 1,633 |
| | — |
| | 3,562 |
|
| Proceeds from divestiture | | 44,693 |
| | — |
| | — |
| | 44,693 |
|
| Restricted cash | | 1,249 |
| | — |
| | — |
| | 1,249 |
|
| Intercompany transfers | | (199,584 | ) | | — |
| | 199,584 |
| | — |
|
| Net cash from investing activities | | (824,008 | ) | | (463,503 | ) | | 199,584 |
| | (1,087,927 | ) |
| Cash flows from financing activities: | | | | | | | | |
| Proceeds from revolving credit facility | | 1,072,500 |
| | — |
| | — |
| | 1,072,500 |
|
| Repayment of revolving credit facility | | (1,040,000 | ) | | — |
| | — |
| | (1,040,000 | ) |
| Payment of debt issuance costs | | (7,704 | ) | | — |
| | — |
| | (7,704 | ) |
| Purchase of treasury stock | | (5,147 | ) | | — |
| | — |
| | (5,147 | ) |
| Other | | (1,373 | ) | | (177 | ) | | — |
| | (1,550 | ) |
| Intercompany transfers | | — |
| | 199,584 |
| | (199,584 | ) | | — |
|
| Net cash from financing activities | | 18,276 |
| | 199,407 |
| | (199,584 | ) | | 18,099 |
|
| Net change in cash and cash equivalents | | (180,526 | ) | | — |
| | — |
| | (180,526 | ) |
| Cash and cash equivalents, beginning of period | | 189,925 |
| | — |
| | — |
| | 189,925 |
|
| Cash and cash equivalents, end of period | | $ | 9,399 |
| | $ | — |
| | $ | — |
| | $ | 9,399 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | | | | | | | | | | |
| | | Consolidating Statements of Cash Flows |
| | | Year Ended December 31, 2017 |
| | | Parent | | Guarantor | | Eliminations | | Consolidated |
| | | (in thousands) |
| | | | | | | | | |
| Cash flows from operating activities | | $ | 546,954 |
| | $ | 50,859 |
| | $ | — |
| | $ | 597,813 |
|
| Cash flows from investing activities: | | | | | | | | |
| Capital expenditures for development of crude oil and natural gas properties | | (439,897 | ) | | (297,311 | ) | | — |
| | (737,208 | ) |
| Capital expenditures for other properties and equipment | | (3,539 | ) | | (1,555 | ) | | — |
| | (5,094 | ) |
| Acquisition of crude oil and natural gas properties | | (21,000 | ) | | 5,372 |
| | — |
| | (15,628 | ) |
| Proceeds from sale of properties and equipment | | 10,084 |
| | (93 | ) | | — |
| | 9,991 |
|
| Sale of promissory note | | 40,203 |
| | — |
| | — |
| | 40,203 |
|
| Restricted cash | | (9,250 | ) | | — |
| | — |
| | (9,250 | ) |
| Sales of short-term investments | | 49,890 |
| | — |
| | — |
| | 49,890 |
|
| Purchases of short-term investments | | (49,890 | ) | | — |
| | — |
| | (49,890 | ) |
| Intercompany transfers | | (239,191 | ) | | — |
| | 239,191 |
| | — |
|
| Net cash from investing activities | | (662,590 | ) | | (293,587 | ) | | 239,191 |
| | (716,986 | ) |
| Cash flows from financing activities: | | | | | | | | |
| Proceeds from issuance of senior notes | | 592,366 |
| | — |
| | — |
| | 592,366 |
|
| Redemption of senior notes | | (519,375 | ) | | — |
| | — |
| | (519,375 | ) |
| Payment of debt issuance costs | | (50 | ) | | — |
| | — |
| | (50 | ) |
| Purchase of treasury stock | | (6,672 | ) | | — |
| | — |
| | (6,672 | ) |
| Other | | (1,195 | ) | | (76 | ) | | — |
| | (1,271 | ) |
| Intercompany transfers | | — |
| | 239,191 |
| | (239,191 | ) | | — |
|
| Net cash from financing activities | | 65,074 |
| | 239,115 |
| | (239,191 | ) | | 64,998 |
|
| Net change in cash and cash equivalents | | (50,562 | ) | | (3,613 | ) | | — |
| | (54,175 | ) |
| Cash and cash equivalents, beginning of period | | 240,487 |
| | 3,613 |
| | — |
| | 244,100 |
|
| Cash and cash equivalents, end of period | | $ | 189,925 |
| | $ | — |
| | $ | — |
| | $ | 189,925 |
|
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
|
| | | | | | | | | | | | | | | | |
| | | Condensed Consolidating Statements of Cash Flows |
| | | Year Ended December 31, 2016 |
| | | Parent | | Guarantor | | Eliminations | | Consolidated |
| | | (in thousands) |
| | | | | | | | | |
| Cash flows from operating activities | | $ | 492,893 |
| | $ | (6,630 | ) | | $ | — |
| | $ | 486,263 |
|
| Cash flows from investing activities: | | | | | | | | |
| Capital expenditures for development of crude oil and natural gas properties | | (436,361 | ) | | (523 | ) | | — |
| | (436,884 | ) |
| Capital expenditures for other properties and equipment | | (2,282 | ) | | (1,182 | ) | | — |
| | (3,464 | ) |
| Acquisition of crude oil and natural gas properties | | (1,076,256 | ) | | 2,533 |
| | — |
| | (1,073,723 | ) |
| Proceeds from sale of properties and equipment | | 4,945 |
| | — |
| | — |
| | 4,945 |
|
| Intercompany transfers | | (9,415 | ) | | — |
| | 9,415 |
| | — |
|
| Net cash from investing activities | | (1,519,369 | ) | | 828 |
| | 9,415 |
| | (1,509,126 | ) |
| Cash flows from financing activities: | | | | | | | | |
| Proceeds from revolving credit facility | | 85,000 |
| | — |
| | — |
| | 85,000 |
|
| Repayment of revolving credit facility | | (122,000 | ) | | — |
| | — |
| | (122,000 | ) |
| Proceeds from issuance of equity, net of issuance costs | | 855,074 |
| | — |
| | — |
| | 855,074 |
|
| Proceeds from issuance of senior notes | | 392,172 |
| | — |
| | — |
| | 392,172 |
|
| Proceeds from issuance of convertible senior notes | | 193,935 |
| | — |
| | — |
| | 193,935 |
|
| Redemption of convertible notes | | (115,000 | ) | | — |
| | — |
| | (115,000 | ) |
| Payment of debt issuance costs | | (15,556 | ) | | — |
| | — |
| | (15,556 | ) |
| Purchase of treasury shares | | (6,935 | ) | | — |
| | — |
| | (6,935 | ) |
| Other | | (577 | ) | | — |
| | — |
| | (577 | ) |
| Intercompany transfers | | — |
| | 9,415 |
| | (9,415 | ) | | — |
|
| Net cash from financing activities | | 1,266,113 |
| | 9,415 |
| | (9,415 | ) | | 1,266,113 |
|
| Net change in cash and cash equivalents | | 239,637 |
| | 3,613 |
| | — |
| | 243,250 |
|
| Cash and cash equivalents, beginning of period | | 850 |
| | — |
| | — |
| | 850 |
|
| Cash and cash equivalents, end of period | | $ | 240,487 |
| | $ | 3,613 |
| | $ | — |
| | $ | 244,100 |
|
The condensed consolidating financial statements for the year ended December 31, 2016 represent one month of activity for the Guarantor as the Delaware Basin acquisition closed in December 2016.
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
SUPPLEMENTAL INFORMATION - UNAUDITED
CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED
Net Proved Reserves
All of our crude oil, natural gas and NGLs reserves are located in the U.S.United States. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas and NGLs reserves. As of December 31, 2018, 20172021, 2020 and 20162019 (as applicable), all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott Company, L.P., and beginning in 2016 Netherland, Sewell & Associates, Inc. prepared the reserve reportsall of our estimates for proved reserves for the Delaware Basin.Basin were based on reserve reports prepared by NSAI. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribedguidelines established by the SEC.
Proved reserves are those quantities of crude oil, natural gasSEC and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development.FASB. All of our proved undeveloped reserves conform to the SEC five-year rule requirement that they be scheduled to be drilled within five years of each location’s initial booking date.
Reserve estimates are based on an unweighted arithmetic average of commodity prices during the preceding 12-month period, using the closing prices on the first day of each month, as required by the SEC. The indicatedtable below presents the index prices for our estimated reserves, by commodity, as of the dates indicated:
| | | | | | | | | | | | | | | | | | | | |
| | Average Benchmark Prices |
| December 31, | | Crude Oil (per Bbl) (1) | | Natural Gas (per MMBtu) (1) | | NGLs (per Bbl) (2) |
| 2021 | | $ | 66.56 | | | $ | 3.60 | | | $ | 66.56 | |
| 2020 | | 39.57 | | | 1.99 | | | 39.57 | |
| 2019 | | 55.69 | | | 2.58 | | | 55.69 | |
____________
(1)Our benchmark indexes for crude oil and natural gas are presented below.WTI and Henry Hub, respectively.
(2)For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. |
| | | | | | | | | | | | |
| | | Average Benchmark Prices (1) |
| As of December 31, | | Crude Oil (per Bbl) (2) | | Natural Gas (per Mcf) (2) | | NGLs (per Bbl) (3) |
| | | | | | | |
| 2018 | | $ | 65.56 |
| | $ | 3.10 |
| | $ | 65.56 |
|
| 2017 | | 51.34 |
| | 2.98 |
| | 51.34 |
|
| 2016 | | 42.75 |
| | 2.48 |
| | 42.75 |
|
The netted back price used to estimate our reserves, by commodity, are presented below.below:
|
| | | | | | | | | | | | |
| | | Price Used to Estimate Reserves (4) |
| As of December 31, | | Crude Oil (per Bbl) | | Natural Gas (per Mcf) | | NGLs (per Bbl) |
| | | | | | | |
| 2018 | | $ | 61.14 |
| | $ | 2.15 |
| | $ | 23.04 |
|
| 2017 | | 48.68 |
| | 2.31 |
| | 20.21 |
|
| 2016 | | 38.67 |
| | 1.85 |
| | 11.97 |
|
| | | | | | | | | | | | | | | | | | | | |
| | Price Used to Estimate Reserves (1) |
| December 31, | | Crude Oil
(per Bbl) | | Natural Gas
(per MMBtu) | | NGLs (per Bbl) |
| 2021 | | $ | 65.37 | | | $ | 2.85 | | | $ | 24.96 | |
| 2020 | | 37.52 | | | 1.26 | | | 10.55 | |
| 2019 | | 52.63 | | | 1.50 | | | 12.21 | |
_______________________
| |
(1) | Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. |
(2) Our benchmark(1)These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for crude oil and natural gasthe respective commodity, including consideration for contracts that are WTI and Henry Hub, respectively.
| |
(3) | For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. |
| |
(4) | These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. |
effective as of December 31, 2021.
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
The following tables present the changes in our estimated quantities of proved reserves:
| | | | | | | | | | | | | | Crude Oil, Condensate (MBbls) | | Natural Gas
(MMcf) | | NGLs
(MBbls) | | Total
(MBoe) |
| | Crude Oil, Condensate (MBbls) | | Natural Gas (MMcf) | | NGLs (MBbls) | | Total (MBoe) | |
| Proved Reserves: | | | | | | | | |
| Proved reserves, January 1, 2016 | 98,975 |
| | 660,737 |
| | 63,727 |
| | 272,825 |
| |
| Proved reserves, January 1, 2019 | | Proved reserves, January 1, 2019 | 190,349 | | | 1,335,689 | | | 131,987 | | | 544,953 | |
| Revisions of previous estimates | (22,097 | ) | | (80,426 | ) | | (7,130 | ) | | (42,631 | ) | Revisions of previous estimates | 25,875 | | | 328,290 | | | 31,559 | | | 112,147 | |
| Extensions, discoveries and other additions | 494 |
| | 4,094 |
| | 355 |
| | 1,531 |
| Extensions, discoveries and other additions | 1,056 | | | 10,262 | | | 1,519 | | | 4,285 | |
| Acquisition of reserves | 50,126 |
| | 305,224 |
| | 32,586 |
| | 133,583 |
| Acquisition of reserves | 553 | | | 4,558 | | | 448 | | | 1,761 | |
| Dispositions | (601 | ) | | (4,202 | ) | | (424 | ) | | (1,725 | ) | Dispositions | (1,412) | | | (5,052) | | | (614) | | | (2,868) | |
| Production | (8,728 | ) | | (51,730 | ) | | (4,826 | ) | | (22,176 | ) | Production | (19,166) | | | (115,950) | | | (10,923) | | | (49,414) | |
| Proved reserves, December 31, 2016 | 118,169 |
| | 833,697 |
| | 84,288 |
| | 341,407 |
| |
| Proved reserves, December 31, 2019 | | Proved reserves, December 31, 2019 | 197,255 | | | 1,557,797 | | | 153,976 | | | 610,864 | |
| Revisions of previous estimates | 28,334 |
| | 96,119 |
| | 8,104 |
| | 52,457 |
| Revisions of previous estimates | (41,089) | | | (272,243) | | | (14,774) | | | (101,237) | |
| Extensions, discoveries and other additions | 2,923 |
| | 11,541 |
| | 1,158 |
| | 6,005 |
| Extensions, discoveries and other additions | 812 | | | 2,991 | | | 324 | | | 1,635 | |
| Acquisition of reserves | 18,971 |
| | 289,223 |
| | 19,604 |
| | 86,778 |
| Acquisition of reserves | 80,590 | | | 795,977 | | | 81,770 | | | 295,023 | |
| Dispositions | (653 | ) | | (4,597 | ) | | (481 | ) | | (1,900 | ) | Dispositions | (2,116) | | | (17,711) | | | (1,776) | | | (6,844) | |
| Production | (12,902 | ) | | (71,689 | ) | | (6,981 | ) | | (31,830 | ) | Production | (23,720) | | | (165,637) | | | (17,042) | | | (68,368) | |
| Proved reserves, December 31, 2017 | 154,842 |
| | 1,154,294 |
| | 105,692 |
| | 452,917 |
| |
| Proved reserves, December 31, 2020 | | Proved reserves, December 31, 2020 | 211,732 | | | 1,901,174 | | | 202,478 | | | 731,073 | |
| Revisions of previous estimates | 26,548 |
| | 94,738 |
| | 12,674 |
| | 55,011 |
| Revisions of previous estimates | 22,651 | | | 408,540 | | | 54,634 | | | 145,375 | |
| Extensions, discoveries and other additions | 8,786 |
| | 61,750 |
| | 8,868 |
| | 27,946 |
| Extensions, discoveries and other additions | 528 | | | 1,584 | | | 168 | | | 960 | |
| Acquisition of reserves | 19,644 |
| | 148,674 |
| | 15,936 |
| | 60,360 |
| Acquisition of reserves | 1,616 | | | 24,174 | | | 2,469 | | | 8,113 | |
| Dispositions | (2,507 | ) | | (35,750 | ) | | (2,656 | ) | | (11,121 | ) | Dispositions | — | | | — | | | — | | | — | |
| Production | (16,964 | ) | | (88,017 | ) | | (8,527 | ) | | (40,160 | ) | Production | (22,682) | | | (175,747) | | | (19,360) | | | (71,333) | |
| Proved reserves, December 31, 2018 | 190,349 |
| | 1,335,689 |
| | 131,987 |
| | 544,953 |
| |
| Proved reserves, December 31, 2021 | | Proved reserves, December 31, 2021 | 213,845 | | | 2,159,725 | | | 240,389 | | | 814,188 | |
| | | | | | | | | | | | | | | | |
| Proved developed reserves, as of: | | Proved developed reserves, as of: | |
| December 31, 2019 | | December 31, 2019 | 66,211 | | | 554,234 | | | 55,411 | | | 213,994 | |
| December 31, 2020 | | December 31, 2020 | 86,330 | | | 860,877 | | | 91,702 | | | 321,512 | |
| December 31, 2021 | | December 31, 2021 | 97,420 | | | 1,088,700 | | | 120,132 | | | 399,002 | |
| Proved undeveloped reserves, as of: | | Proved undeveloped reserves, as of: | |
| December 31, 2019 | | December 31, 2019 | 131,044 | | | 1,003,563 | | | 98,565 | | | 396,870 | |
| December 31, 2020 | | December 31, 2020 | 125,402 | | | 1,040,297 | | | 110,776 | | | 409,561 | |
| December 31, 2021 | | December 31, 2021 | 116,425 | | | 1,071,025 | | | 120,257 | | | 415,186 | |
|
| | | | | | | | | | | |
| Proved Developed Reserves, as of: | | | | | | | |
| December 31, 2016 | 30,013 |
| | 264,452 |
| | 24,196 |
| | 98,284 |
|
| December 31, 2017 | 46,862 |
| | 365,332 |
| | 35,220 |
| | 142,971 |
|
| December 31, 2018 | 61,821 |
| | 443,151 |
| | 43,856 |
| | 179,535 |
|
| Proved Undeveloped Reserves, as of: | | | | |
| | |
| December 31, 2016 | 88,156 |
| | 569,245 |
| | 60,092 |
| | 243,122 |
|
| December 31, 2017 | 107,980 |
| | 788,962 |
| | 70,472 |
| | 309,946 |
|
| December 31, 2018 | 128,528 |
| | 892,538 |
| | 88,131 |
| | 365,418 |
|
| | | | | | | | |
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
| | | | | | | | | | | | | | | | | |
| Developed | | Undeveloped | | Total |
| (MBoe) |
| Proved reserves, January 1, 2019 | 179,535 | | | 365,418 | | | 544,953 | |
| Revisions of previous estimates | 27,452 | | | 84,695 | | | 112,147 | |
| Extensions, discoveries and other additions | 4,285 | | | — | | | 4,285 | |
| Acquisition of reserves | 441 | | | 1,320 | | | 1,761 | |
| Dispositions | (474) | | | (2,394) | | | (2,868) | |
| Production | (49,414) | | | — | | | (49,414) | |
| Undeveloped reserves converted to developed | 52,169 | | | (52,169) | | | — | |
| Proved reserves, December 31, 2019 | 213,994 | | | 396,870 | | | 610,864 | |
| Revisions of previous estimates | (8,634) | | | (92,603) | | | (101,237) | |
| Extensions, discoveries and other additions | 1,635 | | | — | | | 1,635 | |
| Acquisition of reserves | 125,180 | | | 169,843 | | | 295,023 | |
| Dispositions | (2,487) | | | (4,357) | | | (6,844) | |
| Production | (68,368) | | | — | | | (68,368) | |
| Undeveloped reserves converted to developed | 60,192 | | | (60,192) | | | — | |
| Proved reserves, December 31, 2020 | 321,512 | | | 409,561 | | | 731,073 | |
| Revisions of previous estimates | 75,005 | | | 70,370 | | | 145,375 | |
| Extensions, discoveries and other additions | 960 | | | — | | | 960 | |
| Acquisition of reserves | 519 | | | 7,594 | | | 8,113 | |
| Dispositions | — | | | — | | | — | |
| Production | (71,333) | | | — | | | (71,333) | |
| Undeveloped reserves converted to developed | 72,339 | | | (72,339) | | | — | |
| Proved reserves, December 31, 2021 | 399,002 | | | 415,186 | | | 814,188 | |
|
| | | | | | | | |
| | Developed | | Undeveloped | | Total |
| | (MBoe) |
| | | | | | |
| Proved reserves, January 1, 2016 | 70,496 |
| | 202,329 |
| | 272,825 |
|
| Revisions of previous estimates | 6,112 |
| | (48,743 | ) | | (42,631 | ) |
| Extensions, discoveries and other additions | 1,531 |
| | — |
| | 1,531 |
|
| Acquisition of reserves | 10,229 |
| | 123,354 |
| | 133,583 |
|
| Dispositions | (99 | ) | | (1,626 | ) | | (1,725 | ) |
| Production | (22,176 | ) | | — |
| | (22,176 | ) |
| Undeveloped reserves converted to developed | 32,192 |
| | (32,192 | ) | | — |
|
| Proved reserves, December 31, 2016 | 98,285 |
| | 243,122 |
| | 341,407 |
|
| Revisions of previous estimates | 18,291 |
| | 34,166 |
| | 52,457 |
|
| Extensions, discoveries and other additions | 2,292 |
| | 3,713 |
| | 6,005 |
|
| Acquisition of reserves | 1,305 |
| | 85,473 |
| | 86,778 |
|
| Dispositions | (20 | ) | | (1,880 | ) | | (1,900 | ) |
| Production | (31,830 | ) | | — |
| | (31,830 | ) |
| Undeveloped reserves converted to developed | 54,648 |
| | (54,648 | ) | | — |
|
| Proved reserves, December 31, 2017 | 142,971 |
| | 309,946 |
| | 452,917 |
|
| Revisions of previous estimates | 6,284 |
| | 48,727 |
| | 55,011 |
|
| Extensions, discoveries and other additions | 7,874 |
| | 20,072 |
| | 27,946 |
|
| Acquisition of reserves | 8,758 |
| | 51,602 |
| | 60,360 |
|
| Dispositions | (4,486 | ) | | (6,635 | ) | | (11,121 | ) |
| Production | (40,160 | ) | | — |
| | (40,160 | ) |
| Undeveloped reserves converted to developed | 58,294 |
| | (58,294 | ) | | — |
|
| Proved reserves, December 31, 2018 | 179,535 |
| | 365,418 |
| | 544,953 |
|
20182021 Activity. During 2018,2021, we increased proved reserves by 92.083.1 MMBoe, or 11 percent, relative to December 31, 2020. The increase in proved reserves was primarily due to positive revisions resulting from our development activities and significant improvements in commodity prices during 2021, resulting in better economics. In 2021, we produced 71.3 MMBoe.
Revisions of Previous Estimates- Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 75.0 MMBoe primarily due to (i) an increase of 44.3 MMBoe as a result of extended well lives directly correlated with the higher average prices for crude oil, natural gas and NGLs in 2021, (ii) a 24.9 MMBoe increase related to our operated and non-operated current year drilling activities not included within our five year development plan in the prior year, and (iii) an increase of 8.9 MMBoe related to performance revisions and other factors. The positive revisions were partially offset by a 3.1 MMBoe decrease associated with higher operating costs.
Revisions of Previous Estimates- PUDs. Net upward revisions to our previous PUD reserves estimates of 70.4 MMBoe were due to (i) a 166.5 MMBoe increase related to additional locations on proved acreage resulting from our 2021 development activities and changes to our drilling schedule resulting from state regulatory permitting process changes passed in 2021, (ii) a 8.6 MMBoe increase related to extended well lives directly correlated with the upward pricing adjustments due to improved average prices for crude oil, natural gas and NGLs in 2021, and (iii) 3.5 MMBoe related to performance revisions and other items. The positive revisions were partially offset by a 96.4 MMBoe downward revision primarily related to PUD locations that were reclassified to unproven reserves in our Wattenberg Field due to changes to our drilling schedule mainly resulting from state regulatory permitting process changes passed in 2021. Finally, a reduction of 11.8 MMBoe was recognized for locations no longer expected to be developed within five years of their initial recording in accordance with SEC rules.
Extensions, Discoveries and Other Additions- Proved Developed Reserves. Developed activity for 2021 included the addition of 1.0 MMBoe of developed reserves related to two gross newly turned-in-line wells in the Delaware Basin.
Acquisitions of Reserves- Proved Developed Reserves and PUDs. Proved developed and PUD reserves acquired primarily pertains to certain nonmonetary exchanges during 2021.
At December 31, 2020, we projected a PUD reserve conversion rate of 22 percent for 2021. During 2021, our actual conversion rate was 18 percent primarily due to a change in timing of completion activities in the Wattenberg Field. We converted 72.3 MMBoe of PUD reserves at December 31, 2020 to proved developed reserves as of December 31, 2021.
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
Based on economic conditions on December 31, 2021, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. The level of capital spending necessary to execute our development plan is consistent with our recent performance and updated drilling program.
2020 Activity.During 2020, we increased proved reserves by 120.2 MMBoe, or 20 percent, relative to December 31, 2017.2019. The increase in proved reserves was primarily a result of our of the SRC Acquisition, partially offset by downward revisions of previous estimates. In 2020, we produced 68.4 MMBoe.
Revisions of Previous Estimates- Proved Developed Reserves. Proved developed reserves experienced a negative revision of 8.6 MMBoe primarily due to a decrease of 28.2 MMBoe as a result of lower average prices for crude oil, natural gas and NGLs for 2020. The negative revisions were partially offset by a 14.3 MMBoe increase associated with lower operating costs and a 5.3 MMBoe increase related to performance revisions and other items.
Revisions of Previous Estimates- PUDs. Net downward revisions to our previous PUD reserves estimates of 92.6 MMBoe were due to (i) 266.7 MMBoe related to PUD locations that were reclassified to unproven reserves due to drilling schedule changes, (ii) a reduction of 25.5 MMBoe was recognized for locations no longer expected to be developed within five years of their initial recording in accordance with SEC rules, and (iii) 11.3 MMBoe related to downward pricing adjustments due to lower average prices for crude oil, natural gas and NGLs for 2020. Drilling schedule changes resulted from PUD downgrades associated with lower realized prices and revised drilling plans following the completion of the SRC Acquisition. The negative revisions were partially offset by a 199.9 MMBoe increase related to additional locations on proved acreage resulting from our drilling plan and 11.0 MMBoe related to performance revisions and other items.
Extensions, Discoveries and Other Additions- Proved Developed Reserves. Developed activity for 2020 included the addition of 1.6 MMBoe of developed reserves related to two gross newly-drilled wells in the Delaware Basin.
Extensions, Discoveries and Other Additions- PUDs. There were no extensions, discoveries or other additions for PUD reserves during 2020.
Acquisitions of Reserves- Proved Developed Reserves. Proved developed reserves acquired primarily pertain to the SRC Acquisition completed in January 2020.
Acquisitions of Reserves- PUDs. Proved undeveloped reserves acquired primarily pertain to the SRC Acquisition completed in January 2020.
Dispositions- Proved Developed Reserves. Dispositions of 2.5 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges.
Dispositions- PUDs. Dispositions of 4.4 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges.
2019Activity. During 2019, we increased proved reserves by 65.9 MMBoe, or 12 percent, relative to December 31, 2018. The increase in proved reserves was primarily a result of acreage exchange transactions and acquisitions in the Wattenberg Field and reserve additions on proved acreage resulting from our 20182019 development activities. In 2018,2019, we produced 40.2 MMboe.49.4 MMBoe.
Revisions of Previous Estimates-ProvedEstimates- Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 11.428.3 MMBoe duereflecting improved performance revisions, decreased operating costs and other items. An additional increase of 10.2 MMBoe in developed reserves related to an increaseour current year drilling activities. These positive revisions were partially offset by a decrease of 11.0 MMBoe for decreases in prices for crude oil, natural gas and NGLs, offset by net negative revisions of 5.1 MMBoe for an increase in operating costs, performance revisions and other items.NGLs.
Revisions of Previous Estimates-PUDs. Estimates- PUDs. Upward revisions to our PUD reserves were related to an increaseof 71.774.2 MMBoe reflecting newly-bookedadditional locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 26.8 MMBoe in the Wattenberg Field due to drilling schedule changesplan, as well as improved performance revisions and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2018 acreage exchanges, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and type curve revisions,items, which resulted in further upward revisions of 3.828.9 MMBoe of PUD reserves. Partially offsetting these increases were negative revisions of 12.9 MMBoe due to drilling schedule changes and 5.5 MMBoe for decreases in prices for crude oil, natural gas and NGLs.
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
Extensions, Discoveries and Other Additions-ProvedAdditions- Proved Developed Reserves. Developed activityadditions for 20182019 included the addition 7.9of 4.3 MMBoe of developed reserves related to 17three gross (9.2(three net) newly-drilled wells.
Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 20.1 MMBoe ofAdditions- PUDs. There were no extensions, discoveries or other additions for PUD reserves related to 16 gross (15.0 net) PUD locations in the Delaware Basin.during 2019.
Acquisitions of Reserves-ProvedReserves- Proved Developed Reserves.Proved developed reserves acquired in various acreage swapsexchanges and an acquisitionacquisitions were 8.80.4 MMBoe during 2018.2019.
Acquisitions of Reserves-PUDs. Reserves- PUDs. We acquired 47.6 MMBoe and 4.01.3 MMBoe of PUD reserves in 20182019 in acreage swapsexchanges and an acquisition, respectively.acquisitions.
Dispositions-Proved
Dispositions- Proved Developed Reserves. Dispositions of 4.50.5 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps.exchanges.
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
Dispositions-PUDs. Dispositions- PUDs. Dispositions of 6.6PUDs were 2.4 MMBoe reflect that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2017 in the acreage swap transactions.
At December 31, 2017, we projected a PUD reserve conversion rate of 16 percent for 2018. During 2018, a larger number of wells were turned-in-line than we anticipated, resulting in an actual conversion rate of 19 percent. We converted 58.3 MMBoe of PUD reserves at December 31, 2017 to proved developed reserves as of December 31, 2018.
Based on economic conditions on December 31, 2018, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2018, our 2019 PUD reserve conversion rate is expected to be approximately 16 percent. The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities.
2017 Activity. During 2017, we increased proved reserves by 111.5 MMBoe, or 33 percent, relative to December 31, 2016. The increase in proved reserves was primarily a result of an increase in acquisitions and reserve additions on proved acreage in the Delaware Basin from our 2017 development plan. In 2017, we produced 31.8 MMboe.
Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 17.7 MMBoe due to an increase in prices for crude oil, natural gas and NGLs and net positive revisions of 0.6 MMBoe reflecting changes in operating costs, performance revisions and other items.
Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 89.8 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 58.5 MMBoe in the Wattenberg Field due to drilling schedule changesdivestiture and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2017 acreage swaps, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and other, which resulted in further upward revisions of 2.9 MMBoe of PUD reserves.
Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2017 included the addition of 2.3 MMBoe of developed reserves related to newly-drilled wells.
Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 3.7 MMBoe of PUD reserves related to PUD locations in the Delaware Basin.
Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps were 1.3 MMBoe during 2017.
Acquisitions of Reserves-PUDs. We acquired 85.5 MMBoe of PUD reserves in 2017 in acreage swaps.
Dispositions-Proved Developed Reserves. Dispositions were related to acreage surrendered in various acreage swaps.exchanges.
Dispositions-PUDs. Dispositions of PUDs were 1.9 MMBoe, reflecting the fact that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2016 in the acreage swap transactions.
2016 Activity. During 2016, we increased proved reserves by 68.6 MMBoe, or 25 percent, relative to December 31, 2015. This proved reserve increase was primarily a result of the development of longer lateral length well bores in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position to drill longer length laterals with increased working interests. We also acquired proved developed reserves and undeveloped reserves in the Delaware Basin.
Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 2.6 MMBoe due to a decrease in operating costs and a net positive revision of 3.5 MMBoe for performance revisions and other items. These net positive revisions were partially offset by a decrease in prices for crude oil, natural gas and NGLs.
Revisions of Previous Estimates-PUDs. Downward revisions to our PUD reserves were related to a decrease of 61.0 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
exceeding the five-year rule. Drilling schedule changes, primarily related to 2016 acreage swaps, resulted in these locations being reclassified from proved to unproved status. Partially offsetting this decrease was a positive revision of 10.8 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. All other changes were due to commodity pricing, lease operating expenses and other, which resulted in further downward revisions of 1.5 MMBoe of PUD reserves.
Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2016 included the addition 1.5 MMBoe of developed reserves related to newly-drilled wells.
Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and an acquisition were 10.2 MMBoe during 2016.
Acquisitions of Reserves-PUDs. We acquired 98.1 MMBoe and 25.3 MMBoe of PUD reserves in 2016 in acreage swaps and an acquisition, respectively.
Dispositions-Proved Developed Reserves. Dispositions of 0.1 MMBoe were related to acreage surrendered in various acreage swaps.
Dispositions-PUDs. Dispositions of PUDs were 1.6 MMBoe, reflecting the fact that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2015 in the acreage swap transactions.
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
Results of Operations for Crude Oil and Natural Gas Producing Activities
The results of operations for crude oil and natural gas producing activities arefor the periods presented below.below:
| | | | | | | | | | | | | | Year Ended December 31, |
| Year Ended December 31, | | 2021 | | 2020 | | 2019 |
| 2018 | | 2017 | | 2016 | | (in thousands) |
| (in thousands) | |
| Revenue: |
| |
| |
| |
| Revenues: | | Revenues: | |
| Crude oil, natural gas and NGLs sales | $ | 1,389,961 |
| | $ | 913,084 |
| | $ | 497,353 |
| Crude oil, natural gas and NGLs sales | $ | 2,552,558 | | | $ | 1,152,555 | | | $ | 1,307,275 | |
| Commodity price risk management gain (loss), net | 145,237 |
| | (3,936 | ) | | (125,681 | ) | Commodity price risk management gain (loss), net | (701,456) | | | 180,270 | | | (162,844) | |
| 1,535,198 |
| | 909,148 |
| | 371,672 |
| | 1,851,102 | | | 1,332,825 | | | 1,144,431 | |
| Expenses: | | | | | | Expenses: | |
| Lease operating expenses | 130,957 |
| | 89,641 |
| | 59,950 |
| Lease operating expenses | 180,659 | | | 161,346 | | | 142,248 | |
| Production taxes | 90,357 |
| | 60,717 |
| | 31,410 |
| Production taxes | 165,209 | | | 59,368 | | | 80,754 | |
| Transportation, gathering and processing expenses | 37,403 |
| | 33,220 |
| | 18,415 |
| Transportation, gathering and processing expenses | 100,403 | | | 77,835 | | | 46,353 | |
| Exploration expense | 6,204 |
| | 47,334 |
| | 4,669 |
| Exploration expense | 1,064 | | | 1,376 | | | 4,054 | |
| Impairment of properties and equipment | 458,397 |
| | 285,887 |
| | 9,973 |
| |
| Depreciation, depletion and amortization | 551,265 |
| | 462,482 |
| | 413,105 |
| Depreciation, depletion and amortization | 627,466 | | | 611,003 | | | 638,499 | |
| Accretion of asset retirement obligations | 5,075 |
| | 6,306 |
| | 7,080 |
| Accretion of asset retirement obligations | 12,086 | | | 10,072 | | | 6,117 | |
| Impairment of properties and equipment | | Impairment of properties and equipment | 402 | | | 882,393 | | | 38,536 | |
| (Gain) loss on sale of properties and equipment | 394 |
| | (766 | ) | | (43 | ) | (Gain) loss on sale of properties and equipment | (912) | | | (724) | | | 9,734 | |
| 1,280,052 |
| | 984,821 |
| | 544,559 |
| | 1,086,377 | | | 1,802,669 | | | 966,295 | |
Results of operations for crude oil and natural gas producing
activities before provision for income taxes | 255,146 |
| | (75,673 | ) | | (172,887 | ) | Results of operations for crude oil and natural gas producing
activities before provision for income taxes | 764,725 | | | (469,844) | | | 178,136 | |
| Income tax (expense) benefit | (185,667 | ) | | 47,247 |
| | 64,733 |
| Income tax (expense) benefit | (37,013) | | | 5,168 | | | (9,869) | |
| Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs | $ | 69,479 |
| | $ | (28,426 | ) | | $ | (108,154 | ) | Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs | $ | 727,712 | | | $ | (464,676) | | | $ | 168,267 | |
Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective statutory tax rates.
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below.for the periods presented:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (in thousands) |
Acquisition of properties: (1) | | | | | |
| Proved properties | $ | 1 | | | $ | 1,618,000 | | | $ | 16,007 | |
| Unproved properties | 3,151 | | | 114,202 | | | 9,567 | |
Development costs (2) | 583,488 | | | 528,686 | | | 780,851 | |
Exploration costs: (3) | | | | | |
| Exploratory drilling | 6,902 | | | 12,892 | | | 32,218 | |
| Geological and geophysical | 64 | | | 253 | | | 3,017 | |
| Total costs incurred | $ | 593,606 | | | $ | 2,274,033 | | | $ | 841,660 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
| Acquisition of properties: (1) | | | | | |
| Proved properties | $ | 205,253 |
| | $ | 172 |
| | $ | 268,567 |
|
| Unproved properties | 5,477 |
| | 18,914 |
| | 1,843,985 |
|
| Development costs (2) | 970,970 |
| | 688,165 |
| | 383,336 |
|
| Exploration costs: (3) | | | | | |
| Exploratory drilling | 36,704 |
| | 80,103 |
| | — |
|
| Geological and geophysical | 3,401 |
| | 3,881 |
| | 4,669 |
|
| Total costs incurred (4) | $ | 1,221,805 |
| | $ | 791,235 |
| | $ | 2,500,557 |
|
| | | | | | |
__________(1)Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property.
| |
(1) | Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. Proved properties |
(2)Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2021, 2020 and 2019, $227.8 million, $270.7 million and $308.9 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $40.9$35.3 million of infrastructure and pipeline costs in 2016.
| |
(2) | Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2018, 2017 and 2016, $438.4 million, $463.4 million and $204.6 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $74.6 million and $32.8 million of2019. Our infrastructure and pipeline costs in 2018 |
and 2017, respectively.
| |
(3) | Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. |
| |
(4) | During 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved undeveloped and development costs of $24.6 million. We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017. |
pipeline assets were divested in 2019.
(3)Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells.
Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities
Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below:below as of the dates indicated:
| | | | As of December 31, | | | | | | | | | | |
| | 2018 | | 2017 | | December 31, |
| | (in thousands) | | 2021 | | 2020 |
| | | | | | (in thousands) |
| Proved crude oil and natural gas properties | $ | 5,452,613 |
| | $ | 4,356,922 |
| Proved crude oil and natural gas properties | $ | 8,310,018 | | | $ | 7,523,639 | |
| Unproved crude oil and natural gas properties | 492,594 |
| | 1,097,317 |
| Unproved crude oil and natural gas properties | 306,181 | | | 350,677 | |
| Uncompleted wells, equipment and facilities | 332,264 |
| | 265,526 |
| Uncompleted wells, equipment and facilities | 371,360 | | | 523,376 | |
| Capitalized costs | 6,277,471 |
| | 5,719,765 |
| Capitalized costs | 8,987,559 | | | 8,397,692 | |
| Less accumulated DD&A | (2,341,897 | ) | | (1,803,847 | ) | |
| Accumulated DD&A | | Accumulated DD&A | (4,218,330) | | | (3,590,932) | |
| Capitalized costs, net | $ | 3,935,574 |
| | $ | 3,915,918 |
| Capitalized costs, net | $ | 4,769,229 | | | $ | 4,806,760 | |
| | | | | |
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves
The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btucontent, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties.
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves.reserves as of the dates indicated. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves.
| | | | As of December 31, | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | | December 31, |
| | (in thousands) | | 2021 | | 2020 | | 2019 |
| | | | | | | | (in thousands) |
| Future estimated cash flows | $ | 17,554,880 |
| | $ | 12,340,407 |
| | $ | 7,122,525 |
| Future estimated cash flows | $ | 26,143,031 | | | $ | 12,481,830 | | | $ | 14,590,604 | |
| Future estimated production costs* | (4,782,948 | ) | | (3,245,627 | ) | | (1,624,167 | ) | |
Future estimated production costs (1) | | Future estimated production costs (1) | (6,325,129) | | | (4,209,459) | | | (4,530,173) | |
| Future estimated development costs | (3,632,822 | ) | | (2,893,335 | ) | | (2,219,914 | ) | Future estimated development costs | (2,857,951) | | | (2,337,806) | | | (3,257,106) | |
| Future estimated income tax expense | (1,404,121 | ) | | (748,494 | ) | | (597,476 | ) | Future estimated income tax expense | (3,088,187) | | | (301,507) | | | (907,382) | |
| Future net cash flows | 7,734,989 |
| | 5,452,951 |
| | 2,680,968 |
| Future net cash flows | 13,871,764 | | | 5,633,058 | | | 5,895,943 | |
| 10% annual discount for estimated timing of cash flows | (3,287,273 | ) | | (2,572,846 | ) | | (1,260,339 | ) | 10% annual discount for estimated timing of cash flows | (5,963,592) | | | (2,350,879) | | | (2,585,609) | |
| Standardized measure of discounted future estimated net cash flows | $ | 4,447,716 |
| | $ | 2,880,105 |
| | $ | 1,420,629 |
| Standardized measure of discounted future estimated net cash flows | $ | 7,908,172 | | | $ | 3,282,179 | | | $ | 3,310,334 | |
_______________________
| |
* | Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses. |
(1)Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses.
The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows:flows for the periods presented:
| | | | Year Ended December 31, | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | | Year Ended December 31, |
| | (in thousands) | | 2021 | | 2020 | | 2019 |
| | | | | | | | (in thousands) |
| Beginning of period | $ | 2,880,105 |
| | $ | 1,420,629 |
| | $ | 1,096,864 |
| Beginning of period | $ | 3,282,179 | | | $ | 3,310,334 | | | $ | 4,447,716 | |
| Sales of crude oil, natural gas and NGLs production, net of production costs | (1,131,244 | ) | | (729,506 | ) | | (387,576 | ) | Sales of crude oil, natural gas and NGLs production, net of production costs | (2,106,287) | | | (854,006) | | | (1,037,920) | |
| Net changes in prices and production costs (1) | 936,077 |
| | 841,713 |
| | (205,760 | ) | Net changes in prices and production costs (1) | 5,312,870 | | | (1,771,019) | | | (2,122,538) | |
| Extensions, discoveries and improved recovery, less related costs | 190,084 |
| | 47,240 |
| | 15,128 |
| Extensions, discoveries and improved recovery, less related costs | 20,201 | | | 14,110 | | | 39,606 | |
| Sales of reserves | (42,362 | ) | | (2,613 | ) | | (3,745 | ) | Sales of reserves | — | | | (26,771) | | | (14,533) | |
| Purchases of reserves | 467,807 |
| | 224,483 |
| | 487,636 |
| Purchases of reserves | 76,440 | | | 1,969,846 | | | 18,816 | |
| Development costs incurred during the period | 462,088 |
| | 419,047 |
| | 268,672 |
| Development costs incurred during the period | 338,098 | | | 329,495 | | | 605,753 | |
| Revisions of previous quantity estimates | 631,198 |
| | 484,431 |
| | (320,286 | ) | Revisions of previous quantity estimates | 2,645,379 | | | (775,009) | | | 538,242 | |
| Changes in estimated income taxes | (232,002 | ) | | (138,560 | ) | | (13,630 | ) | Changes in estimated income taxes | (1,628,304) | | | 354,369 | | | 346,826 | |
| Net changes in future development costs | (123,663 | ) | | 25,183 |
| | 391,145 |
| Net changes in future development costs | (168,332) | | | 367,630 | | | 206,003 | |
| Accretion of discount | 583,744 |
| | 167,487 |
| | 133,747 |
| Accretion of discount | 345,454 | | | 572,483 | | | 532,127 | |
| Timing and other | (174,116 | ) | | 120,571 |
| | (41,566 | ) | Timing and other | (209,526) | | | (209,283) | | | (249,764) | |
| End of period | $ | 4,447,716 |
| | $ | 2,880,105 |
| | $ | 1,420,629 |
| End of period | $ | 7,908,172 | | | $ | 3,282,179 | | | $ | 3,310,334 | |
______________________
| |
(1) | Our weighted-average price, net of production costs per Boe, in our 2018 reserve report increased to $23.44 as compared to $20.08 for 2017 and $15.73 for 2016. |
(1)Our weighted average price, net of production costs per Boe, in our 2021 reserve report increased to $24.34 as compared to $11.32 for 2020 and $16.18 for 2019.
The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
QUARTERLY FINANCIAL INFORMATION - UNAUDITED
Quarterly financial data for the years ended December 31, 2018 and 2017 is presented below. The quarterly consolidated statements of operations below reflect our revised presentation. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year.
|
| | | | | | | | | | | | | | | |
| | 2018 |
| | Quarter Ended |
| | March 31 (1) | | June 30 | | September 30 (1) | | December 31 (1) |
| | (in thousands, except per share data) |
| Total revenues | $ | 260,600 |
| | $ | 212,531 |
| | $ | 280,717 |
| | $ | 794,811 |
|
| Total costs, expenses and other | 260,924 |
| | 400,770 |
| | 270,593 |
| | 538,626 |
|
| Income (loss) from operations | (324 | ) | | (188,239 | ) | | 10,124 |
| | 256,185 |
|
| Income (loss) before income taxes | (17,705 | ) | | (205,580 | ) | | (7,310 | ) | | 238,024 |
|
| Net income (loss) | $ | (13,139 | ) | | $ | (160,257 | ) | | $ | (3,434 | ) | | $ | 178,853 |
|
| | | | | | | | |
| Earnings per share: | | | | | | | |
| Basic | $ | (0.20 | ) | | $ | (2.43 | ) | | $ | (0.05 | ) | | $ | 2.71 |
|
| Diluted | (0.20 | ) | | (2.43 | ) | | (0.05 | ) | | 2.71 |
|
|
| | | | | | | | | | | | | | | |
| | 2017 |
| | Quarter Ended |
| | March 31 | | June 30 | | September 30 (1) | | December 31 (2) |
| | (in thousands, except per share data) |
| Total revenues | $ | 273,707 |
| | $ | 275,158 |
| | $ | 183,235 |
| | $ | 189,516 |
|
| Total costs, expenses and other | 182,004 |
| | 190,522 |
| | 579,326 |
| | 208,016 |
|
| Income (loss) from operations | 91,703 |
| | 84,636 |
| | (396,091 | ) | | (18,500 | ) |
| Income (loss) before income taxes | 72,476 |
| | 65,787 |
| | (414,887 | ) | | 62,808 |
|
| Net income (loss) | $ | 46,146 |
| | $ | 41,250 |
| | $ | (292,537 | ) | | $ | 77,637 |
|
| | | | | | | | |
| Earnings per share: | | | | | | | |
| Basic | $ | 0.70 |
| | $ | 0.63 |
| | $ | (4.44 | ) | | $ | 1.18 |
|
| Diluted | 0.70 |
| | 0.62 |
| | (4.44 | ) | | 1.17 |
|
(1) Impairment charges, which are included in total costs, expenses and other above, reflect the correction of two errors in the timing of the
reporting of certain impairments. In 2018, we corrected an error in our calculation of unproved properties and goodwill originally
recorded in 2017, resulting in an additional impairment charge of $6.3 million being recorded during the three months ended March 31,
2018. Further, during the fourth quarter of 2018, we corrected for an additional $8.4 million impairment of unproved properties relating
to the three months ended September 30, 2018. See the footnote titled Properties and Equipment to our consolidated financial statements
included elsewhere in this report.
(2) Net income of $77.6 million for the quarter ended December 31, 2017 is primarily due to an income tax benefit of $114.4 million resulting
from a decrease in deferred tax assets and liabilities related to the 2017 Tax Act.
FINANCIAL STATEMENT SCHEDULE
Schedule II -VALUATION AND QUALIFYING ACCOUNTS
| | | Description | | Beginning
Balance
January 1, | | Charged to
Costs and
Expenses | | Deductions (1) | | Ending
Balance
December 31, | Description | | Beginning
Balance
January 1, | | Charged to
Costs and
Expenses | | Deductions (1) | | Ending
Balance
December 31, |
| | | (in thousands) | | | (in thousands) |
| 2021: | | 2021: | |
| | | | | | | | | | |
| 2018: | | | | | | | | | |
| Allowance for doubtful accounts | | $ | 3,128 |
| | $ | 1,276 |
| | $ | 23 |
| | $ | 4,381 |
| Allowance for doubtful accounts | | $ | 6,763 | | | $ | (359) | | | $ | (349) | | | $ | 6,055 | |
| Allowance for expirations of unproved crude oil and natural gas properties | | 251,159 |
| | 388,068 |
| | 96,518 |
| | 542,709 |
| Allowance for expirations of unproved crude oil and natural gas properties | | 224,019 | | | — | | | (17,691) | | | 206,328 | |
| 2017: | | | | | | | | | |
| Allowance for uncollectible notes | | $ | 44,038 |
| | $ | — |
| | $ | 44,038 |
| | $ | — |
| |
| 2020: | | 2020: | |
| | Allowance for doubtful accounts | | 2,190 |
| | 1,108 |
| | 170 |
| | 3,128 |
| Allowance for doubtful accounts | | $ | 7,476 | | | $ | 3,179 | | | $ | (3,892) | | | $ | 6,763 | |
| Allowance for expirations of unproved crude oil and natural gas properties | | 359 |
| | 263,817 |
| | 13,017 |
| | 251,159 |
| Allowance for expirations of unproved crude oil and natural gas properties | | 6,881 | | | 223,895 | | | (6,757) | | | 224,019 | |
| 2016: | | | | | | | | | |
| Allowance for uncollectible notes | | $ | — |
| | $ | 44,038 |
| | $ | — |
| | $ | 44,038 |
| |
| 2019: | | 2019: | |
| | Allowance for doubtful accounts | | 2,009 |
| | 1,309 |
| | 1,128 |
| | 2,190 |
| Allowance for doubtful accounts | | $ | 4,381 | | | $ | 3,209 | | | $ | (114) | | | $ | 7,476 | |
| Allowance for expirations of unproved crude oil and natural gas properties | | 144 |
| | 215 |
| | — |
| | 359 |
| Allowance for expirations of unproved crude oil and natural gas properties | | 542,709 | | | 8,523 | | | (544,351) | | | 6,881 | |
____________
| |
(1) | For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. |
(1)For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of December 31, 2018,2021, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2018 because of the material weaknesses in our internal control over financial reporting described below.2021.
Management'sManagement’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our CEOChief Executive Officer and CFO,Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2018,2021, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"(“COSO”).
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected Based on a timely basis.
We did not maintain a sufficient complement of personnel within the Land Department as a result of increased volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of land administrative records associated with unproved leases, which are used in verifying the completeness, accuracy, valuation, rights and obligations over the accounting of properties and equipment, sales and accounts receivable and costs and expenses. These control deficiencies resulted in immaterial adjustments to our unproved properties, impairment of unproved properties, sales, accounts receivable and depletion expense accounts and related disclosures in our consolidated financial statements for the years ended December 31, 2018 and 2017. Additionally, these control deficiencies could result in misstatements of substantially all accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, our management has determined that these control deficiencies constitute material weaknesses.
Because of these material weaknesses,this evaluation, management concluded that we did not maintainthe Company maintained effective internal control over financial reporting as of December 31, 2018.2021.
The effectiveness of our internal control over financial reporting as of December 31, 20182021 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8.
Remediation Plan for Material Weaknesses
We are committed to continuing to review, optimize and enhance our internal control over financial reporting. In response to the identified material weaknesses, our management, with the oversight of the Audit Committee of our Board of
Directors, has assessed a number of different remediation initiatives to improve our internal control over financial reporting. Building on our efforts during 2017, we continued throughout 2018 to dedicate significant resources and efforts to improve our internal control over financial reporting and to take steps to remediate the material weaknesses identified above. While certain remediation plans have been implemented, we continue to actively plan for and implement additional remediation measures.
During 2018, we have taken steps to strengthen the control activities within the Land Department, which include the combination of hiring of additional personnel with relevant experience, increased layers of supervision, and division of responsibilities within the Land Department. We have also designed and implemented control activities to verify the completeness and accuracy of land administrative records associated with unproved leases, including the verification of the reliability of underlying data used in the execution of the control activities. As we continue to evaluate and work to improve our internal control over financial reporting, we may take additional measures to address these control deficiencies, or we may modify certain of the remediation measures described above to improve the operating effectiveness of those measures. These material weaknesses will not be considered remediated until the applicable remediated controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended December 31, 20182021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 20192022 Annual Stockholders'Stockholders’ meeting and is incorporated by reference in this report.
ITEM 11. EXECUTIVE COMPENSATION
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 20192022 Annual Stockholders'Stockholders’ meeting and is incorporated by reference in this report.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 20192022 Annual Stockholders'Stockholders’ meeting and is incorporated by reference in this report.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 20192022 Annual Stockholders'Stockholders’ meeting and is incorporated by reference in this report.
ITEM 14. PRINCIPAL ACCOUNTINGACCOUNTANT FEES AND SERVICES
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 20192022 Annual Stockholders'Stockholders’ meeting and is incorporated by reference in this report.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
|
| | | | | | | |
| (a) | (1) | Exhibits: |
| | See Exhibits Index on the following page. |
ITEM 16. FORM 10-K SUMMARY
None.
Exhibits Index
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Incorporated by Reference | | |
| Exhibit Number | | Exhibit Description | | Form | | SEC File Number | | Exhibit | | Filing Date | | Filed Herewith |
| | | | | | | | | | | | |
| 2.1 | | | | 8-K12B | | 001-37419 | | 2.1 | | 6/8/2015 | | |
| | | | | | | | | | | | |
| 2.2 | | | | 8-K | | 001-37419 | | 2.1 | | 8/26/2019 | | |
| | | | | | | | | | | | |
| 2.3 | | | | 8-K | | 001-37419 | | 2.1 | | 2/28/2022 | | |
| | | | | | | | | | | | |
| 3.1 | | | | 8-K12B | | 001-37419 | | 3.1 | | 5/27/2020 | | |
| | | | | | | | | | | | |
| 3.2 | | | | 8-K12B | | 001-37419 | | 3.2 | | 6/8/2015 | | |
| | | | | | | | | | | | |
| 4.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| | | | | Incorporated by Reference | | |
| Exhibit Number | | Exhibit Description | | Form | | SEC File Number | | Exhibit | | Filing Date | | Filed Herewith |
| | | | | | | | | | | | | |
| 2.1 | | | | 8-K12B | | 001-37419
| | 2.1 | | 6/8/2015 | | |
| | | | | | | | | | | | | |
| 2.2 | | | | 8-K | | 001-37419
| | 2.1 | | 8/24/2016 | | |
| | | | | | | | | | | | | |
| 2.3 | | Asset Purchase and Sale Agreement, dated August 23, 2016, by and among 299 Resources, LLC, 299 Production, LLC, 299 Pipeline, LLC, Kimmeridge Energy Management Company GP, LLC and PDC Energy, Inc.
| | 8-K | | 001-37419
| | 2.2 | | 8/24/2016 | | |
| | | | | | | | | | | | | |
| 3.1 | | | | 8-K12B | | 001-37419
| | 3.1 | | 6/8/2015 | | |
| | | | | | | | | | | | | |
| 3.2 | | | | 8-K12B | | 001-37419
| | 3.2 | | 6/8/2015 | | |
| | | | | | | | | | | | | |
| 4.1 | | | | 10-K | | 001-37419 | | 4.1 | | 2/28/2017 | |
|
| | | | | | | | | | | | | |
| 4.2 | | Indenture, dated as of November 29, 2017, by and between PDC Energy, Inc., PDC Permian, Inc., a subsidiary guarantor of the Company, and U.S. Bank Trust National Association, as Trustee, relating to the 5.750% Senior Notes due 2026.
| | 8-K | | 001-37419
| | 4.1 | | 11/29/2017 | | |
| | | | | | | | | | | | | |
| 4.3 | | | | 8-K | | 001-37419 | | 4.1 | | 9/14/2016 | | |
| | | | | | | | | | | | | |
| 4.4 | | | | 8-K | | 001-37419 | | 4.2 | | 9/14/2016 | | |
| | | | | | | | | | | | | |
| 4.5 | | | | 8-K | | 001-37419 | | 4.1 | | 9/15/2016 | | |
| | | | | | | | | | | | | |
| 10.1 | | | | 8-K | | 000-07246 | | 10.1 | | 6/8/2015 | | |
| | | | | | | | | | | | | |
| 10.2 | | | | 10-K | | 001-37419 | | 10.2 | | 2/28/2017 | |
|
| | | | | | | | | | | | | |
| 10.3 | | | | 10-K | | 001-37419 | | 10.3 | | 2/27/2018 | |
|
| | | | | | | | | | | | | |
| 10.4 | | | | 10-K | | 000-07246 | | 10.26 | | 2/27/2009 | | |
| | | | | | | | | | | | | |
| 10.4.1 | | | | 8-K | | 000-07246 | |
| | 4/23/2010 | | |
| | | | | | | | | | | | | |
| 10.5 | | | | 10-K | | 001-37419 | | 10.5 | | 2/22/2016 | |
|
| | | | | | | | | | | | | |
| 10.6 | | | | 10-K | | 001-37419 | | 10.6 | | 2/22/2016 | |
|
| | | | | | | | | | | | | |
| 10.7 | | | | 10-K | | 000-07246 | | 10.5.2 | | 2/21/2014 | |
|
| | | | | | | | | | | | | |
| 10.7.1 | | | | 10-K | | 000-07246 | | 10.9 | | 2/27/2013 | |
|
| | | | | | | | | | | | | |
| 10.7.2 | | | | 10-K | | 000-07246 | | 10.10 | | 2/27/2013 | |
|
| | | | | | | | | | | | | |
| 10.7.3 | | | | 10-K | | 000-07246 | | 10.5.4 | | 2/19/2015 | |
|
| | | | | | | | | | | | | |
| 10.7.4 | | | | 10-K | | 000-07246 | | 10.5.5 | | 2/19/2015 | |
|
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Incorporated by Reference | | |
| Exhibit Number | | Exhibit Description | | Form | | SEC File Number | | Exhibit | | Filing Date | | Filed Herewith |
| | | | | | | | | | | | |
| 4.2 | | | | 10-K | | 001-37419 | | 4.1.1 | | 2/26/2020 | | |
| | | | | | | | | | | | |
| 4.3 | | | | 8-K | | 001-37419 | | 4.1 | | 9/14/2016 | | |
| | | | | | | | | | | | |
| 4.4 | | | | 8-K | | 001-37419 | | 4.1 | | 9/15/2016 | | |
| | | | | | | | | | | | |
| 10.1 | | | | 8-K | | 000-07246 | | 10.1 | | 6/8/2015 | | |
| | | | | | | | | | | | |
| 10.2 | | | | 10-K | | 001-37419 | | 10.5 | | 2/22/2016 | | |
| | | | | | | | | | | | |
| 10.3 | | | | 10-Q | | 001-37419 | | 10.1 | | 8/6/2020 | | |
| | | | | | | | | | | | |
| 10.4 | | | | 10-K | | 000-07246 | | 10.10 | | 2/27/2013 | | |
| | | | | | | | | | | | |
| 10.5 | | | | 10-K | | 000-07246 | | 10.5.5 | | 2/19/2015 | | |
| | | | | | | | | | | | |
| 10.6 | | | | 10-K | | 000-07246 | | 10.5.8 | | 2/19/2015 | | |
| | | | | | | | | | | | |
| 10.7 | | | | 10-Q | | 001-37419 | | 99.1 | | 5/2/2019 | | |
| | | | | | | | | | | | |
| 10.8 | | | | 10-Q | | 001-37419 | | 99.3 | | 5/2/2019 | | |
| | | | | | | | | | | | |
| 10.9 | | | | 10-Q | | 001-37419 | | 99.4 | | 5/2/2019 | | |
| | | | | | | | | | | | |
| 10.10 | | | | 8-K | | 001-37419 | | 10.2 | | 1/14/2020 | | |
| | | | | | | | | | | | |
| 10.11 | | | | 10-Q | | 001-37419 | | 99.1 | | 5/7/2020 | | |
| | | | | | | | | | | | |
| 10.12 | | | | 10-Q | | 001-37419 | | 99.3 | | 5/7/2020 | | |
| | | | | | | | | | | | |
| 10.13 | | | | 10-Q | | 001-37419 | | 99.1 | | 5/6/2021 | | |
| | | | | | | | | | | | |
| 10.14 | | | | 10-Q | | 001-37419 | | 99.2 | | 5/6/2021 | | |
| | | | | | | | | | | | |
| 10.15 | | | | 10-Q | | 001-37419 | | 99.3 | | 5/6/2021 | | |
| | | | | | | | | | | | |
| 10.16 | | | | 10-Q | | 001-37419 | | 10.2 | | 8/6/2020 | | |
| | | | | | | | | | | | |
| 10.17 | | | | 8-K | | 001-37419 | | 10.1 | | 5/31/2018 | | |
| | | | | | | | | | | | |
| 10.18 | | | | 8-K | | 001-37419
| | 10.1 | | 5/27/2020 | | |
| | | | | | | | | | | | |
| 10.19 | | | | 8-K | | 001-37419 | | 10.1 | | 1/14/2020 | | |
| | | | | | | | | | | | |
| 10.20 | | | | 10-Q | | 001-37419 | | 10.1 | | 11/3/2021 | | |
| | | | | | | | | | | | |
| 21.1 | | | | 10-K | | 001-37419 | | 21.1 | | 2/26/2020 | | |
| | | | | | | | | | | | |
| 23.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 23.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| | | | | Incorporated by Reference | | |
| Exhibit Number | | Exhibit Description | | Form | | SEC File Number | | Exhibit | | Filing Date | | Filed Herewith |
| | | | | | | | | | | | | |
| 10.7.5 | | | | 10-K | | 000-07246 | | 10.5.6 | | 2/19/2015 | |
|
| | | | | | | | | | | | | |
| 10.7.6 | | | | 10-K | | 000-07246 | | 10.5.7 | | 2/19/2015 | |
|
| | | | | | | | | | | | | |
| 10.7.7 | | | | 10-K | | 000-07246 | | 10.5.8 | | 2/19/2015 | |
|
| | | | | | | | | | | | | |
| 10.7.8 | | | | 10-K | | 001-37419 | | 10.7.8 | | 2/22/2016 | |
|
| | | | | | | | | | | | | |
| 10.7.9 | | | | 10-Q | | 001-37419 | | 99.1 | | 5/3/2018 | | |
| | | | | | | | | | | | | |
| 10.7.10 | | | | 10-Q | | 001-37419 | | 99.2 | | 5/3/2018 | | |
| | | | | | | | | | | | | |
| 10.7.11 | | | | 10-Q | | 001-37419 | | 99.3 | | 5/3/2018 | | |
| | | | | | | | | | | | | |
| 10.9 | | | | 8-K | | 000-07246 | | 10.3 | | 4/23/2010 | | |
| | | | | | | | | | | | | |
| 10.9.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | | |
| 10.10 | | | | 8-K | | 000-07246 | | 10.4 | | 4/23/2010 | | |
| | | | | | | | | | | | | |
| 10.11 | | | | 8-K | | 001-37419 | | 10.1 | | 5/25/2018 | | |
| | | | | | | | | | | | | |
| 10.12 | | | | 10-K | | 001-37419 | | 10.14 | | 2/28/2017 | |
|
| | | | | | | | | | | | | |
| 10.12.1 | | | | 10-K | | 001-37419 | | 10.14.1 | | 2/28/2017 | |
|
| | | | | | | | | | | | | |
| 10.13 | | | | 8-K | | 001-37419
| | 10.1 | | 5/31/2018 | | |
| | | | | | | | | | | | | |
| 10.14 | | | | 8-K | | 001-37419
| | 10.1 | | 2/9/2018 | | |
| | | | | | | | | | | | | |
| 10.15 | | | | 8-K | | 001-37419
| | 10.1 | | 12/7/2016 | | |
| | | | | | | | | | | | | |
| 10.16 | | | | 8-K | | 001-37419 | | 10.2 | | 12/7/2016 | | |
| | | | | | | | | | | | | |
| 21.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | | |
| 23.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | | |
| 23.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | | |
| 23.3 | | | | | | | | | | | | X |
| | | | | | | | | | | | | |
| 31.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | | |
| 31.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | | |
| 32.1* | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| 99.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Incorporated by Reference | | |
| Exhibit Number | | Exhibit Description | | Form | | SEC File Number | | Exhibit | | Filing Date | | Filed Herewith |
| | | | | | | | | | | | |
| 23.3 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 31.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 31.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 32.1* | | | | | | | | | | | | |
| | | | | | | | | | | | |
| 99.1 | | | | Incorporated by Reference | | | | | | | | X |
Exhibit Number | | Exhibit Description | | Form | | SEC File Number | | Exhibit | | Filing Date | | Filed Herewith |
| 99.2 | | | | | | | | | | | | |
99.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101.INS | | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101.SCH | | XBRL Taxonomy Extension Schema Document | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101.LAB | | XBRL Taxonomy Extension Label Linkbase Document | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document | | | | | | | | | | X |
| | | | | | | | | | | | |
| 104 | | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) | | | | | | | | | | X |
| | | | | | | | | | | | |
| * Furnished herewith. |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| PDC ENERGY, INC. |
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| PDC ENERGY, INC. |
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| By: /s/ Barton Brookman |
| Barton Brookman |
| President and Chief Executive Officer
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| February 27, 201928, 2022 |
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
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| Signature | | Title | | Date |
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| /s/ Barton Brookman | | President, Chief Executive Officer and Director | | February 28, 2022 |
| Barton Brookman | | (principal executive officer) | | |
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Signature | | Title | | Date |
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/s/ Barton Brookman | | President, Chief Executive Officer and Director | | February 27, 2019 |
Barton Brookman | | (principal executive officer) | | |
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| /s/ R. Scott Meyers | | Senior Vice President and Chief Financial Officer | | February 27, 201928, 2022 |
| R. Scott Meyers | | (principal financial officer) | | |
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| /s/ Douglas Griggs | | Chief Accounting Officer | | February 27, 201928, 2022 |
| Douglas Griggs | | (principal accounting officer) | | |
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/s/ Jeffrey C. SwovelandMark E. Ellis | | Non-Executive Chairman and Directorof the Board of Directors | | February 27, 201928, 2022 |
Jeffrey C. SwovelandMark E. Ellis | | | | |
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/s/ Anthony J. CrisafioPamela R. Butcher | | Director | | February 27, 201928, 2022 |
Anthony J. CrisafioPamela R. Butcher | | | | |
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/s/ Larry F. MazzaPaul J. Korus | | Director | | February 27, 201928, 2022 |
Larry F. MazzaPaul J. Korus | | | | |
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| /s/ David C. Parke | | Director | | February 27, 201928, 2022 |
| David C. Parke | | | | |
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/s/ Randy S. NickersonLynn A. Peterson | | Director | | February 27, 201928, 2022 |
Randy S. NickersonLynn A. Peterson | | | | |
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/s/ Mark E. EllisCarlos A. Sabater | | Director | | February 27, 201928, 2022 |
Mark E. EllisCarlos A. Sabater | | | | |
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/s/ Christina M. IbrahimDiana L. Sands | | Director | | February 27, 201928, 2022 |
Christina M. IbrahimDiana L. Sands | | | | |
GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS
UNITS OF MEASUREMENT
The following presents a list of units of measurement used throughout the document.
Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume.
Bcf – One billion cubic feet of natural gas volume.
Boe – One barrel of crude oil equivalent.
Btu – British thermal unit.
BBtu – One billion British thermal units.
MBoe – One thousand barrels of crude oil equivalent.
MBbls – One thousand barrels of crude oil.
Mcf – One thousand cubic feet of natural gas volume.
MMBoe – One million barrels of crude oil equivalent.
MMBbls – One million barrels of crude oil.
MMBtu – One million British thermal units.
MMcf – One million cubic feet of natural gas volume.
MMcfd – One million cubic feet of natural gas volume per day.
GLOSSARY OF INDUSTRY TERMS
The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report:
Brent - Brent sweet light crude oil.
CIG - Colorado Interstate Gas.
Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.
Condensate - Liquid hydrocarbons associated with the production that is primarily natural gas.
Developed acreage - Acreage assignable to productive wells.
Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location.
Dry well or dry hole- A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.
Exploratory well- A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Extensions, discoveries and other additions - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.
Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest.
Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons.
Gross acres or wells - Refers to the total acres or wells in which we have a working interest.
Henry Hub - Refers to the pricing point for natural gas futures contracts traded on NYMEX.
Horizontal drilling- A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.
Intensity - Greenhouse gas and methane intensity is reported as total metric tons of methane emissions divided by gross annual production in MBOE.
Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners.
Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane and other natural gasolines.
Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells.
Net production- Crude oil and natural gas production that we own, less royalties and production due to others.
Non-operated - A project in which we are not the operator.
NYMEX- New York Mercantile Exchange.
Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease.
Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest.
Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates.
Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure.
Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above.
Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.
Proved developed producing reserves or PDPs- Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.
Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves.
Proved reserves - This term means "proved“proved oil and gas reserves"reserves” as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs,
and under existing conditions, operating methods and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved undeveloped reserves or PUDs- Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation.
Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project.
Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Section - A square tract of land one mile by one mile, containing 640 acres.
Spud - To begin drilling; the act of beginning a hole.
Standardized measure of discounted future net cash flows or standardized measure- Future net cash flows discounted at a rate of 10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense.
Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production.
Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves.
Waha - Waha West Texas natural gas prices
Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations.
Workover - Major remedial operations on a producing well to restore, maintain, or improve the well'swell’s production.
