Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas production, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.
inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise, especially in areas of planned expansion where such facilities do not currently exist. The amount of oil and gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. For example, recent increases in activity in the DJ Basin have contributed to bottlenecks in processing and transportation that have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Additionally, in recent months, we have experiencedexperience constraints from time to time on the capacity available in certain pipelines that we use to transport natural gas and have been forced to shut in some production from time to time. Capacity constraints typically reduce the productivity of some of our older vertical wells and may on occasion limit incremental production from some of our newer horizontal wells. This constrains our production and reduces our revenue from the affected wells. Capacity constraints affecting natural gas production also impact the associated NGL. We are also dependent on the availability and capacity of oil purchasers for our production. Increases in the amount of oil that we transport out of the DJ Basin for sale would result in an increase in our transportation costs and would reduce the price we receive for the affected production.
Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the DJ Basin, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.
While we have undertaken initiatives to expand our access to midstream and operational infrastructure, these initiatives may be delayed or unsuccessful. As a result, our business, financial condition and results of operations could be adversely affected.
Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. During the year ended December 31, 2017,2020, we have drilled 32337 gross one-mile equivalentoperated horizontal wells and have completed 33245 gross one-mile equivalentoperated horizontal wells and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. In addition, our horizontal drilling activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecast, as well as access to liquidity sources, such as the capital markets, our revolving credit facilityRBL Credit Facility and derivative contracts. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, pipeline and tank ruptures or unauthorized discharges of toxic gases or other pollutants.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
Properties that we decide to drill may not yield oil, natural gas or NGL in commercially viable quantities.
Properties that we decide to drill that do not yield oil, natural gas or NGL in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:
We are subject to stringent environmental and health and safety laws and regulations that could expose us to significant costs and liabilities.
Our oil and natural gas exploration, development and production operations are subject to numerous stringent and complex federal, state and local laws and regulations governing safety and health aspects of our operations, the release, disposal or discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting drilling and
other regulated activities; the restriction of types, quantities and concentration of materials that may be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmentalGovernmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring costly actions. For example, on May 2, 2017, following an incident in Firestone, Colorado, the COGCC issued a Notice to Operators (the “Notice”) that, among other things, required operators of oil and natural gas wells in Colorado: (i) by May 30, 2017, toColorado re-inspect all existing flowlines and pipelines located within 1,000 feet of a defined “building unit,” which term includes residences andand/or properly abandon certain commercial facilities, to identify the well API number and tank battery location ID number associated with each line; (ii) by May 30, 2017, to inspect all existing flowlines and pipelines, regardless of distance to a “building unit,” to verify that any existing flowline or pipeline not in use, regardless of when it was installed or taken out of service, is abandoned in conformity with applicable rules; (iii) by June 30, 2017, to ensure and document that all flowlines within 1,000 feet of a “building unit” have integrity; and (iv) by June 30, 2017, to complete abandonment of any
Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
We may be involved in legal proceedings that could result in substantial liabilities.
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, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Additionally, citizen groups have brought and, in certain instances, may continue to bring legal proceedings against us to challenge our ability to receive environmental permits that we need to operate. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, loss of necessary environmental permits, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has adopted rules under authority of the CAA that, among other things, establish PSD construction and Title V permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal pollutant emissions, which reviews could require meeting “best available control technology” standards for those emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among other things, onshore producing facilities, which include certain of our operations. Federal agencies also have begun directly regulating emissions of methane from oil and natural gas operations, with the EPA publishing NSPS Subpart OOOOa standards in June 2016 that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions and the BLM publishing requirements in November 2016 to reduce methane emissions from venting, flaring, and leaking on public lands. Both of the EPA's and BLM's methane rules have been subject to attempted stays of the rules or parts thereof by the respective agencies and rulemakings that would further amend those rules also have been proposed. THe future implementation of these two methane rules are uncertain but remain a possibility. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In follow-up to an earlier announcement by President Trump, in August 2017, the U.S. Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHG or otherwise limit emissions of GHG from, our equipment and operations could result in increased costs to reduce emissions of GHG associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil, natural gas and NGL we produce and lower the value of our reserves, which devaluation could be significant. One or more of these developments could have a materially adverse effect on our business, financial condition and results of operations. Finally, notwithstanding potential risks related to climate change, the International Energy Agency, an autonomous intergovernmental organization involved in international energy policy, estimates that global energy demand will continue to rise and will not peak until after 2040 and oil and gas will continued to represent a substantial percentage of global energy use over that time. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.
Please read “Business-Regulation of Environmental and Safety and Health Matters-Regulation of Greenhouse Gas (“GHG”) Emissions” for a further description of the laws and regulations relating to climate change that affect us.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions or similar state agencies but several federal agencies have asserted regulatory authority over certain aspects of the process. In addition, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Also, from time to time, the U.S. Congress has considered, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. At the state level, Colorado, where we conduct operations, is among the states that has adopted, and other states are considering adopting, regulations that impose new or more stringent permitting, disclosure or well-construction requirements on hydraulic fracturing operations. States may also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. In addition to state laws, local land use restrictions may restrict drilling or the hydraulic fracturing and cities may adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on federal and American Indian lands, we could incur potentially significant added cost to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Moreover, because most of our operations are conducted in a particular area, the DJ Basin in Colorado, legal restrictions imposed in that area will have a significantly greater adverse effect than if we had our operations spread out amongst several diverse geographic areas. Consequently, in the event that local or state restrictions or prohibitions are adopted in the DJ Basin in Colorado that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
At the local level, some municipalities and local governments have adopted or are considering bans on hydraulic fracturing. Beginning in 2012, voters in the cities of Fort Collins, Boulder, Longmont, Broomfield and Lafayette, Colorado approved bans of varying length on hydraulic fracturing within their respective city limits. In 2014, Boulder and Larimer county lower courts overturned the bans. The cities of Longmont and Fort Collins appealed the decisions. In August 2015, the Court of Appeals requested that the Colorado Supreme Court rule on the issue. The Colorado Supreme Court struck down the Fort Collins and Longmont bans in May 2016. Nonetheless, extended moratoria, like that put in place by Boulder County in December 2016, remain a threat to oil and gas operations in Colorado.
Please read “Business—“Business and Properties—Regulation of Environmental and Safety and Health Matters—Hydraulic Fracturing Activities” for a further description of the laws and regulations relating to hydraulic fracturing that affect us.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties and market oil or natural gas.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business.
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 a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, 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. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows.
Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the United States financial market have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.
We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.
We have grown rapidly since we began operations in late 2012. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:
increased responsibilities for our executive level personnel;
increased administrative burden;
increased capital requirements; and
increased organizational challenges common to large, expansive operations.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.
Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGL. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations from local sources, we may be unable to produce oil, natural gas and NGL economically, which could have an adverse effect on our financial condition, results of operations and cash flows.
Restrictions on drilling activities intended to protect certain species of wildlife and natural resources may adversely affect our ability to conduct drilling activities areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife and natural resources. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves.
Regulation of greenhouse gases and climate change could have a negative impact on our business.
Some scientific studies have suggested that emissions of greenhouse gases may be contributing to warming of the earth’s atmosphere and other climatic changes. Such studies have resulted in increased local, state, regional, national, and international attention and actions relating to issues of climate change and the effect of GHG emissions, particularly emissions from fossil fuels. For example, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change (“UNFCCC”). The U.S. was among 195 nations that participated in the creation of an international accord in December 2015, the Paris Agreement, with the objective of limiting greenhouse gas emissions. The Paris Agreement entered into force on November 4, 2016 and, as of January 2020, had been ratified by 187 of the 197 parties to the UNFCC. The EPA has also taken action under the CAA to regulate greenhouse gas emissions. In addition, a number of states have either proposed or implemented restrictions on greenhouse gas emissions. International accords such as the Paris Agreement may result in additional regulations to control greenhouse gas emissions. Other developments focused on restricting GHG emissions include but are not limited to the Kyoto Protocol; the European Union Emission Trading System; the United Kingdom’s Carbon Reduction Commitment; and, in the U.S., the Regional Greenhouse Gas Initiative, the Western Regional Climate Action Initiative, and various state programs.
The enactment of derivatives legislation and associated regulations could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking underWhile many rules implementing the Dodd-Frank Act have been finalized, some have not, and, as a result, the final form of the regulatory regime for commodity derivatives remains uncertain. Position limits for certain energy commodity futures and options contracts, as well as economically equivalent swaps, futures and options, are subject to ongoing rulemaking activities. With regard to position limits, in November 2013,January 2020, the CFTC withdrew the 2013 proposal, the 2016 supplement, and the 2016 reproposal, and issued a new proposed new rules that would placerule which includes limits on positions in (1) certain core“Core Referenced Futures Contracts,” including contracts for several energy commodities; (2) futures and equivalent swaps contracts foroptions on futures that are directly or indirectly linked to certain physical commodities, subjectthe price of a Core Referenced Futures Contract, or to exceptionsthe same commodity for certaindelivery at the same location as specified in that Core Referenced Futures Contract; and (3) economically equivalent swaps. The proposal also includes exemptions from position limits for bona fide hedging transactions.activities. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception to the mandatory clearing, trade-execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact our liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.
Risks Related to Capital
Recent changes in United States federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition overall.
The final version of the tax reform bill commonly known as the Tax Cuts and Jobs Act (the "TCJA") signed into law on December 22, 2017 may affect our cash flows, results of operations and financial condition. Among other items, the TCJA repealed the deduction for certain U.S. Production activities and provided for a new limitation on the deduction for interest expense. Given the scope of this law and the potential interdependency of its changes, it is difficult at this time to assess whether the overall effect of the TCJA will be cumulatively positive or negative for our earnings and cash flow, but such changes may adversely impact our financial results.
Certain federal income tax deductions currently available with respect to natural gas and oilOur exploration and development projects require substantial capital expenditures. We may be eliminated asunable to obtain required capital or financing on satisfactory terms, which could lead to a result of future legislation.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Although none of these changes were included in the TCJA, future adverse changes could include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.
We may not be able to keep pace with technological developmentsdecline in our industry.reserves.
The oil and natural gas industry is characterized by rapidcapital intensive. We make and significant technological advancementsexpect to continue to make substantial capital expenditures for the exploitation, development and introductionsacquisition of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas reserves. In 2021, we plan to invest $140 million to $180 million for drilling and completion of operated and non-operated wells. We expect to fund our 2021 capital expenditures with borrowings under our RBL Credit Facility, cash flows from operations and possibly through asset sales or additional capital markets transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Item 7. in Part I of this Annual Report.
A negative shift in investor sentiment of the oil and gas industry could have adverse effects on our ability to raise debt and equity capital and on our operations.
Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.
Additionally, negative public perception regarding us and/or our industry may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business. Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.
Declining general economic, business or industry conditions may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologiesa material adverse effect on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the United States financial market have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.
We may be materiallyunable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations.
Declines in commodity prices may cause the financial markets to exert downward pressure on stock prices and adversely affected.
credit capacity for companies throughout the energy industry. For example, during 2020, the market for senior unsecured notes was unfavorable for high-yield issuers such as us. Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorizedplans for growth may require access to sensitive information,the capital and credit markets,
including the ability to misappropriate financial assetsissue senior unsecured notes. Although the market for high-yield debt securities has experienced periods of improvement in the past, if the high-yield market deteriorates, or if we are unable to render dataaccess alternative means of debt or systems unusable; threatsequity financing on acceptable terms, we may be unable to the security ofimplement our facilitiesdrilling and infrastructuredevelopment plan, make acquisitions or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjectedotherwise carry out our operations to increased risks thatbusiness plan, which could have a material adverse effect on our business. financial condition and results of operations and our ability to service our indebtedness.
Risks Related to Debt
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our existing and future debt arrangements, including the RBL Credit Facility, contain or may contain a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:
•incur additional indebtedness;
•sell assets;
•make loans to others;
•make certain acquisitions and investments;
•enter into mergers, consolidations or other transactions resulting in the transfer of all or substantially all of our assets;
•make certain payments, including paying dividends or distributions in respect of our equity;
•hedge future production or interest rates;
•redeem and prepay other debt;
•incur liens; and
•engage in certain other transactions without the prior consent of the lenders.
In particular,addition, our implementationdebt arrangements require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of various proceduresbusiness opportunities that arise because of the limitations that the restrictive covenants under our debt arrangements will impose on us.
Our RBL Credit Facility limits the amount we can borrow up to the lower of our aggregate lender commitments and controlsa borrowing base amount, which the lenders, in their sole discretion, will determine on a semi-annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The lenders will be able to monitorunilaterally adjust the borrowing base and mitigate security threats andthe borrowings permitted to be outstanding under our RBL Credit Facility. We will be required to repay any outstanding borrowings in excess of the then current borrowing base. Any increase security forin the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders does not agree to a proposed borrowing base, then the borrowing base will be the highest borrowing base acceptable to such lenders. Our borrowing base is currently $500.0 million, subject to the current elected lending commitments of $500.0 million.
A breach of any covenant in our information, facilities and infrastructure mayRBL Credit Facility or any other debt agreement would result in increaseda default after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the facility and a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. In addition, our obligations under our RBL Credit Facility are secured by perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 90% of the reserve value as determined by reserve reports, and if we are unable to repay our indebtedness under the RBL Credit Facility, the lenders could seek to foreclose on our assets.
The borrowing base under our RBL Credit Facility may be reduced in connection with declines in commodity prices, which could hinder or prevent us from meeting our future capital needs.
The borrowing base under our RBL Credit Facility is currently $500.0 million, and operating costs. Moreover, there can be no assurance that such procedurescurrent elected lending commitments under the RBL Credit Facility are $500.0 million. Our borrowing base is redetermined semiannually on each May 1 and controls will be sufficient to prevent security breaches from occurring. If any ofNovember 1 (or once per year between these security breaches weredates) based on certain factors, including our reserves and hedge position, with the next borrowing base redetermination scheduled to occur in May 2021. Our borrowing base may decrease as a result of declines in natural gas, NGLs, and oil prices, or as a result of operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or other reasons. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, we may be unable to meet our obligations as they come due and could leadbe required to lossesrepay any indebtedness in excess of financial assets, sensitive information, critical infrastructurethe redetermined borrowing base. In addition, we may be unable to access the equity or capabilities essentialdebt capital markets, including the market for senior unsecured notes, to meet our operationsobligations. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plan, which could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely affecting our financial condition and results of operations.operations and our ability to service our indebtedness.
LossAvailability, terms and cost of our information and computer systemscapital, increases in interest rates or a reduction in credit rating could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We are dependentrequire continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our RBL Credit Facility, depends on our information systemsfinancial condition and computer-based programs, includingoperating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our well operations information, seismic data, electronic data processing and accounting data.control. If any of such programs or systems were to fail or
create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas prices exhibit weakness for an extended period of time, we may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effectinterest on our business.indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt arrangements may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our RBL Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
Risks Related to our Common Stock
The requirementsWe have restated prior financial statements, which may lead to additional risks and uncertainties, including increased possibility of beinglegal proceedings and loss of investor confidence.
We have restated our condensed consolidated financial statements as of and for the three and nine months ended September 30, 2019 in order to correct an accounting error. As a public company, including compliance with the reporting requirementsresult of the Securities Exchange ActRestatement, we have become subject to possible additional costs for accounting and legal fees in connection with or related to the restatement and additional risks and uncertainties, including, among others, the increased possibility of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements inlegal proceedings, shareholder lawsuits or a timely or cost-effective manner.
We completed our IPO in October 2016. As a public company, we must comply with various laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations ofreview by the SEC and the requirements of the NASDAQ, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We are now required to:
institute a more comprehensive compliance function;
comply with rules promulgated by the NASDAQ;
continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
establish new internal policies, such as those relating to insider trading; and
involve and retain to a greater degree outside counsel and accountants in the above activities.
Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, or if in the future we or our independent registered public accounting firm identifies deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses, the market price of our stock could decline, and we could be subject to sanctions or investigations by the SEC or other regulatory authorities,bodies, which would require additional financial and management resources.
In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. If one or more material weaknesses emerge related to financial reporting, or if we otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and could subject us to civil or criminal penalties, shareholder class actions or derivative actions. We could face monetary judgments,
penalties or other sanctions that could have a material adverse effect on our business, financial condition and results of operations and could cause our stock price to decline.
If we fail to meet the requirements for continued listing on the NASDAQ Global Select Market, our common stock could be delisted, which would likely have a negative effectdecrease the liquidity of our common stock and our ability to raise additional capital.
Our common stock was traded on the NASDAQ under the symbol “XOG” until June 25, 2020. On June 16, 2020, we received a letter from the NASDAQ notifying us that, as a result of the Chapter 11 Cases and in accordance with NASDAQ rules, our securities would be delisted at the opening of business on June 25, 2020. On June 25, 2020, our common stock began to be quoted on the Pink Open Market under the symbol “XOGAQ”. In connection with our emergence from bankruptcy, our common stock was relisted on the NASDAQ Global Select Market on January 21, 2021 trading under the symbol “XOG.”
Our common stock is currently listed for quotation on the NASDAQ Global Select Market. We are required to meet specified requirements to maintain our listing on the NASDAQ Global Select Market, including, among other things, a minimum bid price of $1.00 per share. If we fail to satisfy the NASDAQ Global Select Market’s continued listing requirements, we may be delisted and the quotation of our common stock may be transferred to the OTC Bulletin Board. Having our common stock quoted on the OTC Bulletin Board could adversely affect the liquidity of our common stock. Any such transfer could make it more difficult to dispose of, or obtain accurate quotations for the price of, our common stock.
Yorktown’s funds collectively holdstock, and there also would likely be a substantial portion ofreduction in our coverage by securities analysts and the voting power of our common stock.
Yorktown’s funds currently collectively hold approximately 29% of our common stock. See “Security Ownership of Certain Beneficial Owners and Management” for more information regarding ownership of our common stock bynews media, which could cause the Yorktown funds. The existence of affiliated stockholders with significant aggregate holdings that may act as a group may have the effect
of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, this concentration of stock ownership may adversely affect the trading price of our common stock to the extent investors perceivedecline further. We may also face other material adverse consequences in such event, such as negative publicity, a disadvantage in owning stock of a company with affiliated stockholders with significant aggregate holdings that may act as a group.
Conflicts of interest could arise in the future between us, on the one hand, and Yorktown and its affiliates, including its funds and their respective portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities.
Yorktown’s funds are in the business of making investments in entities in the U.S. energy industry. As a result, Yorktown’s funds may, from timedecreased ability to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. Yorktown’s funds and their respective portfolio companies may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Under our certificate of incorporation, Yorktown’s fundsobtain additional financing, diminished investor and/or one or moreemployee confidence, and the loss of their respective affiliates are permitted to engage in business activities or invest in or acquire businessesdevelopment opportunities, any of which may compete withcontribute to a further decline in our business or do business with any client of ours. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.stock price.
Our amended and restated certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, in addition to the Series A Preferred Stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
•limitations on the removal of directors;
•limitations on the ability of our stockholders to call special meetings;
•establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and
•providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws.
We do notWhen conditions are right and certain requirement have been met, we intend to paybegin paying dividends on our common stock, and ourstock. Our debt arrangements and the Series A Preferred Stock place certain restrictions on our ability to do so. Consequently, it is possible that the only opportunity to achieve a return on an investment in our common stock will be if the price of our common stock appreciates.
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally,future if certain requirements are met as stated in the RBL Credit Agreement. However, our debt arrangements and the Series A Preferred Stock restrict our ability to pay cash dividends.dividends when certain requirements have not been met. Consequently, it is possible that the only opportunity to achieve a return on an investment in our common stock will be if shareholders sell their common stock at a price greater than they paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that such investors paid for our common stock. There is no guarantee we will ever pay dividends.
Future sales of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute the ownership in us by current shareholders.
We may sell additional shares of common stock in public or private offerings. We may also issue additional shares of common stock or convertible securities. Excluding any shares of common stock issued upon the conversion of our Series A Preferred Stock including any shares of Series A Preferred Stock that may be issued pursuant to our option to pay dividends on the Series A Preferred Stock in kind pursuant to the terms of the Certificate of Designations setting forth the terms of the Series A Preferred Stock, weWe have 172,059,81425.7 million outstanding shares of common stock as of December 31, 2017. In connection with the IPO, we filed a registration statement with the SEC on Form S-8 providing for the registration of 23,000,000 shares of our common stock issued or reserved for issuance under our equity incentive plan.March 15, 2021. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction. Additionally, the Series A Preferred Stock are convertible into shares of our common stock pursuant to their terms.
We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
The market price of our securities is subject to volatility.
Upon our emergence from the Chapter 11 Cases, our Predecessor Common Stock was exchanged for New Common Stock (as defined in Note 1 — Business and Organization in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report). The market price of our New Common Stock could be subject to wide fluctuations in response to, and the level of trading that develops with our New Common Stock may issue additional preferredbe affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the lack of comparable historical financial information due to our adoption of fresh-start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A. — Risk Factors section of this Annual Report.
The exercise of all or any number of outstanding warrants, the issuance of stock-based awards or the issuance of our common stock whose terms could adversely affectto settle the voting power or valueclaims of general unsecured claimants may dilute your holding of shares of our common stock.
Our certificate
Upon emergence from bankruptcy on January 20, 2021, we entered into a Tranche A Warrant Agreement and Tranche B Warrant Agreements (each as defined Note 8 — Long-Term Debt in Part II, Item 8. Financial Information of incorporation authorizes usthis Annual Report), pursuant to issue, withoutwhich, as of January 31, 2021, the approvalCompany had approximately 2.9 million and 1.5 million of our stockholders, oneTranche A Warrants and Tranche B Warrants issued and outstanding, respectively. The exercise of equity awards, including any stock options that we may grant in the future, or more classes or seriesthe warrants and any issuance of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, asto general unsecured claimants could dilute your holding of shares of our board of directors may determine. The terms of one or more classes or series of preferredcommon stock, which could have an adverse effect on the market for our common stock, including the Series A Preferred Stock,price that an investor could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.obtain for their shares.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim for a breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Risks Related to Taxes
Recent changes in United States federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition overall.
On March 27, 2020, the U.S. Congress enacted into U.S. federal law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), which, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. In particular, under the CARES Act, (i) NOLs arising in 2018, 2019, and 2020 taxable years may be carried back to each of the preceding five years and offset 100% of taxable income for tax years beginning before 2021, and (ii) for taxable years beginning in 2019 and 2020, the base for interest deductibility is increased. Future regulatory guidance may be forthcoming, and such guidance could ultimately increase or lessen this legislation’s impact on our business and financial condition. It is also possible that Congress will enact additional legislation in connection with COVID-19, some of which could have an impact on the Company.
Certain United States federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Future adverse changes could include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
Our ability to use our NOL carryforwards and other tax attributes may be limited.
Under U.S. federal income tax law, a corporation is generally permitted to deduct from taxable income NOLs carried forward from prior years. We had U.S. federal NOLs of approximately $1.3 billion as of December 31, 2020. However, we expect that we will be required to substantially reduce or eliminate certain of our tax attributes, including NOL carryforwards, as a result of cancellation of indebtedness income realized in connection with the Chapter 11 Cases. Additionally, the consummation of the Plan on the Emergence Date resulted in an “ownership change,” under Section 382 of the Code. Absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its pre-ownership change net operating losses that may be utilized to offset future taxable income generally will be subject to an annual limitation equal to the value of its stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate, plus an additional amount calculated based on certain “built in gains” in its assets that may be deemed to be realized within a 5-year period following any ownership change. This limitation, in the case of the ownership change that occurred as a result of the consummation of the Plan, will be subject to additional rules under Sections 382(l)(5) or (l)(6) of the Code, depending upon whether we are eligible for the application of Section 382(l)(5) of the Code and, if so eligible, whether we affirmatively elect not to apply Section 382(l)(5) of the Code. As a result of such limitation, our ability to utilize any NOLs or other tax attributes that are not eliminated as a result of cancellation of indebtedness income arising from the consummation of the Plan may be materially limited in the future.
Risks Related to Technology
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information, to misappropriate financial assets or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of financial assets, sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely affecting our financial condition and results of operations.
Loss of our information and computer systems could adversely affect our business.
We are dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
Conservation measures and technological advances could reduce demand for oil, natural gas and NGL.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and NGL, technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas and NGL. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Risks Related to the General Business
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.
We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.
We have grown rapidly since we began operations in late 2012. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:
•increased responsibilities for our executive level personnel;
•increased administrative burden;
•increased capital requirements; and
•increased organizational challenges common to large, expansive operations.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the
future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential liabilities, including environmental liabilities. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of oil and gas properties or businesses that complement or expand our current business. The successful acquisition of oil and gas properties requires an assessment of several factors, including:
•recoverable reserves;
•future oil, natural gas and NGL prices and their applicable differentials;
•operating costs; and
•potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, our debt arrangements will impose certain limitations on our ability to enter into mergers or combination transactions. Our debt arrangements will also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.
We may be subject to risks in connection with divestitures
In 2020, we announced our ongoing initiative to divest of non-strategic assets in order to increase capital resources available for other core assets, create organizational and operational efficiencies or for other purposes and completed divestitures of several of our non-strategic assets and we have additional divestitures pending, as discussed in “Business and Properties —Recent Developments.” Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties and the availability of purchases willing to acquire the assets with terms we deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance that this evaluation will result in any specific further action.
Sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
Our cash flow from operations and access to capital are subject to a number of variables, including:
•our proved reserves;
•the level of hydrocarbons we are able to produce from existing wells;
•the prices at which our production is sold;
•the availability of takeaway capacity;
•our ability to acquire, locate and produce new reserves; and
•our ability to borrow under our RBL Credit Facility.
If our revenues or the borrowing base under our RBL Credit Facility decreases as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our RBL Credit Facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition and results of operations.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and a failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our business, financial condition, results of operations or cash flows.
Our future growth prospects are dependent upon our ability to identify optimal strategies for investing our capital resources to produce rates of return. In developing our business plan, we consider allocating capital and other resources to various aspects of our business including well development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also consider our likely sources of capital, including cash generated from operations and borrowings under our credit agreement. Notwithstanding the determinations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and future growth may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, natural gas and NGL, we enter into commodity derivative contracts for a significant portion of our production, primarily consisting of swaps, put options and call options. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Sources of Our Revenues” in Part II, Item 7. of this Annual Report. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
•production is less than the volume covered by the derivative instruments;
•the counterparty to the derivative instrument defaults on its contractual obligations;
•there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
•there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, natural gas and NGL prices and
interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas and NGL, which could also have an adverse effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. While we utilize multiple counterparties, if the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.
Approximately 46% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
As of December 31, 2020, approximately 46% of our net leasehold acreage was undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
We are required to pay fees to our service providers based on minimum volumes under long-term contracts regardless of actual volume throughput.
We may enter into firm transportation, gas processing, gathering and compression service, water handling and treatment, or other agreements that require minimum volume delivery commitments. If we have insufficient production to meet the minimum volumes under these agreements or any other firm commitment agreement we may enter into, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results or operations.
In February 2019, we entered into a long-term gas gathering and processing agreements with a third-party midstream provider. The agreement commenced on January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten. The agreement also includes a commitment to sell take-in-kind NGLs of 4,000 Bbl/d in year one, 7,500 Bbl/d in years two through seven with the ability to roll up to a 10% shortfall in a given month to the subsequent month. On December 23, 2020, we entered into a settlement with the counterparty and amended the agreement. As part of the settlement and amended agreement, there were no changes made to the minimum volume commitments. We may be required to pay a shortfall fee for any volume deficiencies under these commitments, calculated based on the applicable gathering and processing fees and/or, with respect to the NGL commitment, the NGL transport cost.
If we are unable to meet our commitments under the Elevation Gathering Agreements, we may incur additional costs.
If we are unable to meet our commitments under the Elevation Gathering Agreements, we may be required to incur additional costs. For example, if we fail to complete wells by the commitment deadline, we would be deemed to be in breach of the agreements and Elevation would be entitled to make a claim for damages against us and our affiliates.
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. 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 other working interest 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, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.
We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to control the operation and profitability of such properties.
We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.
As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGL we produce.
The availability of a ready market for any oil, natural gas and NGL we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See “Business and Properties—Operations—Marketing and Customers.” We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.
The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.
We have exposure to credit risk through receivables from purchasers of our oil, natural gas and NGL production. Three, one and two purchasers accounted for more than 10% of our revenues in the years ended December 31, 2020, 2019 and 2018, respectively. During 2021, we no longer sell to our largest and third largest purchasers in 2020. Rather, we have increased our sales to our second largest purchaser in 2020 and began selling to a new midstream oil marketer who has replaced our largest purchaser in 2020. This concentration of purchasers may impact our overall credit risk in that these entities may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. The inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and natural 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 lease brokers or land men who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we do 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.
Competition in the oil and natural gas industry and from alternative energy sources is intense, making it more difficult for us to acquire properties and market oil or natural gas.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business.
We also face indirect competition from alternative energy sources, including wind, solar, nuclear and electric power. The proliferation of alternative energy sources and businesses that provide such alternative energy sources may decrease the demand for oil and natural gas products. Decreased demand for our products could adversely affect our business, financial condition, results of operations or cash flows.
Climate change legislation or regulations restricting emissions of GHG could result in increased operating costs and reduced demand for the oil, natural gas and NGL that we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. Additionally, growing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has adopted rules under authority of the CAA that, among other things, establish PSD construction and Title V permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal pollutant emissions, which reviews could require meeting “best available control technology” standards for those emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among other things, onshore producing facilities, which include certain of our operations. Federal agencies also have begun directly regulating emissions of methane from oil and natural gas operations, with the EPA publishing NSPS Subpart OOOOa standards in June 2016 that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions and the BLM publishing requirements in November 2016 to reduce methane emissions from venting, flaring, and leaking on public lands. Both of the EPA and BLM took steps to relax or rescind certain requirements under their respective methane rules. In September 2019, EPA published proposed amendments that would rescind the methane standards and roll back other requirements of the NSPS OOOOa standards and, in September 2018, BLM issued a rule that relaxes or rescinds requirements of its November 2016 regulations. California and New Mexico have challenged BLM’s September 2018 rule in ongoing litigation. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement and on November 4, 2019, the U.S. submitted formal notification of its withdrawal to the United Nations. However, during the first part of 2021, the United States, under a new presidential administration, rejoined the Paris Agreement.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHG or otherwise limit emissions of GHG from, our equipment and operations could result in increased costs to reduce emissions of GHG associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil, natural gas and NGL we produce and lower the value of our reserves, which devaluation could be significant. One or more of these developments could have a materially adverse effect on our business, financial condition and results of operations. Finally, notwithstanding potential risks related to climate change, the International Energy Agency, an autonomous intergovernmental organization involved in international energy policy, estimates that global energy demand will continue to rise and will not peak until after 2040 and oil and gas will continue to represent a substantial percentage of global energy use over that time. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Please read “Business and Properties—Regulation of Environmental and Safety and Health Matters—Regulation of Greenhouse Gas (“GHG”) Emissions” for a further description of the laws and regulations relating to climate change that affect us.
Adverse weather conditions may negatively affect our ability to conduct drilling activities and our operating results.
Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, lost or damaged facilities and equipment, power failures, and temporary shut-in of production. Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party services,
such as gathering, processing, compression and transportation services. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.
Risks Related to the COVID-19 Pandemic
Outbreaks of communicable diseases, including the COVID-19 pandemic, could adversely affect our business, financial condition, results of operations and cash flows.
Global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and, therefore, demand and pricing for oil and natural gas products. For example, there have been recent outbreaks in many countries, including the United States, of a highly transmissible and pathogenic coronavirus, which the World Health Organization declared a pandemic in March 2020. The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products. Furthermore, uncertainty regarding the impact and length of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices. The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute on our business plan, which could adversely affect our business, financial condition, results of operations and cash flows.
Additionally, in response to the COVID-19 pandemic, our corporate staff has begun working remotely and many of our key vendors, service suppliers and partners have similarly begun to work remotely. As a result of such remote work arrangements, certain operational, reporting, accounting and other processes may slow, which could result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies. Also, in the event that there is an outbreak of COVID-19 at any of our operating locations, we could be forced to cease operations at such location. Any of the foregoing could adversely affect our business, financial condition, results of operations and cash flows.
The ongoing COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries may result in transportation and storage constraints, reduced production and shut-in of our wells, any of which would adversely affect our business, financial condition and results of operations.
The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. We experienced substantial decreases in our revenues beginning in the first quarter of 2020 and lasting through the end of the year, which negatively impacted our business, financial condition, results of operations, cash flows and outlook during 2020. Due to the commodity price environment, we postponed or eliminated a portion of our developmental drilling in 2020. A sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, have required us to reevaluate and further postpone or eliminate additional drilling. Such actions resulted in the reduction of our PUDs and related PV-10 and a reduction in our ability to service our debt obligations. More recently, however, reduction in oil and gas activity as a result of the COVID-19 pandemic has resulted in a decrease of production as fewer oil wells are drilled, which has led to a contraction in domestic oil and gas supply. Lower levels of supply have pushed current and forecasted oil and gas prices higher, which we expect to have a positive impact on our results of operations and cash flows. To the extent, however, that the outbreak of COVID-19 continues to negatively impact demand and we are required to further curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices remain weak, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.
Risks Related to Bankruptcy
We recently emerged from bankruptcy, which may adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our recent emergence from the voluntary cases under chapter 11 of the Bankruptcy Code may adversely affect our business and relationships with customers, vendors, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:
•key suppliers, vendors or other contract counterparties may terminate their relationships with us, require additional financial assurances or enhanced performance from us or pursue unreasonable fee increases for their goods or services;
•our ability to renew existing contracts and compete for new business may be adversely affected;
•our ability to attract, motivate and/or retain key employees and executives may be adversely affected;
•landowners may not be willing to lease acreage to us; and
•competitors may take business away from us and our ability to attract and retain customers may be negatively impacted.
The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
Our historical financial information may not be indicative of future financial performance.
Our capital structure was significantly impacted by the Plan. Under fresh-start accounting rules that applied to us upon the Emergence Date, assets and liabilities were adjusted to fair values. Accordingly, because fresh-start accounting rules applied, our financial condition and results of operations following emergence from the Chapter 11 Cases will not be comparable to the financial condition and results of operations reflected in our historical financial statements.
Upon our emergence from the Chapter 11 Cases, the composition of our board of directors changed significantly.
Pursuant to the Plan, the composition of our board of directors changed significantly. Upon emergence, our Board consists of seven directors, none of whom served on the Board prior to our emergence from the Chapter 11 Cases. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on our Board and, thus, may have different views on the issues that will determine our future. There is no guarantee that our new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and our plans may differ materially from those of the past.
The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from the Chapter 11 Cases.
The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from the Chapter 11 Cases, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.
We may be negatively impacted by litigation and legal proceedings, including ongoing claims in connection with the Chapter 11 Cases.
We are subject from time to time, and in the future may become subject, to litigation claims. These claims and legal proceedings are typically claims that arise in the normal course of business and include, without limitation, claims relating to environmental, safety and health matters, commercial or contractual disputes with suppliers and customers, claims regarding ownership of mineral interests, including from royalty owners, claims regarding acquisitions and divestitures, regulatory matters and employment and labor matters. We may also become subject to governmental or regulatory proceedings. The outcome of such claims and legal proceedings cannot be predicted with certainty and some may be disposed of unfavorably to us. In addition, the claims resolutions process in connection with the Chapter 11 Cases is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court. The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose before confirmation of the Plan (i) would be subject to compromise and/or treatment under the Plan and/or (ii) would be discharged in accordance with the terms of the Plan. Any claims not ultimately discharged through the Plan could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis. To the extent that these legal proceedings result in claims being allowed against us, such claims will be satisfied through the issuance of shares of our common stock, except as noted herein. As a result, we have not established reserves within our liabilities in connection with these claims. However, it is possible with respect to certain claims that the ultimate outcome of the legal proceedings may result in the contracts not being treated as rejected or the amounts at issue being treated as administrative claims by the Bankruptcy Court, either of which could require us to make cash payments to resolve claims instead of issuing shares of our common stock or require us to establish reserves and accrue liabilities with respect to such claims at a future date. We also may not have insurance that covers such claims and legal proceedings. Successful claims or litigation against us for significant amounts could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flows. Further, even if successful in resolving a claim or legal proceeding, such process could require the attention of members of our senior management, reducing the time they have available to devote to managing our business, and require us to incur substantial legal expenses.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Exchange Act.Act of 1934, as amended (the “Exchange Act”).
ITEM 3. LEGAL PROCEEDINGS
FromWe are involved in various legal proceedings and 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. Although the results cannot be known with certainty, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows.
We were issued a Compliance Advisory in July 2015 from the Colorado Department of Public Health and Environment (“CDPHE”), which alleged air quality violations at certain of our facilities regarding leakages of volatile organic
compounds from storage tanks, all of which were promptly addressed. On January 31, 2018, we entered into a Compliance Order on Consent with the CDPHE that provides for a field-wide administrative settlement of these issues.
The Compliance Order provides that we will implement changes to our design, operation, maintenance and recordkeeping of many of our field-wide storage tank systems to enhance our emissions management. Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation and operation of certain emission mitigation projects at certain facilities constructed in 2018 and 2019. The two primary elements of the Compliance Order are: (i) a monetary penalty of $138,600; and (ii) injunctive relief with an estimated cost of approximately $500,000, primarily representing capital enhancements to our operations. Certain expenditures for the injunctive relief have already been incurred prior to entry of the Compliance Order, with the remainder expected to be incurred over the next few years. We do notcurrently believe that the expenditures resulting from the settlementultimate results of such proceedings will not have a material adverse effect on our business, financial position, results of operations or liquidity.
COGCC Notices of Alleged Violations (“NOAVs”). We have received NOAVs from the COGCC for alleged compliance violations that we have responded to. We do not believe penalties that could result from these NOAVs will have a material effect on our business, financial condition, results of operations or liquidity, but Extraction is in negotiations to settle all of its outstanding NOAVs with the COGCC, and the ultimate settlement amount is expected to exceed $600,000.
The information set forth in Note 16 — Commitments and Contingencies — Litigation and Legal Items, to the accompanying consolidated financial statements.statements included in this Annual Report on Form 10-K is incorporated by reference into this Item 3.
For information on the Chapter 11 Cases, see Items 1. and 2. — Business and Properties — Recent Developments — Chapter 11 Cases which information is incorporated herein by reference.
ITEM 4.MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information.
Our common stock is currently traded on the NASDAQ under the ticker symbol “XOG.” The following table presents
NASDAQ Delisting and Relisting
Our common stock was traded on the rangeNASDAQ under the symbol “XOG” until June 25, 2020. On June 16, 2020, we received a letter from the NASDAQ notifying us that, as a result of highthe Chapter 11 Cases and low intraday sales prices per share forin accordance with NASDAQ rules, our securities would be delisted at the indicated periods, as reported by NASDAQ:
|
| | | | | | | | |
| | | High | | Low |
| Fiscal Year Ended December 31, 2017 | | | | |
| Fourth quarter (ended December 31, 2017) | | $ | 16.57 |
| | $ | 14.31 |
|
| Third quarter (ended September 30, 2017) | | $ | 15.39 |
| | $ | 11.38 |
|
| Second quarter (ended June 30, 2017) | | $ | 18.65 |
| | $ | 12.96 |
|
| First quarter (ended March 31, 2017) | | $ | 19.96 |
| | $ | 15.30 |
|
| Fiscal Year Ended December 31, 2016 | | | | |
| From October 12, 2016 to December 31, 2016 | | $ | 25.08 |
| | $ | 19.10 |
|
Dividend Policy
We have not historically paid and do not anticipate paying any cash dividends in the future, to common stockholdersholders of our common stock. In addition, our revolving credit facility, our Senior Notes (collectively, our “debt arrangements”) and the Series A Preferred Stock place certain restrictions on our ability to pay cash dividends. Please see Note 5 — Long Term Debt included in the notes to the consolidated financial statements included elsewhere in this Annual Report for more information regarding the restrictions placed on our ability to pay cash dividends.
Comparison of Cumulative Return
The following graph compares the cumulative total shareholder return on a $100 investment in our common stock on October 12, 2016 through December 31, 2017, to that of the cumulative return on a $100 investment in the S&P 500 Composite for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. The indices are included for comparative purpose only. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.
Holders
Pursuant to the records of the transfer agent, as of February 23, 2018,March 15, 2021 the number of holders of record of our common stock was 68.233.
Sales of Unregistered Securities
We did not have any sales of unregistered securities during the fiscal year ended December 31, 2017.2020.
Issuer Purchases of Equity Securities
In July 2017, we purchased 165,385 common shares, with an averageWe did not have any share price of $12.73, in order for employees to satisfy tax withholding payments related to incentive restricted stock unit awards that vestedrepurchase activity during the period. There were no purchases of equity securities during the fourth quarter of 2017.three months ended December 31, 2020.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data asinformation responsive to Item 301 of and for the five-years ended December 31, 2017. The data asRegulation S-K is not required of and for the fiscal years ended December 31 for each respective year was derived from our historical consolidated financial statements and the accompanying notes included elsewhere in this Annual Report.smaller reporting companies.
The following selected consolidated financial information should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations” and the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data” presented elsewhere in this Annual Report for further discussion of the factors affecting the comparability of the Company’s financial data. Also see “Recent Accounting Pronouncements” included in the notes to the consolidated financial statements included elsewhere in this Annual Report.
|
| | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (in thousands, except per share data) |
| Revenues: | | | | | | | | | |
| Oil sales | $ | 419,904 |
| | $ | 194,059 |
| | $ | 157,024 |
| | $ | 75,460 |
| | $ | 2,025 |
|
| Natural gas sales | 92,322 |
| | 48,652 |
| | 26,019 |
| | 9,247 |
| | 299 |
|
| NGL sales | 92,070 |
| | 35,378 |
| | 14,707 |
| | 8,133 |
| | 30 |
|
| Total Revenues | 604,296 |
| | 278,089 |
| | 197,750 |
| | 92,840 |
| | 2,354 |
|
| Operating Expenses: | |
| | |
| | |
| | | | |
| Lease operating expenses | 111,306 |
| | 62,043 |
| | 30,628 |
| | 5,067 |
| | 56 |
|
| Production taxes | 51,367 |
| | 20,730 |
| | 17,035 |
| | 9,743 |
| | 235 |
|
| Exploration expenses | 36,256 |
| | 36,422 |
| | 18,636 |
| | 126 |
| | 313 |
|
| Depletion, depreciation, amortization and accretion | 314,999 |
| | 205,348 |
| | 146,547 |
| | 34,042 |
| | 396 |
|
| Impairment of long lived assets | 1,647 |
| | 23,425 |
| | 15,778 |
| | — |
| | — |
|
| Other operating expenses | 451 |
| | 10,891 |
| | 2,353 |
| | — |
| | — |
|
| Acquisition transaction expenses | — |
| | 2,719 |
| | 6,000 |
| | — |
| | — |
|
| General and administrative expenses | 110,167 |
| | 232,388 |
| | 37,149 |
| | 19,598 |
| | 1,510 |
|
| Total Operating Expenses | 626,193 |
| | 593,966 |
| | 274,126 |
| | 68,576 |
| | 2,510 |
|
| Operating Income (Loss) | (21,897 | ) | | (315,877 | ) | | (76,376 | ) | | 24,264 |
| | (156 | ) |
| Other Income (Expense): | |
| | |
| | |
| | | | |
| Commodity derivatives gain (loss) | (36,332 | ) | | (100,947 | ) | | 79,932 |
| | 48,008 |
| | — |
|
| Interest expense | (51,889 | ) | | (68,843 | ) | | (51,030 | ) | | (22,454 | ) | | (10 | ) |
| Other income | 2,010 |
| | 386 |
| | 210 |
| | 24 |
| | 366 |
|
| Total Other Income (Expense) | (86,211 | ) | | (169,404 | ) | | 29,112 |
| | 25,578 |
| | 356 |
|
| Net Income (Loss) Before Income Taxes | (108,108 | ) | | (485,281 | ) | | (47,264 | ) | | 49,842 |
| | 200 |
|
Income Tax Benefit: (1) | 63,700 |
| | 29,280 |
| | — |
| | — |
| | — |
|
| Net Income (Loss) | $ | (44,408 | ) | | $ | (456,001 | ) | | $ | (47,264 | ) | | $ | 49,842 |
| | $ | 200 |
|
Loss Per Common Share (2) | |
| | |
| | |
| | | | |
| Basic and diluted | $ | (0.35 | ) | | $ | (1.54 | ) | | |
| | | | |
| Total Production Volumes: | | | | | | | | | |
| Oil (MBbls) | 9,594 |
| | 5,287 |
| | 3,946 |
| | 1,022 |
| | 23 |
|
| Natural Gas (MMcf) | 32,395 |
| | 20,212 |
| | 10,823 |
| | 2,664 |
| | 61 |
|
| NGL (MBbls) | 3,901 |
| | 2,284 |
| | 1,335 |
| | 325 |
| | 1 |
|
| Total (MBOE) | 18,894 |
| | 10,940 |
| | 7,084 |
| | 1,792 |
| | 34 |
|
| Average net sales (BOE/d) | 51,764 |
| | 29,891 |
| | 19,408 |
| | 4,908 |
| | 93 |
|
| Proved Reserves: | |
| | |
| | |
| | | | |
| Oil (MBbls) | 111,275 |
| | 90,995 |
| | 71,500 |
| | 45,165 |
| | 124 |
|
| Natural Gas (MMcf) | 626,169 |
| | 507,735 |
| | 292,584 |
| | 166,416 |
| | 673 |
|
| NGL (MBbls) | 77,106 |
| | 62,448 |
| | 38,383 |
| | 19,451 |
| | 89 |
|
| Total (MBOE) | 292,743 |
| | 238,066 |
| | 158,647 |
| | 92,352 |
| | 325 |
|
Selected consolidated financial information continued:
|
| | | | | | | | | | | | | | | | | | | |
| | As of and for the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| Consolidated Cash Flow Information: | | | | | | | | | |
| Net cash provided by (used in) operating activities | $ | 316,965 |
| | $ | 116,388 |
| | $ | 166,683 |
| | $ | 77,390 |
| | $ | (840 | ) |
| Net cash used in investing activities | $ | (1,362,328 | ) | | $ | (915,808 | ) | | $ | (520,006 | ) | | $ | (970,640 | ) | | $ | (23,374 | ) |
| Net cash provided by financing activities | $ | 463,395 |
| | $ | 1,291,050 |
| | $ | 371,404 |
| | $ | 972,090 |
| | $ | 23,407 |
|
| Consolidated Balance Sheet Information: | | | | | | | | | |
| Total Assets | $ | 3,384,669 |
| | $ | 2,784,776 |
| | $ | 1,634,140 |
| | $ | 1,201,069 |
| | $ | 28,938 |
|
| Long-term Debt | $ | 1,023,361 |
| | $ | 538,141 |
| | $ | 637,790 |
| | $ | 508,903 |
| | $ | 23,672 |
|
| Series A Preferred Stock | $ | 158,383 |
| | $ | 153,139 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Total Equity | $ | 1,616,765 |
| | $ | 1,616,073 |
| | $ | 754,232 |
| | $ | 545,188 |
| | $ | 1,362 |
|
Other Financial Data (3): | | | | | | | | | |
| Adjusted EBITDAX | $ | 380,462 |
| | $ | 192,265 |
| | $ | 176,120 |
| | $ | 66,892 |
| | $ | 919 |
|
| |
(1) | Extraction Oil & Gas, Inc. is a subchapter C corporation (“C-Corp”) under the Internal Revenue Code of 1986, as amended (the "Code"), and is subject to federal and State of Colorado income taxes. Our predecessor, Extraction Oil & Gas Holdings, LLC was not subject to U.S. federal income taxes. As a result, the consolidated net income (loss) in our historical financial statements for periods prior to our October 12, 2016 corporate reorganization to a C-Corp does not reflect the tax expense we would have incurred as a C-Corp during such periods. |
| |
(2) | See Note 9 — Equity and Note 12 — Earnings (Loss) Per Share in our consolidated financial statements, included herein, for additional discussion regarding the calculation of loss per share for 2016.
|
| |
(3) | Adjusted EBITDAX is a non-GAAP financial measure. Management defines Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items, including depreciation, depletion, amortization and accretion ("DD&A"), impairment of long lived assets, exploration expenses, rig termination fees, acquisition transaction expenses, commodity derivative (gain) loss, settlements on commodity derivatives, premiums paid for derivatives that settled during the period, unit and stock-based compensation expense, amortization of debt discount and debt issuance costs, interest expense, income taxes and non-recurring charges. See Part II, Item & - Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report for additional disclosures related to Adjusted EBITDAX. |
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes appearing in “Item 8. Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
This section of this Form 10-K generally discusses 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Form 10-K and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2019 and are incorporated herein by reference.
OVERVIEW
We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reservesreserve in the Rocky Mountain region, primarily in the Wattenberg Field of the DJ Basin.Denver-Julesburg Basin (the “DJ Basin”) of Colorado. We have developed an oil, natural gas and NGL asset base of proved reserves, as well as a portfolio of development drilling opportunities on high resource-potential leasehold on contiguous acreage blocks in some of the most productive areas of what we consider to be the core of the DJ Basin. We are focused on growing our proved reserves
Our Properties and production primarily through the development of our large inventory of identified liquids-rich horizontal drilling locations.Operations
Our Properties
We have assembled, as of December 31, 2017,2020, approximately 171,400140,000 net acres of large, contiguous acreage blocks in some of the most productive areas of what we consider to be the core of the DJ Basin as indicated by the results of our horizontal drilling program and the results of offset operators. Additionally, we hold approximately 183,30096,700 net acres outside of what we consider our Core DJ Basin, which we refer to as our “Other Rockies Area,” that we believe is prospective forhas many of the same formations as our properties in the Core DJ Basin. We operated 94%99% of our horizontal production for the year ended December 31, 2017,2020, our total estimated proved reserves were approximately 292.7145.9 MMBoe, of which approximately 35%77% were classified as proved developed reserves. For more information about our properties, please read “Business—Items 1. and 2. Business and Properties — Our Properties.”Properties in Part 1 of this Annual Report.
Deconsolidation of Elevation Midstream, LLC
Please see Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for information related to the deconsolidation of Elevation Midstream, LLC.
Financial Overview
For the year ended December 31, 2017,2020, we had a net loss of $44.4 million$1.3 billion as compared to a net loss of $456.0 million$1.4 billion for the year ended December 31, 2016.2019. The decrease in net loss was primarily driven by an increase in production revenue of $326.2 million and a decrease in non-cash compensation expense primarily relatedoperating expenses of $1.1 billion, which includes a decrease of $1.1 billion in the impairment of long-lived assets, and a change from a loss to the IPO in 2016a gain on commodity derivatives of $134.7 million, partially$202.1 million. These were offset by an increasea decrease in depletion, depreciation, amortizationsales revenues of $348.7 million, $676.9 million in reorganization items which did not exist in 2019, and accretiona $73.1 million loss on deconsolidation of Elevation Midstream, LLC which also did not exist in 2019. Additionally, interest expense of $109.7 million, associated with an increase in production volumes.decreased $22.1 million.
For the year ended December 31, 2017,2020, crude oil, natural gas, and NGL sales and gathering and compression revenue, coupled with the impact of settled derivatives, increaseddecreased to $585.7$650.7 million as compared to $306.7$881.9 million in the same prior year period due to an increase in sales volumesa decrease of 7,954 MBoe and an increase of $2.96$7.24 in realized price per BOE, including settled derivatives.derivatives, offset by an increase in sales volumes
of approximately 155 MBoe. During June 2020, we unwound the majority of our hedges when we filed for bankruptcy and received aggregate settlement proceeds of $96.1 million.
Adjusted EBITDAX was $380.5$449.2 million for the year ended December 31, 2017,2020, as compared to $192.3$610.7 million in the same period in 2016,2019, reflecting a 98% increase.26% decrease. Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Adjusted EBITDAX.”
Operational Overview
During the year ended December 31, 2017,2020, we continued to focusfocused on growing production while at the same time implementingemerging from bankruptcy, improving free cash flow and implemented operational efficiencies to reduce drilling, completion and completionoperating costs. We incurred approximately $864.5$159.6 million excluding outstanding elections, in drilling 18637 gross (137.4(25.7 net) wells with an average lateral length of 1.72.3 miles and completing 19845 gross (158.9(34.1 net) wells with an average lateral length of 1.72.4 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred approximately $73.2$16.9 million of leasehold and surface acreage additions, excluding acquisitions,additions.
How We Evaluate Our Operations
We use various financial and approximately $10.9 millionoperational metrics to assess the performance of midstream additions, excludingour oil and gas operations, including:
•Sources of revenue;
•Sales volumes;
•Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative contracts;
•Lease operating expenses (“LOE”);
•Capital expenditures;
•Adjusted EBITDAX (a Non-GAAP measure); and
•Free cash flow (a Non-GAAP measure).
Sources of Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGL that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives. For the year ended December 31, 2020, our revenues were derived 69% from oil sales, 17% from natural gas sales and 14% from NGL sales. For the year ended December 31, 2019, our revenues were derived 80% from oil sales, 12% from natural gas sales and 8% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
Sales Volumes
The following table presents historical sales volumes for the periods indicated:
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2020 | | 2019 |
| Oil (MBbl) | 12,543 | | | 15,436 | |
| Natural gas (MMcf) | 72,311 | | | 64,710 | |
| NGL (MBbl) | 7,945 | | | 6,164 | |
| Total (MBoe) | 32,540 | | | 32,385 | |
| Average net sales (BOE/d) | 88,907 | | | 88,728 | |
As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic growth as well as acquisitions. Our 2018ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, budget anticipatesobtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read Item 1A. Risk Factors — Risks Related to the Oil, Natural Gas and NGL Industry and Our Business in Part 1 of this Annual Report for a two to three operated rig drilling program. further description of the risks that affect us.
Realized Prices on the Sale of Oil, Natural Gas and NGL
Recent AcquisitionsOur results of operations depend upon many factors, particularly the price of oil, natural gas and Divestitures
Asset Divestitures
To date, we have received multiple agreementsNGL and our ability to divest various propertiesmarket our production effectively. Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For example, during the period from January 1, 2014 to December 31, 2020, NYMEX West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of negative $37.63 per Bbl. Average daily prices for approximately $70.0 million.NYMEX Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.48 per MMBtu during the same period. Declines in, and continued depression of, the price of oil and natural gas occurring during 2015, 2019 and 2020 are due to a combination of factors including increased U.S. supply, global economic concerns stemming from COVID-19 and the price war between Russia and Saudi Arabia. These sales are not expected toprice variations can have a material impact on our financial results and capital expenditures.
Oil pricing is predominantly driven by the physical market, supply and demand, financial markets and national and international politics. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. In the DJ Basin, oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials.
Natural gas prices vary by region and locality, depending upon the distance to our previously announced 2018 guidancemarkets, availability of pipeline capacity and are projected to close during the second quartersupply and demand relationships in that region or locality. The NYMEX Henry Hub price of 2018.
November 2017 Acquisition
On November 15, 2017, we acquired an unaffiliated oil andnatural gas company's interest in approximately 36,600 net acres of leasehold and primarily non-producing properties located in Arapahoe County, Colorado, (the "November 2017 Acquisition"). Upon closing the seller received $214.3 million in cash, subject to customary purchase price adjustments. We also recordedis a liability of $12.2 millionwidely used benchmark for the final settlement payment duepricing of natural gas in April 2018the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGL. Location differentials to NYMEX Henry Hub prices result from variances in conjunction withtransportation costs based on the November 2017 Acquisitionnatural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant, generally in the form of percentage of proceeds. The price we receive for total consideration of $226.5 million. The acquisition provides new development opportunitiesour natural gas produced in the DJ Basin.
July 2017 AcquisitionBasin is based on CIG prices, adjusted for certain deductions.
On July 7, 2017, we acquired an unaffiliatedOur price for NGL produced in the DJ Basin is based on a combination of prices from the Conway hub in Kansas and Mont Belvieu in Texas where this production is marketed.
The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil, natural gas and gas company’s interest in approximately 12,500 net acres of leaseholdNGL normally sells at a discount to the NYMEX WTI and primarily non-producing properties located in Adams County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systemsNYMEX Henry Hub price, as applicable.
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2020 | | 2019 |
| Oil | | | |
| NYMEX WTI High ($/Bbl) | $ | 63.27 | | | $ | 66.30 | |
| NYMEX WTI Low ($/Bbl) | $ | (37.63) | | | $ | 46.54 | |
| NYMEX WTI Average ($/Bbl) | $ | 39.34 | | | $ | 57.04 | |
| Average Realized Price ($/Bbl) (1) | $ | 30.50 | | | $ | 46.74 | |
| Average Realized Price, with derivative settlements ($/Bbl) (1) | $ | 37.15 | | | $ | 45.16 | |
| Average Realized Price as a % of Average NYMEX WTI | 77.5 | % | | 81.9 | % |
| Differential ($/Bbl) to Average NYMEX WTI (2) | $ | (7.92) | | | $ | (8.71) | |
| Natural Gas | | | |
| NYMEX Henry Hub High ($/MMBtu) | $ | 3.35 | | | $ | 3.59 | |
| NYMEX Henry Hub Low ($/MMBtu) | $ | 1.48 | | | $ | 2.07 | |
| NYMEX Henry Hub Average ($/MMBtu) (3) | $ | 2.34 | | | $ | 2.78 | |
| Average Realized Price ($/Mcf) | $ | 1.34 | | | $ | 1.68 | |
| Average Realized Price, with derivative settlements ($/Mcf) | $ | 1.47 | | | $ | 1.68 | |
| Average Realized Price as a % of Average NYMEX Henry Hub (3) | 57.3 | % | | 60.4 | % |
| Differential ($/Mcf) to Average NYMEX Henry Hub (3) | $ | (1.00) | | | $ | (1.10) | |
| NGL | | | |
| Average Realized Price ($/Bbl) | $ | 9.72 | | | $ | 12.18 | |
| Average Realized Price as a % of Average NYMEX WTI | 24.7 | % | | 21.4 | % |
(1)Includes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the years ended December 31, 2020, and other assets. Upon closing the seller received total consideration of $84.0 million in cash.December 31, 2019, pursuant to ASC 606, Revenue Recognition.
June 2017 Acquisition
On June 8, 2017, we acquired an unaffiliated(2)Excludes non-cash amounts allocated to a satisfied performance obligation, recognized within oil and gas company's interests in producing properties located in Weld County, Colorado. The acquisition increased our interest in existing operated wells. We paid approximately $13.4 million in cash consideration in connection with the closing of the acquisition. The acquired interest contributed $3.7 million of revenue and $3.0 million of earningssales for the year ended December 31, 2017.2020, and December 31, 2019, pursuant to ASC 606, Revenue Recognition.
(3)Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf using a conversion factor of 1.1 to 1.
Derivative Arrangements
AmendmentsTo achieve more predictable cash flow and to Revolvingreduce our exposure to adverse fluctuations in commodity prices, from time to time, we enter into derivative arrangements for our oil and natural gas production. By removing a significant portion of price volatility associated with our oil and natural gas production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our derivatives contract prices are higher than market prices. In certain circumstances we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts.
We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We have relied on a variety of hedging strategies and instruments to hedge our future price risk. We have utilized swaps, put options and call options, which in some instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas production. We expect to continue to use a variety of hedging strategies and instruments for the foreseeable future.
The hedge prices will depend on the commodity price environment at the time those hedge transactions are entered into. Our ability to enter into derivative arrangements at favorable prices may be limited, and, under our RBL Credit Agreement (as defined in Note 8—Long-Term Debt in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report), we are obligated to hedge a specific portion of our oil or natural gas production. The RBL Credit Agreement requires us to maintain commodity hedges covering a minimum of 65% of our anticipated oil and gas production from PDP reserves for the succeeding twelve months and 50% of our anticipated oil and gas production from PDP reserves for the next succeeding twelve months.
For a description of our derivative instruments that we utilize and a summary of our open commodity derivative contracts as of December 31, 2020, please see Note 9 — Commodity Derivative Instruments in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated.
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 |
| NYMEX WTI Crude Swaps: | | | |
| Notional volume (Bbl) | 4,316,000 | | | 9,830,000 | |
| Weighted average fixed price ($/Bbl) | $ | 49.16 | | | $ | 53.08 | |
| NYMEX WTI Crude Purchased Puts: | | | |
| Notional volume (Bbl) | 4,950,000 | | | 22,050,000 | |
| Weighted average purchased put price ($/Bbl) | $ | 54.48 | | | $ | 46.87 | |
| NYMEX WTI Crude Purchased Calls: | | | |
| Notional volume (Bbl) | 1,100,000 | | | 18,350,000 | |
| Weighted average purchased call price ($/Bbl) | $ | 68.04 | | | $ | 65.74 | |
| NYMEX WTI Crude Sold Calls: | | | |
| Notional volume (Bbl) | 5,650,000 | | | 22,300,000 | |
| Weighted average sold call price ($/Bbl) | $ | 63.37 | | | $ | 64.57 | |
| NYMEX WTI Crude Sold Puts: | | | |
| Notional volume (Bbl) | 5,300,000 | | | 22,350,000 | |
| Weighted average sold put price ($/Bbl) | $ | 44.39 | | | $ | 45.11 | |
| NYMEX HH Natural Gas Swaps: | | | |
| Notional volume (MMBtu) | 31,000,000 | | | 32,400,000 | |
| Weighted average fixed price ($/MMBtu) | $ | 2.66 | | | $ | 2.81 | |
| NYMEX HH Natural Gas Purchased Puts: | | | |
| Notional volume (MMBtu) | 600,000 | | | 3,600,000 | |
| Weighted average purchased put price ($/MMBtu) | $ | 2.90 | | | $ | 3.04 | |
| NYMEX HH Natural Gas Sold Calls: | | | |
| Notional volume (MMBtu) | 600,000 | | | 3,600,000 | |
| Weighted average sold call price ($/MMBtu) | $ | 3.48 | | | $ | 3.46 | |
| NYMEX HH Natural Gas Sold Puts: | | | |
| Notional volume (MMBtu) | — | | | 3,000,000 | |
| Weighted average fixed basis price ($/MMBtu) | $ | — | | | $ | 2.50 | |
| CIG Basis Gas Swaps: | | | |
| Notional volume (MMBtu) | 27,600,000 | | | 42,200,000 | |
| Weighted average fixed basis price ($/MMBtu) | $ | (0.58) | | | $ | (0.73) | |
| Total Amounts Received/(Paid) from Settlement (in thousands) | $ | 188,822 | | | $ | (5,790) | |
| Cash (used in) provided by changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives | $ | (2,957) | | | $ | 5,112 | |
| Derivative unwinds reducing the Prior Credit Facility balance | $ | (96,065) | | | $ | — | |
| Settlements on Commodity Derivatives per Consolidated Statements of Cash Flows | $ | 89,800 | | | $ | (678) | |
Lease Operating Expenses
All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constitutes part of the current operating expenses of a working interest. Such costs include labor, supplies, repairs, maintenance, water injection and disposal costs, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.
Capital Expenditures
For the year ended December 31, 2020, we incurred approximately $159.6 million in drilling and completion capital expenditures. For the year ended December 31, 2020, we drilled 37 gross (25.7 net) wells with an average lateral length of approximately 2.3 miles and completed 45 gross (34.1 net) wells with an average lateral length of approximately 2.4 miles. We turned to sales 49 gross (36.5 net) wells with an average lateral length of approximately 2.4 miles. In addition, we incurred approximately $16.9 million of leasehold and surface acreage additions.
Our 2021 capital budget for the drilling and completion of operated and non-operated wells is approximately $140 million to $180 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 34 gross operated wells, complete 49 gross operated wells and turn-in-line 44 gross operated wells. Our 2021 capital budget anticipates a one-rig drilling program we expect to operate most of the year.
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer or accelerate a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.
Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income (loss) as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net loss adjusted for certain cash and non-cash items, including depletion, depreciation, amortization and accretion (DD&A), impairment of long lived assets, non-recurring charges in other operating expenses, exploration and abandonment expenses, (gain) loss on sale of property and equipment, commodity derivatives (gain) loss, settlements on commodity derivative instruments, premiums paid for derivatives that settled during the period, stock-based compensation expense, amortization of debt issuance costs, interest expense, gain on repurchase of senior notes, income tax benefit, loss on deconsolidation of Elevation Midstream, LLC and reorganization items, net. Adjusted EBITDAX is also used to evaluate the performance of reportable segments. See Note 18 — Segment Information in Part II, Item 8 of this Annual Report for more information regarding the EBITDAX of reportable segments.
Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure (i) is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors; (ii) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and (iii) is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting.
The following table presents a reconciliation of the GAAP financial measure net loss to Adjusted EBITDAX for each of the periods indicated (in thousands).
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2020 | | 2019 |
| Reconciliation of Net Loss to Adjusted EBITDAX: | | | |
| Net Loss | $ | (1,267,534) | | | $ | (1,367,420) | |
| Add back: | | | |
| Depletion, depreciation, amortization and accretion | 332,319 | | | 524,537 | |
| Impairment of long lived assets | 208,463 | | | 1,337,996 | |
| Other operating expenses | 79,615 | | | — | |
| Exploration and abandonment expenses | 258,932 | | | 88,794 | |
| (Gain) loss on sale of property and equipment | (122) | | | 421 | |
| Commodity derivative (gain) loss | (164,968) | | | 37,107 | |
| Settlements on commodity derivative instruments | 188,822 | | | (5,790) | |
| Premiums paid for derivatives that settled during the period | — | | | (18,929) | |
| Stock-based compensation expense | 6,511 | | | 43,954 | |
| Amortization of debt issuance costs | 3,685 | | | 5,482 | |
| Interest expense | 53,458 | | | 84,236 | |
| Gain on repurchase of 2026 Senior Notes | — | | | (10,486) | |
| Income tax benefit | — | | | (109,176) | |
| Loss on deconsolidation of Elevation Midstream, LLC | 73,139 | | | — | |
| Reorganization items, net | 676,855 | | | — | |
| Adjusted EBITDAX | $ | 449,175 | | | $ | 610,726 | |
Free Cash Flow
Our Free Cash Flow is not a measure of net income (loss) as determined by GAAP. We define Free Cash Flow as Discretionary Cash Flow (non-GAAP) less Adjusted Cash Flow used in Investing (non-GAAP) adjusted for Other Non-Recurring Adjustments (non-GAAP). Discretionary Cash Flow is defined as net cash provided by operating activities (GAAP) less changes in working capital (current assets and liabilities). Adjusted Cash Flow used in Investing is defined as cash flow used in investing activities (GAAP) adjusted for changes in accounts payable and accrued liabilities related to capital expenditures.
Free Cash Flow is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Free Cash Flow can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe Free Cash Flow provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities, construct and support midstream assets, and to return capital to stockholders.
The following tables present a reconciliation of Discretionary Cash Flow and Free Cash Flow to the GAAP financial measure of net cash provided by operating activities for each of the periods indicated.
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Year Ended December 31, 2020 |
| Cash Flow from Operating Activities | | | | | |
| Net cash provided by operating activities | $ | 263,095 | | | $ | 2,880 | | | $ | 265,975 | |
| Changes in current assets and liabilities | (695,436) | | | (1,907) | | | (697,343) | |
| Discretionary Cash Flow | $ | (432,341) | | | $ | 973 | | | $ | (431,368) | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | $ | (239,261) | | | $ | (5,840) | | | $ | (245,101) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | 74,247 | | | 2,210 | | | 76,457 | |
| Adjusted Cash Flow used in Investing | $ | (165,014) | | | $ | (3,630) | | | $ | (168,644) | |
| | | | | |
| Other Non-Recurring Adjustments (1) | $ | 1,729 | | | $ | — | | | $ | 1,729 | |
| Other Non-Recurring Adjustments (2) | $ | 582,439 | | | $ | — | | | $ | 582,439 | |
| | | | | |
| Free Cash Flow | $ | (13,187) | | | $ | (2,657) | | | $ | (15,844) | |
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Year Ended December 31, 2019 |
| Cash Flow from Operating Activities | | | | | |
| Net cash provided by operating activities | $ | 554,171 | | | $ | 3,786 | | | $ | 557,957 | |
| Changes in current assets and liabilities | 10,589 | | | 829 | | | 11,418 | |
| Discretionary Cash Flow | $ | 564,760 | | | $ | 4,615 | | | $ | 569,375 | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | $ | (623,506) | | | $ | (226,647) | | | $ | (850,153) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | 23,372 | | | 428 | | | 23,800 | |
| Adjusted Cash Flow used in Investing | $ | (600,134) | | | $ | (226,219) | | | $ | (826,353) | |
| | | | | |
| Other Non-Recurring Adjustments (1) | $ | 16,496 | | | $ | — | | | $ | 16,496 | |
| | | | | |
| Free Cash Flow | $ | (18,878) | | | $ | (221,604) | | | $ | (240,482) | |
(1) Amount incurred for the construction of our field office that is included in other property and equipment in our consolidated statements of cash flows.
(2) Amount of accrued damages for rejected and settled contracts within changes in current assets and liabilities on the consolidated statements of cash flows.
Items Affecting the Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, for the reasons described below:
•During the Chapter 11 Cases, our financial results have been volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impacted our financial results. For the year ended December 31, 2020, we incurred $676.9 million of reorganization items net as compared to none in 2019. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. The Company emerged from the Chapter 11 proceedings on January 20, 2021, however claim assessments will continue for months longer.
•Elevation Midstream, LLC was deconsolidated as of March 16, 2020 and accounted for as an equity method investment. We elected the fair value option to remeasure the Elevation Midstream, LLC equity method investment and determined it had no fair value. We recorded a $73.1 million loss on deconsolidation of Elevation Midstream, LLC in the consolidated statements of operations for the year ended December 31, 2020. Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for information related to the deconsolidation of Elevation Midstream, LLC.
•For the years ended December 31, 2020 and 2019 we recognized $194.3 million and $1.3 billion, respectively, in impairment expense on our oil and gas properties related to assets in our Core DJ Basin field and to a much lesser extent in our northern field.
•For the years ended December 31, 2020 and 2019, respectively, exploration and abandonment expenses increased primarily due to the abandonment of $253.1 million and $73.7 million of unproved properties.
Historical Results of Operations and Operating Expenses
Oil, Natural Gas and NGL Sales Revenues, Operating Expenses and Other Income (Expense)
For components of our revenues, operating expenses, other income (expense) and net income (loss), please see our consolidated statements of operations in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report. The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2020 | | 2019 |
| Sales (MBoe): (1) | 32,540 | | | 32,385 | |
| Oil sales (MBbl) | 12,543 | | | 15,436 | |
| Natural gas sales (MMcf) | 72,311 | | | 64,710 | |
| NGL sales (MBbl) | 7,945 | | | 6,164 | |
| Sales (BOE/d): (1) | 88,907 | | | 88,728 | |
| Oil sales (Bbl/d) | 34,270 | | | 42,291 | |
| Natural gas sales (Mcf/d) | 197,570 | | | 177,288 | |
| NGL sales (Bbl/d) | 21,708 | | | 16,889 | |
| Average sales prices: (2) | | | |
| Oil sales (per Bbl) (3) | $ | 30.50 | | | $ | 46.74 | |
| Oil sales with derivative settlements (per Bbl) (3) | 37.15 | | | 45.16 | |
| Natural gas sales (per Mcf) | 1.34 | | | 1.68 | |
| Natural gas sales with derivative settlements (per Mcf) | 1.47 | | | 1.68 | |
| NGL sales (per Bbl) | 9.72 | | | 12.18 | |
| Average price (per BOE) (3) | 17.10 | | | 27.96 | |
| Average price with derivative settlements (per BOE) (3) | 19.95 | | | 27.19 | |
| Expense per BOE: (1) | | | |
| Lease operating expenses | $ | 2.39 | | | $ | 3.00 | |
| Transportation and gathering | 4.26 | | | 1.64 | |
| Production taxes | 0.89 | | | 2.11 | |
| Exploration and abandonment expenses | 7.96 | | | 2.74 | |
| Depletion, depreciation, amortization, and accretion | 10.21 | | | 16.20 | |
| General and administrative expenses | 1.70 | | | 3.05 | |
| Cash general and administrative expenses | 1.50 | | | 1.69 | |
| Stock-based compensation | 0.20 | | | 1.36 | |
| Total operating expenses per BOE (4) | 27.41 | | | 28.74 | |
| | | |
| Production taxes as a percentage of revenue | 5.2 | % | | 7.5 | % |
(1)One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2)Average prices shown in the table reflect prices both before and after the effects of our settlements of commodity derivative contracts. Our calculation of such effects includes both gains and losses on settlements for commodity derivatives and amortization of premiums paid or received on options that settled during the period.
(3)Includes amounts allocated to a satisfied performance obligation, recognized within oil sales for the years ended December 31, 2020 and December 31, 2019, pursuant to ASC 606, Revenue Recognition.
(4)Excludes midstream operating expenses, impairment of long lived assets, gain on sale of property and equipment and other operating expenses.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Oil sales revenues. Crude oil sales revenues decreased by $338.9 million to $382.5 million for the year ended December 31, 2020 as compared to crude oil sales of $721.4 million for the year ended December 31, 2019. A decrease in sales volumes between these periods contributed to a $135.2 million negative impact, and a decrease in crude oil prices contributed a $203.7 million negative impact. Additionally, for the year ended December 31, 2020 crude oil revenue decreased by approximately $12.3 million as compared to a crude oil revenue decrease of approximately $24.7 million for the year ended December 31, 2019 due to a contract term impacting the amount of consideration that can be included in the transaction price which reduced oil sales revenue pursuant to ASC 606.
For the year ended December 31, 2020, our crude oil sales averaged 34.3 MBbl/d. Our crude oil sales volumes decreased 19% to 12,543 MBbl for the year ended December 31, 2020 compared to 15,436 MBbl for the year ended December 31, 2019. The volume decrease was primarily due to the natural decline of our existing producing properties, which was partially offset by an increase in production from the completion of 45 wells during the year ended December 31, 2020.
The average price we realized on the sale of crude oil was $30.50 per Bbl for the year ended December 31, 2020 compared to $46.74 per Bbl for the year ended December 31, 2019, primarily due to changes in market prices for crude oil and the $12.3 million and $24.7 million decrease of crude oil revenue explained above.
Natural gas sales revenues. Natural gas sales revenues decreased by $12.2 million to $96.7 million for the year ended December 31, 2020 as compared to natural gas sales revenues of $108.9 million for the year ended December 31, 2019. An increase in sales volumes between these periods contributed a $12.8 million positive impact, while a decrease in natural gas prices contributed a $25.0 million negative impact.
For the year ended December 31, 2020, our natural gas sales averaged 197.6 MMcf/d. Natural gas sales volumes increased by 12% to 72,311 MMcf for the year ended December 31, 2020 as compared to 64,710 MMcf for the year ended December 31, 2019. The volume increase was primarily due to the completion of 45 gross wells for the year ended December 31, 2020. The increased production from these new wells was partially offset by the natural decline of our existing producing properties.
The average price we realized on the sale of our natural gas was $1.34 per Mcf for the year ended December 31, 2020 compared to $1.68 per Mcf for the year ended December 31, 2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative commodity price environment due to oversupply and a decrease in demand.
NGL sales revenues. NGL sales revenues increased by $2.1 million to $77.2 million for the year ended December 31, 2020 as compared to NGL sales revenues of $75.1 million for the year ended December 31, 2019. An increase in sales volumes between these periods contributed a $21.6 million positive impact, while a decrease in price contributed a $19.4 million negative impact.
For the year ended December 31, 2020, our NGL sales averaged 21.7 MBbl/d. NGL sales volumes increased by 29% to 7,945 MBbl for the year ended December 31, 2020 as compared to 6,164 MBbl for the year ended December 31, 2019. The volume increase is primarily due to the completion of 45 gross wells for the year ended December 31, 2020. The increased production from these new wells was partially offset by the natural decline of our existing producing properties. Our NGL sales are directly associated with our natural gas sales because our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $9.72 per Bbl for the year ended December 31, 2020 compared to $12.18 per Bbl for the year ended December 31, 2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative commodity price environment due to oversupply and a decrease in demand.
Lease operating expenses ("LOE"). Our LOE, decreased by $19.5 million to $77.8 million for the year ended December 31, 2020, from $97.3 million for the year ended December 31, 2019. The decrease in LOE was primarily the result of optimization of our field cost structure during the year ended December 31, 2020. On a per unit basis, LOE decreased to $2.39 per BOE sold for the year ended December 31, 2020 from $3.00 per BOE sold for the year ended December 31, 2019.
Transportation and gathering. Our T&G expense increased by $85.5 million to $138.6 million for the year ended December 31, 2020, from $53.1 million for the year ended December 31, 2019. The increase in T&G is primarily attributable to an increase of volumes on a certain gathering system and a change in oil contracts.
On a per unit basis, T&G increased to $4.26 per BOE sold for the year ended December 31, 2020 from $1.64 per BOE sold for the year ended December 31, 2019.
Production taxes. Our production taxes decreased by $39.2 million to $29.0 million for the year ended December 31, 2020 as compared to $68.2 million for the year ended December 31, 2019. The decrease was attributable to decreased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 5.2% for the year ended December 31, 2020 as compared to 7.5% for the year ended December 31, 2019. The decrease in production taxes as a percentage of sales revenue relates to a decrease in the estimated ad valorem and severance tax rates and an adjustment to the estimated ad valorem tax payable as of December 31, 2020.
Exploration and abandonment expenses. Our exploration and abandonment expenses were $258.9 million and $88.8 million for the years ended December 31, 2020 and 2019, respectively. We recognized $4.9 million in expense attributable to the extension of certain leases and $253.1 million in expense attributable to the abandonment of unproved properties for the year ended December 31, 2020. We recognized $12.4 million in expense attributable to the extension of certain leases and $73.7 million in expense attributable to the abandonment of unproved properties for the year ended December 31, 2019.
Depletion, depreciation, amortization and accretion expense. Our DD&A expense decreased $192.2 million to $332.3 million for the year ended December 31, 2020 as compared to $524.5 million for the year ended December 31, 2019. This decrease was due to an impairment of $1.3 billion of proved oil and gas properties that occurred during the fourth quarter of 2019. On a per unit basis, DD&A expense decreased from $16.20 per BOE for the year ended December 31, 2019 to $10.21 per BOE for the year ended December 31, 2020.
Impairment of long lived assets. For the year ended December 31, 2020, our impairment expense was $208.5 million, related to the impairment of other property and equipment, well equipment inventory, and the impairment of oil and gas properties in our Core DJ Basin field as the field’s fair values did not exceed the carrying amounts associated with our proved oil and gas properties. For the year ended December 31, 2019, our impairment expense was $1.3 billion. We recognized $14.5 million related to impairment of the proved oil and gas properties in our northern field and $1.3 billion of impairment expense was recognized for the year ended December 31, 2019 on proved oil and gas properties in our Core DJ Basin field.
(Gain) loss on sale of property and equipment and assets of unconsolidated subsidiary. Our gain on the sale of insignificant property was $0.1 million for the year ended December 31, 2020, as compared to a $0.4 million loss for the year ended December 31, 2019, which was related to our March 2019 Divestiture, August 2019 Divestiture and December 2019 Divestitures.
General and administrative expenses (“G&A”). General and administrative expenses decreased by $43.6 million to $55.2 million for the year ended December 31, 2020 as compared to $98.8 million for the year ended December 31, 2019. This decrease was primarily due to a decrease of $37.6 million in stock based compensation and a decrease in employed workforce of 61%, or 198 employees during the year ended December 31, 2020 compared to the year ended December 31, 2019. On a per unit basis, G&A expenses decreased by $1.35 per BOE from $3.05 per BOE sold for the year ended December 31, 2019 to $1.70 per BOE sold for the year ended December 31, 2020.
Our G&A expenses include the non-cash expense for stock-based compensation for equity awards granted to our employees and directors. For the year ended December 31, 2020, stock-based compensation expense was $6.4 million as compared to stock-based compensation expense of $44.0 million for the year ended December 31, 2019. On a per unit basis, stock-based compensation decreased $1.16 per BOE from $1.36 per BOE sold for the year ended December 31, 2019 to $0.20 per BOE sold for the year ended December 31, 2020.
Other operating expenses. Other operating expenses were $79.6 million for the year ended December 31, 2020. This amount is made up of a $46.8 million loss contingency related to an alleged breach in contract, $4.2 million of accrued interest related to the aforementioned breach in contract, a $13.2 million early termination fee related to the termination of our crude oil marketing contract, $7.6 million incurred due to workforce reductions, $4.1 million incurred in production tax interest expense, a $2.4 million early termination fee related to the termination of a drilling rig contract, and $1.3 million in expenses related to legal accruals and other.
Commodity derivative gain (loss). Primarily due to the unwinding of trades due to the commencement of the Chapter 11 Cases, coupled with the decrease in NYMEX crude oil futures prices at December 31, 2020 as compared to December 31, 2019 and change in fair value from the execution of new positions, we incurred a net gain on our commodity derivatives of $165.0 million for the year ended December 31, 2020. Primarily due to the increase in NYMEX crude oil futures prices at December 31, 2019 as compared to December 31, 2018 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of $37.1 million. These gains and losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. For the years ended December 31, 2020 and 2019, we received and paid cash settlements of commodity derivatives totaling $188.8 million and $5.8 million, respectively.
Loss on deconsolidation of Elevation Midstream, LLC. On March 16, 2020, we deconsolidated Elevation Midstream, LLC. Upon deconsolidation, we elected the fair value option to remeasure the Elevation equity method investment and determined it had no fair value. The Company recorded a $73.1 million loss on deconsolidation of Elevation Midstream, LLC in the consolidated statements of operations for the year ended December 31, 2020.
Reorganization items, net. Due to the commencement of the Chapter 11 Cases during the second quarter of 2020, we have incurred and will continue to incur significant costs associated with our reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. For the year ended December 31, 2020, we recognized $676.9 million in reorganization items. No reorganization items were recognized during the same period in the preceding year. Please see Note 6 — Reorganization Items, Net in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
Interest expense. Interest expense consists of interest expense on our long-term debt and debt issuance costs, net of capitalized interest. For the year ended December 31, 2020, we recognized interest expense of approximately $57.1 million as compared to $79.2 million for the year ended December 31, 2019, as a result of borrowings under our Prior Credit Facility, our DIP Credit Facility, our 2024 Senior Notes, our 2026 Senior Notes, and the amortization of other debt issuance costs.
We incurred interest expense for the year ended December 31, 2020 of approximately $58.8 million related to our 2024 Senior Notes, 2026 Senior Notes, Prior Credit Facility and Capital Raise
2026DIP Credit Facility. We incurred interest expense for the year ended December 31, 2019 of approximately $91.5 million related to our 2024 Senior Notes,
On January 25, 2018, we issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026 (the "2026 Senior Notes" and the offering, the "2026 Senior Notes Offering"). The 2026 Senior Notes bearand Prior Credit Facility. Also included in interest expense for the years ended December 31, 2020 and 2019 was the amortization of debt issuance costs of $3.7 million and $5.5 million, respectively, and a gain on the sale of extinguishment of debt of $10.5 million for the year ended December 31, 2019. For the years ended December 31, 2020 and 2019, we capitalized interest expense of $5.3 million and $7.2 million, respectively.
Income tax (expense) benefit. We recorded no income tax expense (benefit) for the year ended December 31, 2020 resulting in an annual interesteffective tax rate of 5.625%approximately zero. We recorded an income tax benefit of approximately $109.2 million for the year ended December 31, 2019 resulting in an effective tax rate of approximately 7.4%. Our effective tax rate for 2020 and 2019 differs from the U.S. statutory income tax rate of 21% primarily due to the effects of state income taxes, estimated permanent taxable differences, nondeductible stock-based compensation, and the recording of a valuation allowance against deferred tax assets.
Gathering and facilities segment. Prior to March 31, 2020, we had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the “exploration and production segment”) and (ii) the construction, operation and support of midstream assets to gather and process crude oil and gas production (the “gathering and facilities segment”). Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for further information related to the deconsolidation of Elevation Midstream, LLC. After March 31, 2020, Extraction began reporting as a single reportable segment.
Our consolidated statements of operations for the year ended December 31, 2020 contains the following amounts, which were incurred during the first quarter of 2020. The interestgathering and facilities segment had revenues of $6.0 million and direct operating expenses of $3.9 million. General and administrative expenses were $0.7 million and depreciation expense was $1.1 million as the gathering facility was placed into service during the fourth quarter of 2019. Please see Note 18 — Segments in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
Our consolidated statements of operations for the year ended December 31, 2019 contains the following amounts. The gathering and facilities segment had revenues of $6.9 million and direct operating expenses of $2.3 million. General and administrative expenses were $4.6 million and depreciation expense was $1.4 million as the gathering facility was placed into service during the fourth quarter of 2019.
Liquidity and Capital Resources
Chapter 11 Cases and Effect of Automatic Stay
On June 14, 2020, we filed for relief under Chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Prior Credit Agreement (defined below) and the indentures governing our Senior Notes, resulting in the automatic and immediate acceleration of all of our outstanding debt under the Prior Credit Agreement and the Senior Notes. Any efforts to enforce payment obligations related to the acceleration of our debt were automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. On June 14, 2020, we also entered into the Restructuring Support Agreement (“RSA”) with certain holders of our Senior Notes to support a restructuring in accordance with the terms set forth therein. As more fully disclosed in Note 1 — Business and Organization and Note 8 — Long-Term Debt in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report, the RSA contemplated a financial restructuring which would provide for the treatment of holders of certain claims and existing equity interests. The Plan, which included substantially all terms set forth in the RSA, was approved by the Bankruptcy Court on December 23, 2020 and we emerged from bankruptcy on January 20, 2020.
We continued operations in the ordinary course for the duration of the Chapter 11 Cases funding operations with our DIP Credit Facility (as defined in Note 8 — Long-Term Debt in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report along with all capitalized debt terms in this paragraph). Upon emergence from bankruptcy, our Prior Credit Facility and DIP Credit Facility were paid off and we obtained a RBL Credit Facility discussed below.
As a result of the Chapter 11 Cases, our total available liquidity as of December 31, 2020 consisted of cash on hand of $205.9 million and $11.5 million of availability on the DIP Credit Facility. With this liquidity and funds generated from ongoing operations, we funded cash requirements throughout 2020 during the Chapter 11 proceedings. As such, we paid and expect to continue paying vendor and royalty obligations according to the terms of our current contracts.
Sources of Liquidity and Capital Resources
Historically, our primary sources of liquidity have been borrowings under our Prior Credit Facility, proceeds from notes offerings and preferred stock offerings, equity provided by investors, including our management team, cash from issuance of preferred stock, and cash flows from divestitures and from the sale of oil, gas and NGL production. Our primary uses of capital have been for the acquisition of oil and gas properties to increase our acreage position, as well as development and exploration of oil and gas properties. As of December 31, 2020, our DIP Credit Facility borrowings were $106.7 million, with $75.0 million total outstanding including amounts that were rolled over from the Prior Credit Facility. Our Prior Credit Facility borrowings were $453.7 million and $470.0 million at December 31, 2020, and December 31, 2019, respectively. We had senior notes totaling $1.1 billion outstanding at December 31, 2020 and December 31, 2019. We also have other contractual commitments, which are described in Note 16 — Commitments and Contingencies in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report.
Upon emergence from bankruptcy on January 20, 2021 indebtedness under our 2024 and 2026 Senior Notes was discharged in exchange for equity as is payableexplained in Note 1 — Business and Organization in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report. Our Prior Credit Facility and DIP Credit Facility were paid off, terminated and replaced by our RBL Credit Facility that has a maximum commitment of $1.0 billion with an initial borrowing base and current elected lending commitments of $500.0 million. The borrowing base will be redetermined semiannually on Februaryor around May 1 and AugustNovember 1 of each year, commencingwith one interim “wildcard” redetermination available to us and our administrative agent between scheduled redeterminations during any 12-month period. The next scheduled redetermination will be on Augustor around May 1, 2018. We received net proceeds2021.
As of approximately $737.9the date of this filing, we have drawn $253.7 million on the RBL Credit Facility. Total funds available for borrowing under our RBL Credit Facility, after deducting discounts and fees. We used $534.2giving effect to an aggregate of $0.5 million of undrawn letters of credit, were $245.8 million as of the date of this filing.
We enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations, or alternatively, we may decide to unwind or restructure the hedging arrangements we previously entered into. The RBL Credit Agreement requires us to maintain commodity hedges covering a minimum of 65% of our anticipated oil and gas production from PDP reserves for the succeeding twelve months and 50% of our anticipated oil and gas production from PDP reserves for the next succeeding twelve months.
Our 2021 capital budget for the drilling and completion of operated and non-operated wells is approximately $140 million to $180 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 34 gross operated wells, complete 49 gross operated wells and turn-in-line 44 gross operated wells. Our 2021 capital budget anticipates a one-rig drilling program we expect to operate most of the year.
We had a Stock Repurchase Program in place that ended in 2019. Spending under this program was $137.0 million and we repurchased 34.1 million shares during the year ended December 31, 2019. We also had a Senior Notes Repurchase Program in place. Spending under this program during the year ended December 31, 2019 was $39.3 million. No common stock or Senior Notes were repurchased during the year ended December 31, 2020.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in thousands):
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 |
| Net cash provided by operating activities | $ | 265,975 | | | $ | 557,957 | |
| Net cash used in investing activities | (245,101) | | | (850,153) | |
| Net cash provided by financing activities | 160,362 | | | 89,592 | |
Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019
Net cash provided by operating activities. For the year ended December 31, 2020 as compared to the year ended December 31, 2019, our net proceedscash provided by operating activities decreased by $292.0 million primarily due to a decrease in operating revenues net of expenses of $377.3 million as a result of a decrease in commodity prices and a decrease of $126.3 million related to changes in working capital when excluding the $582.4 million change in accrued damages for rejected and settled contracts. Also, cash paid for reorganization items during 2020 increased $34.4 million. These reductions to cash inflows were partially offset by an increase of $90.5 million in commodity derivative settlement payments, a decrease of $46.1 million in cash paid for interest and a decrease of $6.1 million in cash paid for general and administrative expenses.
Net cash used in investing activities. For the year ended December 31, 2020 as compared to the year ended December 31, 2019, our net cash used in investing activities decreased by $605.1 million primarily due to decreased spending of $385.9 million on oil and gas property additions, $206.7 million on our gathering systems and facilities, $35.4 million on other property and equipment, and $20.0 million on investments in an unconsolidated subsidiary. During 2020, cash received from the 2026 Senior Notes Offering to tender for our 2021 Senior Notes, $52.7sale of property and equipment decreased $41.9 million to redeem any 2021 Senior Notes not tendered and cash received from the remainder will be used for general corporate purposes. Our borrowing base under our revolving credit facility was automatically reduced to $700.0 million in connection withsale of assets of unconsolidated subsidiary decreased $1.0 million.
Net cash provided by financing activities. For the closing of the 2026 Senior Notes Offering; however, there was no changeyear ended December 31, 2020 as compared to the current maximum lending commitments of $650.0year ended December 31, 2019, our net cash provided by financing activities increased by $70.8 million.
Tender Offer to Purchase 2021 Senior Notes
On January 25, 2018, we announced Net borrowings on the results of our cash tender offer to purchase any and all of the outstanding aggregate principal amount of the 2021 Senior Notes. An aggregate principal amount of $500.6 million (91%) was tendered and paid, in addition to a make-whole premium of $32.6Prior Credit Facility decreased $54.5 million, and accrued and unpaid interestno cash was received in 2020 from the issuance of $1.0Elevation Preferred Units compared to $99.0 million received during 2019. These decreases were offset by an increase in net borrowings on January 25, 2018. On February 17, 2018, we redeemed the approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which includes a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.
January 2018DIP Credit Facility Amendment
On January 5, 2018, we amended the revolving credit facility to (i) increase the borrowing base from $525.0of $31.7 million, to $750.0a decrease in cash spent on payroll withholding taxes of $1.7 million, subject to the current maximum lending commitments of $650.0 million, (ii) increase the maximum amount for the letter of credit issueda decrease in favor of a purchaser of our crude oil be increased from $25.0 million to $35.0 million, and (iii) amend certain provisions of the credit agreement, including the commitments and allocations of each lender. Subsequent to this amendment our borrowing base was reduced in connections with the 2026 Senior Notes Offering. See "–Liquidity and Capital Resources–Revolving Credit Facility.”
October 2017 Credit Facility Amendment
On October 11, 2017, we amended the revolving credit facility to, among other things, (i) provide for the joinder of new lenders, (ii) increase the borrowing base under the credit facility from $375.0 million to $525.0 million, and (iii) amend certain provisions of the credit agreement, including the commitments and allocations of each lender. See “–Liquidity and Capital Resources–Revolving Credit Facility.”
August 2017 Credit Facility Amendment and Restatement
On August 16, 2017, we entered into an amendment and restatement of our existing credit facility, which provides commitments of $1.5 billion with a syndicate of banks, which was subject to a borrowing base of $375.0 million. The credit facility matures on the earlier of (a) August 16, 2022, (b) January 15, 2021 if (and only if) our 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior to January 15, 2021, (c) April 15, 2021, if (and only if) (i) the convertible preferred equity interests issued by us has not been converted into common equity or redeemed prior to April 15, 2021, and (ii) prior to April 15, 2021, the maturity date of the Series A Preferred Stock has not been extendeddividends of $10.9 million, and a decrease of Preferred Unit Issuance costs of $2.5 million during 2020 compared to 2019. Additionally, during 2020 no cash was spent repurchasing common stock and senior notes, but during 2019 cash spent to repurchase common stock was $137.7 million, as result of our Share Repurchase Program, and senior notes was $39.3 million, as a date that is no earlier than six months after August 16, 2022 or (d) the earlier termination in wholeresult of the commitments. See “–Liquidity and Capital Resources–Revolving Credit Facility.”our Senior Notes Repurchase Program.
2024 Senior NotesWorking Capital
On August 1, 2017, we issuedOur working capital deficit at par $400.0December 31, 2020 was $369.4 million principaland at December 31, 2019 was $240.8 million. However, as of December 31, 2020, many of our current liabilities in the amount of 7.375% Senior Notes due May 15, 2024 (the "2024 Senior Notes"$279.6 million were classified as liabilities subject to compromise (excluding approximately $1.8 billion of debt, accrued interest, damages for rejected and settled contracts and other). Our cash balances totaled $205.9 million and $32.4 million at December 31, 2020 and 2019, respectively.
Due to the amounts that we incur related to our drilling and completion program and the offering,timing of such expenditures, we may incur working capital deficits in the "2024 Senior Notes Offering"). Thefuture. We expect that our cash flows from operating activities and availability under our RBL Credit Facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil, natural gas and NGL production will be the largest variables affecting our working capital.
Debt Arrangements
For details of our debt arrangements including our RBL Credit Facility, DIP Credit Facility, Prior Credit Facility, 2024 Senior Notes bearand 2026 Senior Notes, please see Note 8 — Long-Term Debt in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
Equity Arrangements
For details of our equity arrangements including our Series A Preferred Stock and Elevation Preferred Units, please see Note 12 — Equity in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report.
Commitments, Contingencies and Contractual Obligations
The information responsive to Item 303 (a)(5) of Regulation S-K is not required of smaller reporting companies.
Off-Balance Sheet Arrangements
As of December 31, 2020, we do not have material off-balance sheet arrangements.
Impact of Inflation/Deflation and Pricing
All of our transactions are denominated in U.S. dollars. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, as prices for oil and natural gas decrease, costs decline. Cost declines tend to lag and may not adjust downward in proportion to decline commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the year ended December 31, 2020, commodity prices decreased during the first and second quarters and subsequently increased in the third and fourth quarters. During the year ended December 31, 2019, commodity prices decreased during the first quarter, increased in the second quarter, and subsequently decreased in the third quarter and fourth quarter. Changes in commodity prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel.
Critical Accounting Policies and Estimates
Use of Estimates in the Preparation of Financial Statements
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include:
(1) oil and gas reserves;
(2) depreciation, depletion, amortization and accretion;
(3) cash flow estimates used in impairment testing of oil and gas proved and unproved properties;
(4) valuation of commodity derivative instruments;
(5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill;
(6) asset retirement obligations;
(7) accrued revenue and related receivables;
(8) valuation of stock-based payments,
(9) income taxes, and
(10) bankruptcy proceedings.
Although management believes these estimates are reasonable, actual results could differ from these estimates. We evaluate our estimates on an annualon-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe our estimates are reasonable.
Successful Efforts Method of Accounting
We follow the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
We capitalize interest, rateif debt is outstanding, during drilling operations in our exploration and development activities.
Oil and Gas Reserves
Our estimates of 7.375%. The interestproved reserves are based on the 2024 Senior Notesquantities of oil, natural gas and NGL, 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 under existing economic 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 payablereasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Our independent petroleum engineers, Ryder Scott, prepare a reserve and economic evaluation of all of our properties on May 15a well-by-well basis. The accuracy of reserve estimates is a function of the:
•quality and November 15quantity of available data;
•interpretation of that data;
•accuracy of various mandated economic assumptions; and
•judgment of the independent reserve engineer.
One of the most significant estimates we make is the estimate of oil, natural gas and NGL reserves. Oil, natural gas and NGL reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, projected future production, economic assumptions relating to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation costs and these estimates are inherently uncertain. For example, if estimates of proved reserves decline, our DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of oil and gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. We cannot predict what reserve revisions may be required in future periods.
Ryder Scott estimated all of our proved reserve quantities as of December 31, 2020 and 2019. In connection with Ryder Scott performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.
The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 |
| Revisions resulting from price changes (MBOE) | (27,204) | | | (18,049) | |
| Revisions resulting from production, performance and other (MBOE) | (60,105) | | | (72,488) | |
| Total revisions (MBOE) | (87,309) | | | (90,537) | |
Declines in oil, natural gas and NGL prices increase the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market. A prolonged period of depressed commodity prices may have a significant impact on the value and volumetric quantities of our proved reserve portfolio, assuming no other changes to our development plans or costs.
Depreciation, Depletion, Amortization and Accretion
Our DD&A rate is dependent upon our estimates of total proved and proved developed reserves, which incorporate various assumptions and future projections. If our estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, which in turn reduces our net income. Such a decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploration and development program, as well as future economic conditions.
Impairment of Proved Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets and goodwill in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization.
Future commodity pricing for oil is based on five-year West Texas Intermediate strip prices, which decreased 14.0% from an average of $53.65/Bbl at December 31, 2019 to an average of $46.14/Bbl at December 31, 2020. Future commodity pricing for natural gas is based on five-year Henry Hub strip prices, which increased 4.9% from an average of $2.42/MMBtu at December 31, 2019 to an average of $2.54/MMBtu at December 31, 2020. Future commodity pricing for NGLs is based on five-year WTI strip prices, which decreased 10.7% from an average of $14.40/Bbl at December 31, 2019 to an average of $12.85/Bbl at December 31, 2020.
Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.
For the year ended December 31, 2020, our impairment expense related to oil and gas properties was $197.9 million. We recognized $3.6 million related to impairment of the proved oil and gas properties in our northern field and $194.3 million related to assets in one of our Core DJ Basin fields, as the fields’ fair values did not exceed the carrying amounts associated with our proved oil and gas properties. For the year ended December 31, 2019, our impairment expense was $1.3 billion. We recognized $14.5 million related to impairment of the proved oil and gas properties in our northern field and $1.3 billion related to assets in one of our Core DJ Basin fields as the fields’ fair values did not exceed the carrying amounts associated with our proved oil and gas properties.
Forward commodity prices and estimates of future production play a significant role in determining impairment of proved oil and gas properties. As a result of lower commodity prices and their impact on our estimated future cash flows, we will continue to review our proved oil and gas properties for impairment. After our fourth quarter 2020 impairment charges in two of our Core DJ Basin fields at December 31, 2020, the carrying value of our oil and gas properties exceeded our expected undiscounted future cash flows for proved and risk-adjusted probable and possible reserves by approximately $56.8 million and $340.3 million, in each field. After our fourth quarter 2019 impairment charges in two of our Core DJ Basin fields at
December 31, 2019, the carrying value of our oil and gas properties exceeded our expected undiscounted future cash flows for proved and risk-adjusted probable and possible reserves by approximately $33.8 million and $1.2 billion, in each field. At December 31, 2018, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $0.8 billion, or 30%.
Abandonment of Unproved Oil and Gas Properties
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. We evaluate significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration and abandonment expenses in the consolidated statements of operations. As a result of the abandonment of unproved properties, we recognized $253.1 million and $73.7 million in abandonment expense for the years ended December 31, 2020 and 2019, respectively. To the extent we do not elect to renew current leases, we expect further abandonment charges in 2021.
Commodity Derivative Instruments
We have entered into commodity derivative instruments utilizing swaps to reduce the effect of price changes on a portion of our future oil and natural gas production. For a description of our derivative instruments that we utilize and a summary of our open commodity derivative contracts as of December 31, 2020, please see Note 9 — Commodity Derivative Instruments in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
The commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets or liabilities. We have not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, we do not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivative gain (loss) line on the consolidated statements of operations. Our cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in our consolidated statements of cash flows.
Our valuation estimate takes into consideration the counterparties’ credit worthiness, our credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market participant’s view. We believe that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please see “—How We Evaluate Our Operations—Derivative Arrangements.”
Accounting for Business Combinations
We account for all of our business combinations using the acquisition method, which is the only method permitted under ASC 805, Business Combinations, and involves the use of significant judgment. In connection with a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, we must prepare estimates. To estimate the fair values of these properties, we prepare estimates of gas, oil and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows 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 subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future net cash flows of probable and possible reserves are reduced by additional risk factors. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.
Asset Retirement Obligations
Our asset retirement obligations (“ARO”) consist of estimated future costs associated with the plugging and abandonment of oil, natural gas and NGL wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws, and applicable lease terms. The fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free discount rate to be used; and inflation rates. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property.
Revenue Recognition
Revenue from the sale of oil, natural gas and NGLs is recognized in accordance with ASC 606 - Revenue from Contracts with Customers five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. To account for producer imbalances, we recognize revenues on all sales of oil, natural gas and NGLs to third party customers regardless of their ownership percentage and adjust the underlifter or overlifter’s claim on the asset’s remaining reserves. In other words, revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. We receive payment one to three months after delivery. At the end of each year commencing on November 15, 2017. Wemonth, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts received net proceeds ofare recorded in the month payment is received. A 10% change in our revenue accrual would have impacted total operating revenues by approximately $392.6$6.3 million after deducting discounts and fees.$10.5 million for the years ended December 31, 2020 and 2019, respectively.
Stock-Based Payments
We granted awards under the 2016 LTIP and 2021 LTIP (as defined in Note 14 — Stock-Based Compensation in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report) to certain directors, officers and employees, including stock options, restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards which therefore required us to recognize the expense in our consolidated financial statements.
All stock-based payments to employees are measured at fair value on the grant date and expensed over the relevant service period. The fair value of stock option awards is determined by using the Black-Scholes option pricing model. The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. All stock-based payment expense is recognized using the straight-line method and is included within general and administrative expenses in the consolidated statements of operations and stock-based compensation in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 14 — Stock-Based Compensation in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for additional discussion on stock-based payments.
Income TaxesCapital Expenditures
For the year ended December 31, 2020, we incurred approximately $159.6 million in drilling and completion capital expenditures. For the year ended December 31, 2020, we drilled 37 gross (25.7 net) wells with an average lateral length of approximately 2.3 miles and completed 45 gross (34.1 net) wells with an average lateral length of approximately 2.4 miles. We turned to sales 49 gross (36.5 net) wells with an average lateral length of approximately 2.4 miles. In addition, we incurred approximately $16.9 million of leasehold and surface acreage additions.
Our 2021 capital budget for the drilling and completion of operated and non-operated wells is approximately $140 million to $180 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 34 gross operated wells, complete 49 gross operated wells and turn-in-line 44 gross operated wells. Our 2021 capital budget anticipates a one-rig drilling program we expect to operate most of the year.
On December 22, 2017,The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the Tax Cuts and Jobs Act (the “TCJA”) was enacted making significant changesflexibility to defer or accelerate a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the Internal Revenue Code.success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.
Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income (loss) as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We have calculated our best estimatedefine Adjusted EBITDAX as net loss adjusted for certain cash and non-cash items, including depletion, depreciation, amortization and accretion (DD&A), impairment of long lived assets, non-recurring charges in other operating expenses, exploration and abandonment expenses, (gain) loss on sale of property and equipment, commodity derivatives (gain) loss, settlements on commodity derivative instruments, premiums paid for derivatives that settled during the impactperiod, stock-based compensation expense, amortization of the TCJA in our year-enddebt issuance costs, interest expense, gain on repurchase of senior notes, income tax provisionbenefit, loss on deconsolidation of Elevation Midstream, LLC and reorganization items, net. Adjusted EBITDAX is also used to evaluate the performance of reportable segments. See Note 18 — Segment Information in Part II, Item 8 of this Annual Report for more information regarding the EBITDAX of reportable segments.
Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure (i) is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors; (ii) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and (iii) is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting.
The following table presents a reconciliation of the TCJAGAAP financial measure net loss to Adjusted EBITDAX for each of the periods indicated (in thousands).
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2020 | | 2019 |
| Reconciliation of Net Loss to Adjusted EBITDAX: | | | |
| Net Loss | $ | (1,267,534) | | | $ | (1,367,420) | |
| Add back: | | | |
| Depletion, depreciation, amortization and accretion | 332,319 | | | 524,537 | |
| Impairment of long lived assets | 208,463 | | | 1,337,996 | |
| Other operating expenses | 79,615 | | | — | |
| Exploration and abandonment expenses | 258,932 | | | 88,794 | |
| (Gain) loss on sale of property and equipment | (122) | | | 421 | |
| Commodity derivative (gain) loss | (164,968) | | | 37,107 | |
| Settlements on commodity derivative instruments | 188,822 | | | (5,790) | |
| Premiums paid for derivatives that settled during the period | — | | | (18,929) | |
| Stock-based compensation expense | 6,511 | | | 43,954 | |
| Amortization of debt issuance costs | 3,685 | | | 5,482 | |
| Interest expense | 53,458 | | | 84,236 | |
| Gain on repurchase of 2026 Senior Notes | — | | | (10,486) | |
| Income tax benefit | — | | | (109,176) | |
| Loss on deconsolidation of Elevation Midstream, LLC | 73,139 | | | — | |
| Reorganization items, net | 676,855 | | | — | |
| Adjusted EBITDAX | $ | 449,175 | | | $ | 610,726 | |
Free Cash Flow
Our Free Cash Flow is not a measure of net income (loss) as determined by GAAP. We define Free Cash Flow as Discretionary Cash Flow (non-GAAP) less Adjusted Cash Flow used in Investing (non-GAAP) adjusted for Other Non-Recurring Adjustments (non-GAAP). Discretionary Cash Flow is defined as net cash provided by operating activities (GAAP) less changes in working capital (current assets and guidanceliabilities). Adjusted Cash Flow used in Investing is defined as cash flow used in investing activities (GAAP) adjusted for changes in accounts payable and accrued liabilities related to capital expenditures.
Free Cash Flow is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Free Cash Flow can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe Free Cash Flow provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities, construct and support midstream assets, and to return capital to stockholders.
The following tables present a reconciliation of Discretionary Cash Flow and Free Cash Flow to the GAAP financial measure of net cash provided by operating activities for each of the periods indicated.
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Year Ended December 31, 2020 |
| Cash Flow from Operating Activities | | | | | |
| Net cash provided by operating activities | $ | 263,095 | | | $ | 2,880 | | | $ | 265,975 | |
| Changes in current assets and liabilities | (695,436) | | | (1,907) | | | (697,343) | |
| Discretionary Cash Flow | $ | (432,341) | | | $ | 973 | | | $ | (431,368) | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | $ | (239,261) | | | $ | (5,840) | | | $ | (245,101) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | 74,247 | | | 2,210 | | | 76,457 | |
| Adjusted Cash Flow used in Investing | $ | (165,014) | | | $ | (3,630) | | | $ | (168,644) | |
| | | | | |
| Other Non-Recurring Adjustments (1) | $ | 1,729 | | | $ | — | | | $ | 1,729 | |
| Other Non-Recurring Adjustments (2) | $ | 582,439 | | | $ | — | | | $ | 582,439 | |
| | | | | |
| Free Cash Flow | $ | (13,187) | | | $ | (2,657) | | | $ | (15,844) | |
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Year Ended December 31, 2019 |
| Cash Flow from Operating Activities | | | | | |
| Net cash provided by operating activities | $ | 554,171 | | | $ | 3,786 | | | $ | 557,957 | |
| Changes in current assets and liabilities | 10,589 | | | 829 | | | 11,418 | |
| Discretionary Cash Flow | $ | 564,760 | | | $ | 4,615 | | | $ | 569,375 | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | $ | (623,506) | | | $ | (226,647) | | | $ | (850,153) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | 23,372 | | | 428 | | | 23,800 | |
| Adjusted Cash Flow used in Investing | $ | (600,134) | | | $ | (226,219) | | | $ | (826,353) | |
| | | | | |
| Other Non-Recurring Adjustments (1) | $ | 16,496 | | | $ | — | | | $ | 16,496 | |
| | | | | |
| Free Cash Flow | $ | (18,878) | | | $ | (221,604) | | | $ | (240,482) | |
(1) Amount incurred for the construction of our field office that is included in other property and equipment in our consolidated statements of cash flows.
(2) Amount of accrued damages for rejected and settled contracts within changes in current assets and liabilities on the consolidated statements of cash flows.
Items Affecting the Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, for the reasons described below:
•During the Chapter 11 Cases, our financial results have been volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impacted our financial results. For the year ended December 31, 2020, we incurred $676.9 million of reorganization items net as compared to none in 2019. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. The Company emerged from the Chapter 11 proceedings on January 20, 2021, however claim assessments will continue for months longer.
•Elevation Midstream, LLC was deconsolidated as of March 16, 2020 and accounted for as an equity method investment. We elected the fair value option to remeasure the Elevation Midstream, LLC equity method investment and determined it had no fair value. We recorded a $73.1 million loss on deconsolidation of Elevation Midstream, LLC in the consolidated statements of operations for the year ended December 31, 2020. Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for information related to the deconsolidation of Elevation Midstream, LLC.
•For the years ended December 31, 2020 and 2019 we recognized $194.3 million and $1.3 billion, respectively, in impairment expense on our oil and gas properties related to assets in our Core DJ Basin field and to a much lesser extent in our northern field.
•For the years ended December 31, 2020 and 2019, respectively, exploration and abandonment expenses increased primarily due to the abandonment of $253.1 million and $73.7 million of unproved properties.
Historical Results of Operations and Operating Expenses
Oil, Natural Gas and NGL Sales Revenues, Operating Expenses and Other Income (Expense)
For components of our revenues, operating expenses, other income (expense) and net income (loss), please see our consolidated statements of operations in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report. The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2020 | | 2019 |
| Sales (MBoe): (1) | 32,540 | | | 32,385 | |
| Oil sales (MBbl) | 12,543 | | | 15,436 | |
| Natural gas sales (MMcf) | 72,311 | | | 64,710 | |
| NGL sales (MBbl) | 7,945 | | | 6,164 | |
| Sales (BOE/d): (1) | 88,907 | | | 88,728 | |
| Oil sales (Bbl/d) | 34,270 | | | 42,291 | |
| Natural gas sales (Mcf/d) | 197,570 | | | 177,288 | |
| NGL sales (Bbl/d) | 21,708 | | | 16,889 | |
| Average sales prices: (2) | | | |
| Oil sales (per Bbl) (3) | $ | 30.50 | | | $ | 46.74 | |
| Oil sales with derivative settlements (per Bbl) (3) | 37.15 | | | 45.16 | |
| Natural gas sales (per Mcf) | 1.34 | | | 1.68 | |
| Natural gas sales with derivative settlements (per Mcf) | 1.47 | | | 1.68 | |
| NGL sales (per Bbl) | 9.72 | | | 12.18 | |
| Average price (per BOE) (3) | 17.10 | | | 27.96 | |
| Average price with derivative settlements (per BOE) (3) | 19.95 | | | 27.19 | |
| Expense per BOE: (1) | | | |
| Lease operating expenses | $ | 2.39 | | | $ | 3.00 | |
| Transportation and gathering | 4.26 | | | 1.64 | |
| Production taxes | 0.89 | | | 2.11 | |
| Exploration and abandonment expenses | 7.96 | | | 2.74 | |
| Depletion, depreciation, amortization, and accretion | 10.21 | | | 16.20 | |
| General and administrative expenses | 1.70 | | | 3.05 | |
| Cash general and administrative expenses | 1.50 | | | 1.69 | |
| Stock-based compensation | 0.20 | | | 1.36 | |
| Total operating expenses per BOE (4) | 27.41 | | | 28.74 | |
| | | |
| Production taxes as a percentage of revenue | 5.2 | % | | 7.5 | % |
(1)One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2)Average prices shown in the table reflect prices both before and after the effects of our settlements of commodity derivative contracts. Our calculation of such effects includes both gains and losses on settlements for commodity derivatives and amortization of premiums paid or received on options that settled during the period.
(3)Includes amounts allocated to a satisfied performance obligation, recognized within oil sales for the years ended December 31, 2020 and December 31, 2019, pursuant to ASC 606, Revenue Recognition.
(4)Excludes midstream operating expenses, impairment of long lived assets, gain on sale of property and equipment and other operating expenses.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Oil sales revenues. Crude oil sales revenues decreased by $338.9 million to $382.5 million for the year ended December 31, 2020 as compared to crude oil sales of $721.4 million for the year ended December 31, 2019. A decrease in sales volumes between these periods contributed to a $135.2 million negative impact, and a decrease in crude oil prices contributed a $203.7 million negative impact. Additionally, for the year ended December 31, 2020 crude oil revenue decreased by approximately $12.3 million as compared to a crude oil revenue decrease of approximately $24.7 million for the year ended December 31, 2019 due to a contract term impacting the amount of consideration that can be included in the transaction price which reduced oil sales revenue pursuant to ASC 606.
For the year ended December 31, 2020, our crude oil sales averaged 34.3 MBbl/d. Our crude oil sales volumes decreased 19% to 12,543 MBbl for the year ended December 31, 2020 compared to 15,436 MBbl for the year ended December 31, 2019. The volume decrease was primarily due to the natural decline of our existing producing properties, which was partially offset by an increase in production from the completion of 45 wells during the year ended December 31, 2020.
The average price we realized on the sale of crude oil was $30.50 per Bbl for the year ended December 31, 2020 compared to $46.74 per Bbl for the year ended December 31, 2019, primarily due to changes in market prices for crude oil and the $12.3 million and $24.7 million decrease of crude oil revenue explained above.
Natural gas sales revenues. Natural gas sales revenues decreased by $12.2 million to $96.7 million for the year ended December 31, 2020 as compared to natural gas sales revenues of $108.9 million for the year ended December 31, 2019. An increase in sales volumes between these periods contributed a $12.8 million positive impact, while a decrease in natural gas prices contributed a $25.0 million negative impact.
For the year ended December 31, 2020, our natural gas sales averaged 197.6 MMcf/d. Natural gas sales volumes increased by 12% to 72,311 MMcf for the year ended December 31, 2020 as compared to 64,710 MMcf for the year ended December 31, 2019. The volume increase was primarily due to the completion of 45 gross wells for the year ended December 31, 2020. The increased production from these new wells was partially offset by the natural decline of our existing producing properties.
The average price we realized on the sale of our natural gas was $1.34 per Mcf for the year ended December 31, 2020 compared to $1.68 per Mcf for the year ended December 31, 2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative commodity price environment due to oversupply and a decrease in demand.
NGL sales revenues. NGL sales revenues increased by $2.1 million to $77.2 million for the year ended December 31, 2020 as compared to NGL sales revenues of $75.1 million for the year ended December 31, 2019. An increase in sales volumes between these periods contributed a $21.6 million positive impact, while a decrease in price contributed a $19.4 million negative impact.
For the year ended December 31, 2020, our NGL sales averaged 21.7 MBbl/d. NGL sales volumes increased by 29% to 7,945 MBbl for the year ended December 31, 2020 as compared to 6,164 MBbl for the year ended December 31, 2019. The volume increase is primarily due to the completion of 45 gross wells for the year ended December 31, 2020. The increased production from these new wells was partially offset by the natural decline of our existing producing properties. Our NGL sales are directly associated with our natural gas sales because our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $9.72 per Bbl for the year ended December 31, 2020 compared to $12.18 per Bbl for the year ended December 31, 2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative commodity price environment due to oversupply and a decrease in demand.
Lease operating expenses ("LOE"). Our LOE, decreased by $19.5 million to $77.8 million for the year ended December 31, 2020, from $97.3 million for the year ended December 31, 2019. The decrease in LOE was primarily the result of optimization of our field cost structure during the year ended December 31, 2020. On a per unit basis, LOE decreased to $2.39 per BOE sold for the year ended December 31, 2020 from $3.00 per BOE sold for the year ended December 31, 2019.
Transportation and gathering. Our T&G expense increased by $85.5 million to $138.6 million for the year ended December 31, 2020, from $53.1 million for the year ended December 31, 2019. The increase in T&G is primarily attributable to an increase of volumes on a certain gathering system and a change in oil contracts.
On a per unit basis, T&G increased to $4.26 per BOE sold for the year ended December 31, 2020 from $1.64 per BOE sold for the year ended December 31, 2019.
Production taxes. Our production taxes decreased by $39.2 million to $29.0 million for the year ended December 31, 2020 as compared to $68.2 million for the year ended December 31, 2019. The decrease was attributable to decreased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 5.2% for the year ended December 31, 2020 as compared to 7.5% for the year ended December 31, 2019. The decrease in production taxes as a percentage of sales revenue relates to a decrease in the estimated ad valorem and severance tax rates and an adjustment to the estimated ad valorem tax payable as of December 31, 2020.
Exploration and abandonment expenses. Our exploration and abandonment expenses were $258.9 million and $88.8 million for the years ended December 31, 2020 and 2019, respectively. We recognized $4.9 million in expense attributable to the extension of certain leases and $253.1 million in expense attributable to the abandonment of unproved properties for the year ended December 31, 2020. We recognized $12.4 million in expense attributable to the extension of certain leases and $73.7 million in expense attributable to the abandonment of unproved properties for the year ended December 31, 2019.
Depletion, depreciation, amortization and accretion expense. Our DD&A expense decreased $192.2 million to $332.3 million for the year ended December 31, 2020 as compared to $524.5 million for the year ended December 31, 2019. This decrease was due to an impairment of $1.3 billion of proved oil and gas properties that occurred during the fourth quarter of 2019. On a per unit basis, DD&A expense decreased from $16.20 per BOE for the year ended December 31, 2019 to $10.21 per BOE for the year ended December 31, 2020.
Impairment of long lived assets. For the year ended December 31, 2020, our impairment expense was $208.5 million, related to the impairment of other property and equipment, well equipment inventory, and the impairment of oil and gas properties in our Core DJ Basin field as the field’s fair values did not exceed the carrying amounts associated with our proved oil and gas properties. For the year ended December 31, 2019, our impairment expense was $1.3 billion. We recognized $14.5 million related to impairment of the proved oil and gas properties in our northern field and $1.3 billion of impairment expense was recognized for the year ended December 31, 2019 on proved oil and gas properties in our Core DJ Basin field.
(Gain) loss on sale of property and equipment and assets of unconsolidated subsidiary. Our gain on the sale of insignificant property was $0.1 million for the year ended December 31, 2020, as compared to a $0.4 million loss for the year ended December 31, 2019, which was related to our March 2019 Divestiture, August 2019 Divestiture and December 2019 Divestitures.
General and administrative expenses (“G&A”). General and administrative expenses decreased by $43.6 million to $55.2 million for the year ended December 31, 2020 as compared to $98.8 million for the year ended December 31, 2019. This decrease was primarily due to a decrease of $37.6 million in stock based compensation and a decrease in employed workforce of 61%, or 198 employees during the year ended December 31, 2020 compared to the year ended December 31, 2019. On a per unit basis, G&A expenses decreased by $1.35 per BOE from $3.05 per BOE sold for the year ended December 31, 2019 to $1.70 per BOE sold for the year ended December 31, 2020.
Our G&A expenses include the non-cash expense for stock-based compensation for equity awards granted to our employees and directors. For the year ended December 31, 2020, stock-based compensation expense was $6.4 million as compared to stock-based compensation expense of $44.0 million for the year ended December 31, 2019. On a per unit basis, stock-based compensation decreased $1.16 per BOE from $1.36 per BOE sold for the year ended December 31, 2019 to $0.20 per BOE sold for the year ended December 31, 2020.
Other operating expenses. Other operating expenses were $79.6 million for the year ended December 31, 2020. This amount is made up of a $46.8 million loss contingency related to an alleged breach in contract, $4.2 million of accrued interest related to the aforementioned breach in contract, a $13.2 million early termination fee related to the termination of our crude oil marketing contract, $7.6 million incurred due to workforce reductions, $4.1 million incurred in production tax interest expense, a $2.4 million early termination fee related to the termination of a drilling rig contract, and $1.3 million in expenses related to legal accruals and other.
Commodity derivative gain (loss). Primarily due to the unwinding of trades due to the commencement of the Chapter 11 Cases, coupled with the decrease in NYMEX crude oil futures prices at December 31, 2020 as compared to December 31, 2019 and change in fair value from the execution of new positions, we incurred a net gain on our commodity derivatives of $165.0 million for the year ended December 31, 2020. Primarily due to the increase in NYMEX crude oil futures prices at December 31, 2019 as compared to December 31, 2018 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of $37.1 million. These gains and losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. For the years ended December 31, 2020 and 2019, we received and paid cash settlements of commodity derivatives totaling $188.8 million and $5.8 million, respectively.
Loss on deconsolidation of Elevation Midstream, LLC. On March 16, 2020, we deconsolidated Elevation Midstream, LLC. Upon deconsolidation, we elected the fair value option to remeasure the Elevation equity method investment and determined it had no fair value. The Company recorded a $73.1 million loss on deconsolidation of Elevation Midstream, LLC in the consolidated statements of operations for the year ended December 31, 2020.
Reorganization items, net. Due to the commencement of the Chapter 11 Cases during the second quarter of 2020, we have incurred and will continue to incur significant costs associated with our reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. For the year ended December 31, 2020, we recognized $676.9 million in reorganization items. No reorganization items were recognized during the same period in the preceding year. Please see Note 6 — Reorganization Items, Net in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
Interest expense. Interest expense consists of interest expense on our long-term debt and debt issuance costs, net of capitalized interest. For the year ended December 31, 2020, we recognized interest expense of approximately $57.1 million as compared to $79.2 million for the year ended December 31, 2019, as a result of borrowings under our Prior Credit Facility, our DIP Credit Facility, our 2024 Senior Notes, our 2026 Senior Notes, and the amortization of other debt issuance costs.
We incurred interest expense for the year ended December 31, 2020 of approximately $58.8 million related to our 2024 Senior Notes, 2026 Senior Notes, Prior Credit Facility and DIP Credit Facility. We incurred interest expense for the year ended December 31, 2019 of approximately $91.5 million related to our 2024 Senior Notes, 2026 Senior Notes and Prior Credit Facility. Also included in interest expense for the years ended December 31, 2020 and 2019 was the amortization of debt issuance costs of $3.7 million and $5.5 million, respectively, and a gain on the sale of extinguishment of debt of $10.5 million for the year ended December 31, 2019. For the years ended December 31, 2020 and 2019, we capitalized interest expense of $5.3 million and $7.2 million, respectively.
Income tax (expense) benefit. We recorded no income tax expense (benefit) for the year ended December 31, 2020 resulting in an effective tax rate of approximately zero. We recorded an income tax benefit of approximately $109.2 million for the year ended December 31, 2019 resulting in an effective tax rate of approximately 7.4%. Our effective tax rate for 2020 and 2019 differs from the U.S. statutory income tax rate of 21% primarily due to the effects of state income taxes, estimated permanent taxable differences, nondeductible stock-based compensation, and the recording of a valuation allowance against deferred tax assets.
Gathering and facilities segment. Prior to March 31, 2020, we had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the “exploration and production segment”) and (ii) the construction, operation and support of midstream assets to gather and process crude oil and gas production (the “gathering and facilities segment”). Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for further information related to the deconsolidation of Elevation Midstream, LLC. After March 31, 2020, Extraction began reporting as a single reportable segment.
Our consolidated statements of operations for the year ended December 31, 2020 contains the following amounts, which were incurred during the first quarter of 2020. The gathering and facilities segment had revenues of $6.0 million and direct operating expenses of $3.9 million. General and administrative expenses were $0.7 million and depreciation expense was $1.1 million as the gathering facility was placed into service during the fourth quarter of 2019. Please see Note 18 — Segments in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
Our consolidated statements of operations for the year ended December 31, 2019 contains the following amounts. The gathering and facilities segment had revenues of $6.9 million and direct operating expenses of $2.3 million. General and administrative expenses were $4.6 million and depreciation expense was $1.4 million as the gathering facility was placed into service during the fourth quarter of 2019.
Liquidity and Capital Resources
Chapter 11 Cases and Effect of Automatic Stay
On June 14, 2020, we filed for relief under Chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Prior Credit Agreement (defined below) and the indentures governing our Senior Notes, resulting in the automatic and immediate acceleration of all of our outstanding debt under the Prior Credit Agreement and the Senior Notes. Any efforts to enforce payment obligations related to the acceleration of our debt were automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. On June 14, 2020, we also entered into the Restructuring Support Agreement (“RSA”) with certain holders of our Senior Notes to support a restructuring in accordance with the terms set forth therein. As more fully disclosed in Note 1 — Business and Organization and Note 8 — Long-Term Debt in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report, the RSA contemplated a financial restructuring which would provide for the treatment of holders of certain claims and existing equity interests. The Plan, which included substantially all terms set forth in the RSA, was approved by the Bankruptcy Court on December 23, 2020 and we emerged from bankruptcy on January 20, 2020.
We continued operations in the ordinary course for the duration of the Chapter 11 Cases funding operations with our DIP Credit Facility (as defined in Note 8 — Long-Term Debt in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report along with all capitalized debt terms in this paragraph). Upon emergence from bankruptcy, our Prior Credit Facility and DIP Credit Facility were paid off and we obtained a RBL Credit Facility discussed below.
As a result of the Chapter 11 Cases, our total available liquidity as of December 31, 2020 consisted of cash on hand of $205.9 million and $11.5 million of availability on the DIP Credit Facility. With this liquidity and funds generated from ongoing operations, we funded cash requirements throughout 2020 during the Chapter 11 proceedings. As such, we paid and expect to continue paying vendor and royalty obligations according to the terms of our current contracts.
Sources of Liquidity and Capital Resources
Historically, our primary sources of liquidity have been borrowings under our Prior Credit Facility, proceeds from notes offerings and preferred stock offerings, equity provided by investors, including our management team, cash from issuance of preferred stock, and cash flows from divestitures and from the sale of oil, gas and NGL production. Our primary uses of capital have been for the acquisition of oil and gas properties to increase our acreage position, as well as development and exploration of oil and gas properties. As of December 31, 2020, our DIP Credit Facility borrowings were $106.7 million, with $75.0 million total outstanding including amounts that were rolled over from the Prior Credit Facility. Our Prior Credit Facility borrowings were $453.7 million and $470.0 million at December 31, 2020, and December 31, 2019, respectively. We had senior notes totaling $1.1 billion outstanding at December 31, 2020 and December 31, 2019. We also have other contractual commitments, which are described in Note 16 — Commitments and Contingencies in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report.
Upon emergence from bankruptcy on January 20, 2021 indebtedness under our 2024 and 2026 Senior Notes was discharged in exchange for equity as is explained in Note 1 — Business and Organization in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report. Our Prior Credit Facility and DIP Credit Facility were paid off, terminated and replaced by our RBL Credit Facility that has a maximum commitment of $1.0 billion with an initial borrowing base and current elected lending commitments of $500.0 million. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year, with one interim “wildcard” redetermination available to us and our administrative agent between scheduled redeterminations during any 12-month period. The next scheduled redetermination will be on or around May 1, 2021.
As of the date of this filing, we have drawn $253.7 million on the RBL Credit Facility. Total funds available for borrowing under our RBL Credit Facility, after giving effect to an aggregate of $0.5 million of undrawn letters of credit, were $245.8 million as of the date of this filing. Many
We enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations, or alternatively, we may decide to unwind or restructure the hedging arrangements we previously entered into. The RBL Credit Agreement requires us to maintain commodity hedges covering a minimum of 65% of our anticipated oil and gas production from PDP reserves for the succeeding twelve months and 50% of our anticipated oil and gas production from PDP reserves for the next succeeding twelve months.
Our 2021 capital budget for the drilling and completion of operated and non-operated wells is approximately $140 million to $180 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 34 gross operated wells, complete 49 gross operated wells and turn-in-line 44 gross operated wells. Our 2021 capital budget anticipates a one-rig drilling program we expect to operate most of the provisionsyear.
We had a Stock Repurchase Program in place that ended in 2019. Spending under this program was $137.0 million and we repurchased 34.1 million shares during the TCJA have an effective date for years beginning afteryear ended December 31, 2017, including2019. We also had a Senior Notes Repurchase Program in place. Spending under this program during the loweringyear ended December 31, 2019 was $39.3 million. No common stock or Senior Notes were repurchased during the year ended December 31, 2020.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in thousands):
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 |
| Net cash provided by operating activities | $ | 265,975 | | | $ | 557,957 | |
| Net cash used in investing activities | (245,101) | | | (850,153) | |
| Net cash provided by financing activities | 160,362 | | | 89,592 | |
Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019
Net cash provided by operating activities. For the year ended December 31, 2020 as compared to the year ended December 31, 2019, our net cash provided by operating activities decreased by $292.0 million primarily due to a decrease in operating revenues net of the U.S. corporate rate from 35% to 21%. However,expenses of $377.3 million as a result of a decrease in commodity prices and a decrease of $126.3 million related to changes in working capital when excluding the enactment date$582.4 million change in accrued damages for rejected and settled contracts. Also, cash paid for reorganization items during 2020 increased $34.4 million. These reductions to cash inflows were partially offset by an increase of $90.5 million in commodity derivative settlement payments, a decrease of $46.1 million in cash paid for interest and a decrease of $6.1 million in cash paid for general and administrative expenses.
Net cash used in investing activities. For the year ended December 31, 2020 as compared to the year ended December 31, 2019, our net cash used in investing activities decreased by $605.1 million primarily due to decreased spending of $385.9 million on oil and gas property additions, $206.7 million on our gathering systems and facilities, $35.4 million on other property and equipment, and $20.0 million on investments in an unconsolidated subsidiary. During 2020, cash received from the sale of property and equipment decreased $41.9 million and cash received from the sale of assets of unconsolidated subsidiary decreased $1.0 million.
Net cash provided by financing activities. For the year ended December 31, 2020 as compared to the year ended December 31, 2019, our net cash provided by financing activities increased by $70.8 million. Net borrowings on the Prior Credit Facility decreased $54.5 million, and no cash was received in 2020 from the issuance of Elevation Preferred Units compared to $99.0 million received during 2019. These decreases were offset by an increase in net borrowings on the DIP Credit Facility of $31.7 million, a decrease in cash spent on payroll withholding taxes of $1.7 million, a decrease in Series A Preferred Stock dividends of $10.9 million, and a decrease of Preferred Unit Issuance costs of $2.5 million during 2020 compared to 2019. Additionally, during 2020 no cash was spent repurchasing common stock and senior notes, but during 2019 cash spent to repurchase common stock was $137.7 million, as result of our Share Repurchase Program, and senior notes was $39.3 million, as a result of our Senior Notes Repurchase Program.
Working Capital
Our working capital deficit at December 31, 2020 was $369.4 million and at December 31, 2019 was $240.8 million. However, as of December 22, 2017,31, 2020, many of our current liabilities in the amount of $279.6 million were classified as liabilities subject to compromise (excluding approximately $1.8 billion of debt, accrued interest, damages for rejected and settled contracts and other). Our cash balances totaled $205.9 million and $32.4 million at December 31, 2020 and 2019, respectively.
Due to the amounts that we incur related to our drilling and completion program and the timing of such expenditures, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our RBL Credit Facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil, natural gas and NGL production will be the largest variables affecting our working capital.
Debt Arrangements
For details of our debt arrangements including our RBL Credit Facility, DIP Credit Facility, Prior Credit Facility, 2024 Senior Notes and 2026 Senior Notes, please see Note 8 — Long-Term Debt in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
Equity Arrangements
For details of our equity arrangements including our Series A Preferred Stock and Elevation Preferred Units, please see Note 12 — Equity in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report.
Commitments, Contingencies and Contractual Obligations
The information responsive to Item 303 (a)(5) of Regulation S-K is not required of smaller reporting companies.
Off-Balance Sheet Arrangements
As of December 31, 2020, we do not have material off-balance sheet arrangements.
Impact of Inflation/Deflation and Pricing
All of our transactions are requireddenominated in U.S. dollars. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, as prices for oil and natural gas decrease, costs decline. Cost declines tend to remeasurelag and may not adjust downward in proportion to decline commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the deferred taxyear ended December 31, 2020, commodity prices decreased during the first and second quarters and subsequently increased in the third and fourth quarters. During the year ended December 31, 2019, commodity prices decreased during the first quarter, increased in the second quarter, and subsequently decreased in the third quarter and fourth quarter. Changes in commodity prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel.
Critical Accounting Policies and Estimates
Use of Estimates in the Preparation of Financial Statements
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the rate in which they are expected to reverse. We provisionally recorded an income tax benefit in the amount of $23.4 million related to the remeasurementdate of the net deferred tax liability. We are currently evaluating other potential impactsfinancial statements and the reported amounts of revenues and expenses during the TCJA.reporting period. Significant areas requiring the use of assumptions, judgments and estimates include:
In(1) oil and gas reserves;
(2) depreciation, depletion, amortization and accretion;
(3) cash flow estimates used in impairment testing of oil and gas proved and unproved properties;
(4) valuation of commodity derivative instruments;
(5) assigning fair value and allocating purchase price in connection with business combinations, including the IPO in October 2016, our accounting predecessor, Extraction Oil & Gas Holdings, LLC ("Holdings") was merged into the Company. Prior to this corporate reorganization, we were not subject to federal or state income taxes. Accordingly, the financial data attributable to us prior to such corporate reorganization contain no provision for federal or statedetermination of any resulting goodwill;
(6) asset retirement obligations;
(7) accrued revenue and related receivables;
(8) valuation of stock-based payments,
(9) income taxes, because the tax liability with respect to Holdings’ taxable income was passed through toand
(10) bankruptcy proceedings.
Although management believes these estimates are reasonable, actual results could differ from these estimates. We evaluate our members. Beginning October 12, 2016,estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we beganbelieve to be taxed as a C corporationreasonable under the Code and subject to federal and state income taxes at a blended statutory rate of approximately 38% of pretax earnings.circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe our estimates are reasonable.
How We Evaluate Our Operations
Successful Efforts Method of Accounting
We use a varietyfollow the successful efforts method of financial and operational metrics to assess the performance of ouraccounting for oil and gas operations, including:properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.
SourcesThe costs of revenue;exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability.
Sales volumes;Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
Realized prices
We capitalize interest, if debt is outstanding, during drilling operations in our exploration and development activities.
Oil and Gas Reserves
Our estimates of proved reserves are based on the salequantities of oil, natural gas and NGL, includingwhich, 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 under existing economic conditions, operating methods and government regulations prior to the effecttime 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. Our independent petroleum engineers, Ryder Scott, prepare a reserve and economic evaluation of all of our commodity derivative contracts;properties on a well-by-well basis. The accuracy of reserve estimates is a function of the:
Lease operating expenses (“LOE”);
Capital expenditures;•quality and quantity of available data;
Adjusted EBITDAX (a Non-GAAP measure).•interpretation of that data;
•accuracy of various mandated economic assumptions; and
•judgment of the independent reserve engineer.
SourcesOne of Our Revenues
Our revenues are derived from the salemost significant estimates we make is the estimate of our oil and natural gas production, as well as the sale of NGL that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives. For the year ended December 31, 2017, our revenues were derived 70% from oil sales, 15% fromreserves. Oil, natural gas sales and 15% from NGL sales. Forreserve estimates require significant judgments in the year ended December 31, 2016, our revenues were derived 70% from oil sales, 17% from natural gas salesevaluation of all available geological, geophysical, engineering and 13% from NGL sales. For the year ended December 31, 2015, our revenues were derived 79% from oil sales, 13% from natural gas sales and 8% from NGL sales. Our revenueseconomic data. The data for a given field may vary significantly from period to periodchange substantially over time as a result of changesnumerous factors including, but not limited to, additional development activity, production history, projected future production, economic assumptions relating to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation costs and these estimates are inherently uncertain. For example, if estimates of proved reserves decline, our DD&A rate will increase, resulting in volumesa decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of oil and gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. We cannot predict what reserve revisions may be required in future periods.
Ryder Scott estimated all of our proved reserve quantities as of December 31, 2020 and 2019. In connection with Ryder Scott performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production sold or changes in commodity prices.
Sales Volumesdata and (4) our well ownership interests.
The following table presents historical sales volumes forinformation about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our properties for the periods indicated:part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.
|
| | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Oil (MBbl) | 9,594 |
| | 5,287 |
| | 3,946 |
|
| Natural gas (MMcf) | 32,395 |
| | 20,212 |
| | 10,823 |
|
| NGL (MBbl) | 3,901 |
| | 2,284 |
| | 1,335 |
|
| Total (MBoe) | 18,894 |
| | 10,940 |
| | 7,084 |
|
| Average net sales (BOE/d) | 51,764 |
| | 29,891 |
| | 19,408 |
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 |
| Revisions resulting from price changes (MBOE) | (27,204) | | | (18,049) | |
| Revisions resulting from production, performance and other (MBOE) | (60,105) | | | (72,488) | |
| Total revisions (MBOE) | (87,309) | | | (90,537) | |
As reservoir pressures decline, production from a given well or formation decreases. GrowthDeclines in our future production and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic growth as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read “Risks Related to the Oil, Natural Gas and NGL Industry and Our Business” in Item 1A. of this Annual Report for a further description of the risks that affect us.
Realized Prices on the Sale of Oil, Natural Gas and NGL
Our results of operations depend upon many factors, particularly the price of oil, natural gas and NGL prices increase the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market. A prolonged period of depressed commodity prices may have a significant impact on the value and volumetric quantities of our abilityproved reserve portfolio, assuming no other changes to market our development plans or costs.
Depreciation, Depletion, Amortization and Accretion
Our DD&A rate is dependent upon our estimates of total proved and proved developed reserves, which incorporate various assumptions and future projections. If our estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, which in turn reduces our net income. Such a decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploration and development program, as well as future economic conditions.
Impairment of Proved Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production effectively. Oil, naturalestimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets and NGL prices are amonggoodwill in the most volatileconsolidated statements of alloperations, which increases accumulated depletion, depreciation and amortization.
Future commodity prices. For example, during the period from January 1, 2014 to December 31, 2017, average daily pricespricing for NYMEXoil is based on five-year West Texas Intermediate oilstrip prices, rangedwhich decreased 14.0% from a highan average of $107.26 per $53.65/Bbl at December 31, 2019 to a lowan average of $26.21 per Bbl. Average daily prices$46.14/Bbl at December 31, 2020. Future commodity pricing for NYMEX Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu during the same period. Declines in, and continued depression of, the price of oil and natural gas occurring during 2015 and continuing during 2017 are due to a combination of factors including increased U.S. supply, global economic concerns and geopolitical risks. These price variations can have a material impact on our financial results and capital expenditures.
Oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and international politics. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. In the DJ Basin, oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials.
Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEXbased on five-year Henry Hub price as a resultstrip prices, which increased 4.9% from an average of quality and location differentials. For example, wet natural gas with a high Btu content sells$2.42/MMBtu at a premiumDecember 31, 2019 to low Btu content dry natural gas because it yields a greater quantityan average of NGL. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant, generally in the form of percentage of proceeds. The price we receive$2.54/MMBtu at December 31, 2020. Future commodity pricing for our natural gas produced in the DJ BasinNGLs is based on CIGfive-year WTI strip prices, adjusted for certain deductions.which decreased 10.7% from an average of $14.40/Bbl at December 31, 2019 to an average of $12.85/Bbl at December 31, 2020.
Our price for NGL producedimpairment analysis requires us to apply judgment in the DJ Basin is based on a combinationidentifying impairment indicators and estimating future cash flows of prices from the Conway hub in Kansas and Mont Belvieu in Texas where this production is marketed.
The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil, natural gas and NGL normally sells at a discount to the NYMEX WTI and NYMEX Henry Hub price, as applicable.
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Oil | | | | | |
| NYMEX WTI High ($/Bbl) | $ | 60.42 |
| | $ | 54.06 |
| | $ | 61.43 |
|
| NYMEX WTI Low ($/Bbl) | $ | 42.53 |
| | $ | 26.21 |
| | $ | 34.73 |
|
| NYMEX WTI Average ($/Bbl) | $ | 50.85 |
| | $ | 43.47 |
| | $ | 48.76 |
|
| Average Realized Price ($/Bbl) | $ | 43.77 |
| | $ | 36.70 |
| | $ | 39.80 |
|
| Average Realized Price, with derivative settlements ($/Bbl) | $ | 41.67 |
| | $ | 40.59 |
| | $ | 53.29 |
|
| Average Realized Price as a % of Average NYMEX WTI | 86.1 | % | | 84.4 | % | | 81.6 | % |
| Differential ($/Bbl) to Average NYMEX WTI | $ | (7.08 | ) | | $ | (6.77 | ) | | $ | (8.96 | ) |
| Natural Gas | | | | | |
| NYMEX Henry Hub High ($/MMBtu) | $ | 3.42 |
| | $ | 3.93 |
| | $ | 3.23 |
|
| NYMEX Henry Hub Low ($/MMBtu) | $ | 2.56 |
| | $ | 1.64 |
| | $ | 1.76 |
|
| NYMEX Henry Hub Average ($/MMBtu) | $ | 3.02 |
| | $ | 2.55 |
| | $ | 2.63 |
|
| Average Realized Price ($/Mcf) | $ | 2.85 |
| | $ | 2.41 |
| | $ | 2.40 |
|
| Average Realized Price, with derivative settlements ($/Mcf) | $ | 2.90 |
| | $ | 2.81 |
| | $ | 2.82 |
|
Average Realized Price as a % of Average NYMEX Henry Hub(1) | 85.8 | % | | 85.9 | % | | 83.0 | % |
Differential ($/Mcf) to Average NYMEX Henry Hub(1) | $ | (0.47 | ) | | $ | (0.40 | ) | | $ | (0.49 | ) |
| NGL | | | | | |
| Average Realized Price ($/Bbl) | $ | 23.60 |
| | $ | 15.49 |
| | $ | 11.02 |
|
| Average Realized Price as a % of Average NYMEX WTI | 46.4 | % | | 35.6 | % | | 22.6 | % |
| |
(1) | Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf using a conversion factor of 1.1 to 1. |
Derivative Arrangements
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our oil and natural gas production. By removing a significant portionproperties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.
For the year ended December 31, 2020, our impairment expense related to oil and gas properties was $197.9 million. We recognized $3.6 million related to impairment of price volatilitythe proved oil and gas properties in our northern field and $194.3 million related to assets in one of our Core DJ Basin fields, as the fields’ fair values did not exceed the carrying amounts associated with our proved oil production, we believe we will mitigate, but not eliminate,and gas properties. For the potential negative effectsyear ended December 31, 2019, our impairment expense was $1.3 billion. We recognized $14.5 million related to impairment of reductionsthe proved oil and gas properties in oil prices on our cash flow from operations for those periods. However,northern field and $1.3 billion related to assets in a portionone of our current positions,Core DJ Basin fields as the fields’ fair values did not exceed the carrying amounts associated with our hedging activity may also reduce our ability to benefit from increases inproved oil and natural gas prices. We will sustain losses toproperties.
the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our derivatives contract prices are higher than market prices. In certain circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. See “—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes inForward commodity prices and our commodity derivative contracts.
We will continue to use commodity derivative instruments to hedge our price riskestimates of future production play a significant role in the future. Our hedging strategydetermining impairment of proved oil and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis.gas properties. As a result of recent volatilitylower commodity prices and their impact on our estimated future cash flows, we will continue to review our proved oil and gas properties for impairment. After our fourth quarter 2020 impairment charges in two of our Core DJ Basin fields at December 31, 2020, the carrying value of our oil and gas properties exceeded our expected undiscounted future cash flows for proved and risk-adjusted probable and possible reserves by approximately $56.8 million and $340.3 million, in each field. After our fourth quarter 2019 impairment charges in two of our Core DJ Basin fields at
December 31, 2019, the carrying value of our oil and gas properties exceeded our expected undiscounted future cash flows for proved and risk-adjusted probable and possible reserves by approximately $33.8 million and $1.2 billion, in each field. At December 31, 2018, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $0.8 billion, or 30%.
Abandonment of Unproved Oil and Gas Properties
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. We evaluate significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration and abandonment expenses in the priceconsolidated statements of oiloperations. As a result of the abandonment of unproved properties, we recognized $253.1 million and natural gas,$73.7 million in abandonment expense for the years ended December 31, 2020 and 2019, respectively. To the extent we have relied on a variety of hedging strategies and instrumentsdo not elect to hedge our future price risk. renew current leases, we expect further abandonment charges in 2021.
Commodity Derivative Instruments
We have utilizedentered into commodity derivative instruments utilizing swaps put options, and call options, which in some instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas production. We expect to continue to useFor a varietydescription of hedging strategiesour derivative instruments that we utilize and instruments for the foreseeable future.a summary of our open commodity derivative contracts as of December 31, 2020, please see Note 9 — Commodity Derivative Instruments in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
A swap hasThe commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets or liabilities. We have not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, we do not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivative gain (loss) line on the consolidated statements of operations. Our cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in our consolidated statements of cash flows.
Our valuation estimate takes into consideration the counterparties’ credit worthiness, our credit worthiness, and the time value of money. The consideration of the factors results in an established fixed price. Whenestimated exit-price for each derivative asset or liability under a market participant’s view. We believe that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please see “—How We Evaluate Our Operations—Derivative Arrangements.”
Accounting for Business Combinations
We account for all of our business combinations using the settlementacquisition method, which is the only method permitted under ASC 805, Business Combinations, and involves the use of significant judgment. In connection with a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is belowrecorded as a gain on bargain purchase or goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the fixed price,values attributed to assets acquired and liabilities assumed.
In estimating the counterparty pays us an amount equalfair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the difference betweenestimated fair values assigned to proved and unproved oil and gas properties. If sufficient market data is not available regarding the settlement pricefair values of proved and unproved properties, we must prepare estimates. To estimate the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price,fair values of these properties, we pay our counterparty an amount equalprepare estimates of gas, oil and NGL reserves. We estimate future prices to apply to the difference betweenestimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the settlement price and the fixed price multiplied by the hedged contract volume.
A put option has an established floor price. The buyerfuture net cash flows are discounted using a market-based weighted average cost of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of our purchased put options have deferred premiums. For the deferred premium puts, we agreed to pay a premium to the counterpartycapital rate determined appropriate at the time of settlement.the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future net cash flows of probable and possible reserves are reduced by additional risk factors. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.
Asset Retirement Obligations
A call option hasOur asset retirement obligations (“ARO”) consist of estimated future costs associated with the plugging and abandonment of oil, natural gas and NGL wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws, and applicable lease terms. The fair value of an established ceiling price. The buyer ofARO liability is required to be recognized in the call option pays the seller a premium to enter into the call option. When the settlement priceperiod in which it is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
We combine swaps, purchased put options, sold put options, and sold call options in order to achieve various hedging strategies. Some examples of our hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options, and sold call options, and enhanced swaps, which include either sold put options or sold call optionsincurred, with the associated premiums rolled into an enhanced fixed price swap. We have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices.
We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements at favorable prices may be limited, and we are not obligated to hedge a specific portion of our oil or natural gas production. The following summarizes our derivative positions related to crude oil and natural gas sales in effectasset retirement cost capitalized as of December 31, 2017:
|
| | | | | | | |
| | 2018 | | 2019 |
NYMEX WTI Crude Swaps: | | | |
| Notional volume (Bbl) | 5,100,000 |
| | — |
|
| Weighted average fixed price ($/Bbl) | $ | 51.61 |
| | |
NYMEX WTI Crude Sold Calls: | |
| | |
| Notional volume (Bbl) | 8,290,000 |
| | 5,100,000 |
|
| Weighted average sold call price ($/Bbl) | $ | 56.18 |
| | $ | 55.93 |
|
NYMEX WTI Crude Sold Puts: | |
| | |
| Notional volume (Bbl) | 13,438,800 |
| | 5,100,000 |
|
| Weighted average sold put price ($/Bbl) | $ | 39.10 |
| | $ | 39.82 |
|
NYMEX WTI Crude Purchased Puts: | |
| | |
| Notional volume (Bbl) | 12,327,600 |
| | 5,100,000 |
|
| Weighted average purchased put price ($/Bbl) | $ | 44.81 |
| | $ | 49.69 |
|
NYMEX HH Natural Gas Swaps: | |
| | |
| Notional volume (MMBtu) | 40,800,000 |
| | — |
|
| Weighted average fixed price ($/MMBtu) | $ | 3.10 |
| | |
NYMEX HH Natural Gas Purchased Puts: | |
| | |
| Notional volume (MMBtu) | 2,400,000 |
| | — |
|
| Weighted average purchased put price ($/MMBtu) | $ | 3.00 |
| | |
NYMEX HH Natural Gas Sold Calls: | |
| | |
| Notional volume (MMBtu) | 2,400,000 |
| | — |
|
| Weighted average sold call price ($/MMBtu) | $ | 3.15 |
| | |
CIG Basis Gas Swaps: | |
| | |
| Notional volume (MMBtu) | 6,300,000 |
| | — |
|
| Weighted average fixed basis price ($/MMBtu) | $ | (0.31 | ) | | |
The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated.
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
NYMEX HH Natural Gas Swaps: | | | | | |
| Notional volume (MMBtu) | 25,240,000 |
| | 13,194,600 |
| | 6,444,552 |
|
| Weighted average fixed price ($/MMBtu) | $ | 3.05 |
| | $ | 3.13 |
| | $ | 3.27 |
|
CIG Basis Gas Swaps: | | | | | |
| Notional volume (MMBtu) | 12,615,000 |
| | 2,970,000 |
| | — |
|
| Weighted average fixed basis price ($/MMBtu) | $ | (0.34 | ) | | $ | (0.19 | ) | | |
NYMEX WTI Crude Swaps: | | | | | |
| Notional volume (Bbl) | 4,125,000 |
| | 1,989,060 |
| | 1,293,769 |
|
| Weighted average fixed price ($/Bbl) | $ | 48.02 |
| | $ | 41.87 |
| | $ | 76.24 |
|
NYMEX WTI Crude Sold Puts: | | | | | |
| Notional volume (Bbl) | 7,720,000 |
| | 2,100,000 |
| | — |
|
| Weighted average strike price ($/Bbl) | $ | 37.67 |
| | $ | 44.93 |
| | |
NYMEX WTI Crude Purchased Puts: | | | | | |
| Notional volume (Bbl) | 5,570,000 |
| | 4,724,150 |
| | 1,943,588 |
|
| Weighted average strike price ($/Bbl) | $ | 45.18 |
| | $ | 51.82 |
| | $ | 57.67 |
|
NYMEX WTI Crude Sold Calls: | | | | | |
| Notional volume (Bbl) | 4,620,000 |
| | 2,786,090 |
| | 1,943,588 |
|
| Weighted average strike price ($/Bbl) | $ | 54.70 |
| | $ | 59.44 |
| | $ | 67.21 |
|
NYMEX WTI Crude Purchased Calls: | | | | | |
| Notional volume (Bbl) | 750,000 |
| | 216,000 |
| | — |
|
| Weighted average strike price ($/Bbl) | $ | 61.32 |
| | $ | 69.58 |
| | |
| Total Amounts Received/(Paid) from Settlement (in thousands) | $ | (18,031 | ) | | $ | 34,196 |
| | $ | 59,785 |
|
| Cash provided by (used in) changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives | $ | 6,046 |
| | $ | 8,631 |
| | $ | (4,015 | ) |
| Cash Settlements on Commodity Derivatives per Consolidated Statements of Cash Flows | $ | (11,985 | ) | | $ | 42,827 |
| | $ | 55,770 |
|
Lease Operating Expenses
All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expensescarrying cost of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, water injectionthe oil and disposal costs, allocated overhead charges, workover, insurancegas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and other expenses incidentaltiming of settlements; the credit-adjusted risk-free discount rate to production, but exclude lease acquisitionbe used; and inflation rates. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or drilling or completion expenses. LOE also includes expenses incurredthe amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to gatherthe passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and delivergas property.
Revenue Recognition
Revenue from the sale of oil, natural gas and NGLs is recognized in accordance with ASC 606 - Revenue from Contracts with Customers five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. To account for producer imbalances, we recognize revenues on all sales of oil, natural gas and NGLs to third party customers regardless of their ownership percentage and adjust the underlifter or overlifter’s claim on the asset’s remaining reserves. In other words, revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. A receivable or liability is recognized only to the processing plant and/or selling point.extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. We receive payment one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A 10% change in our revenue accrual would have impacted total operating revenues by approximately $6.3 million and $10.5 million for the years ended December 31, 2020 and 2019, respectively.
Stock-Based Payments
We granted awards under the 2016 LTIP and 2021 LTIP (as defined in Note 14 — Stock-Based Compensation in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report) to certain directors, officers and employees, including stock options, restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards which therefore required us to recognize the expense in our consolidated financial statements.
All stock-based payments to employees are measured at fair value on the grant date and expensed over the relevant service period. The fair value of stock option awards is determined by using the Black-Scholes option pricing model. The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. All stock-based payment expense is recognized using the straight-line method and is included within general and administrative expenses in the consolidated statements of operations and stock-based compensation in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 14 — Stock-Based Compensation in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for additional discussion on stock-based payments.
Capital Expenditures
For the year ended December 31, 2017,2020, we incurred approximately $864.5$159.6 million excluding outstanding elections, in drilling 186and completion capital expenditures. For the year ended December 31, 2020, we drilled 37 gross (137.4(25.7 net) wells with an average lateral length of 1.7approximately 2.3 miles and completing 198completed 45 gross (158.9(34.1 net) wells with an average lateral length of 1.7approximately 2.4 miles. We turned to sales 49 gross (36.5 net) wells with an average lateral length of approximately 2.4 miles. In addition, we incurred approximately $73.2$16.9 million of leasehold and surface acreage additions, excluding acquisitions,additions.
Our 2021 capital budget for the drilling and completion of operated and non-operated wells is approximately $10.9 million of midstream, excluding acquisitions. Our 2017 revised budget allocated approximately $865$140 million to $885 million to the drilling of 185 to 190 gross operated wells and the completion of 190 to 195 gross operated wells, approximately $60.0 million to $80.0 million to undeveloped leasehold, midstream and other capital expenditures, excluding amounts that were paid for acquisitions.
Our 2018 capital budget is approximately $890 million to $990$180 million, substantially all of which we intend to allocate to the Core DJ Basin. We intend to allocate approximately $770 million to $840 million of our 2018 capital budget to operated and non-operated drilling and completion of new wells. We expect to drill 170 to 17534 gross operated wells, complete 49 gross operated wells and complete 185 to
190turn-in-line 44 gross operated wells. Approximately $120 million to $150 million is expected to be allocated to organic undeveloped acreage leasing, midstream, and other capital expenditures. Our 2021 capital budget anticipates a two to three operated rigone-rig drilling program and excludes any amounts that were or may be paid for potential acquisitions.we expect to operate most of the year.
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer or accelerate a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.
Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income (loss) as determined by United States generally accepted accounting principles ("GAAP").GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss)loss adjusted for certain cash and non-cash items, including depletion, depreciation, amortization and accretion ("DD&A")(DD&A), impairment of long lived assets, non-recurring charges in other operating expenses, exploration and abandonment expenses, rig termination fees, acquisition transaction expenses,(gain) loss on sale of property and equipment, commodity derivativederivatives (gain) loss, settlements on commodity derivatives,derivative instruments, premiums paid for derivatives that settled during the period, unit and stock-based compensation expense, amortization of debt discount and debt issuance costs, interest expense, gain on repurchase of senior notes, income taxestax benefit, loss on deconsolidation of Elevation Midstream, LLC and non-recurring charges.reorganization items, net. Adjusted EBITDAX is also used to evaluate the performance of reportable segments. See Note 18 — Segment Information in Part II, Item 8 of this Annual Report for more information regarding the EBITDAX of reportable segments.
Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company'scompany’s financial performance, such as a company'scompany’s cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
measure (i) is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors;
(ii) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and
(iii) is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting. Adjusted EBITDAX is also used by our Board of Directors as a performance measure in determining executive compensation.
The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss)loss to Adjusted EBITDAX for each of the periods indicated (in thousands).
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2020 | | 2019 |
| Reconciliation of Net Loss to Adjusted EBITDAX: | | | |
| Net Loss | $ | (1,267,534) | | | $ | (1,367,420) | |
| Add back: | | | |
| Depletion, depreciation, amortization and accretion | 332,319 | | | 524,537 | |
| Impairment of long lived assets | 208,463 | | | 1,337,996 | |
| Other operating expenses | 79,615 | | | — | |
| Exploration and abandonment expenses | 258,932 | | | 88,794 | |
| (Gain) loss on sale of property and equipment | (122) | | | 421 | |
| Commodity derivative (gain) loss | (164,968) | | | 37,107 | |
| Settlements on commodity derivative instruments | 188,822 | | | (5,790) | |
| Premiums paid for derivatives that settled during the period | — | | | (18,929) | |
| Stock-based compensation expense | 6,511 | | | 43,954 | |
| Amortization of debt issuance costs | 3,685 | | | 5,482 | |
| Interest expense | 53,458 | | | 84,236 | |
| Gain on repurchase of 2026 Senior Notes | — | | | (10,486) | |
| Income tax benefit | — | | | (109,176) | |
| Loss on deconsolidation of Elevation Midstream, LLC | 73,139 | | | — | |
| Reorganization items, net | 676,855 | | | — | |
| Adjusted EBITDAX | $ | 449,175 | | | $ | 610,726 | |
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Reconciliation of Net Loss to Adjusted EBITDAX: | | | | | |
| Net loss | $ | (44,408 | ) | | $ | (456,001 | ) | | $ | (47,264 | ) |
| Add back: | |
| | |
| | |
|
| Depreciation, depletion, amortization, and accretion | 314,999 |
| | 205,348 |
| | 146,547 |
|
| Impairment of long lived assets | 1,647 |
| | 23,425 |
| | 15,778 |
|
| Exploration expenses | 36,256 |
| | 36,422 |
| | 18,636 |
|
| Rig termination fee | — |
| | 891 |
| | 1,657 |
|
| Write-off of deposit on acquisition | — |
| | 10,000 |
| | — |
|
| Loss on sale of property and equipment | 451 |
| | — |
| | — |
|
| Acquisition transaction expenses | — |
| | 2,719 |
| | 6,000 |
|
| (Gain) loss on commodity derivatives | 36,332 |
| | 100,947 |
| | (79,932 | ) |
| Settlements on commodity derivative instruments | (18,031 | ) | | 34,196 |
| | 59,785 |
|
| Premiums paid for derivatives that settled during the period | (580 | ) | | (5,553 | ) | | (2,087 | ) |
| Unit and stock-based compensation expense | 65,607 |
| | 200,308 |
| | 5,970 |
|
| Amortization of debt discount and debt issuance costs | 4,260 |
| | 19,256 |
| | 5,604 |
|
| Interest expense | 47,629 |
| | 49,587 |
| | 45,426 |
|
| Income tax benefit | (63,700 | ) | | (29,280 | ) | | — |
|
| Adjusted EBITDAX | $ | 380,462 |
| | $ | 192,265 |
| | $ | 176,120 |
|
Our Free Cash Flow is not a measure of net income (loss) as determined by GAAP. We define Free Cash Flow as Discretionary Cash Flow (non-GAAP) less Adjusted Cash Flow used in Investing (non-GAAP) adjusted for Other Non-Recurring Adjustments (non-GAAP). Discretionary Cash Flow is defined as net cash provided by operating activities (GAAP) less changes in working capital (current assets and liabilities). Adjusted Cash Flow used in Investing is defined as cash flow used in investing activities (GAAP) adjusted for changes in accounts payable and accrued liabilities related to capital expenditures.
Free Cash Flow is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Free Cash Flow can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe Free Cash Flow provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities, construct and support midstream assets, and to return capital to stockholders.
The following tables present a reconciliation of Discretionary Cash Flow and Free Cash Flow to the GAAP financial measure of net cash provided by operating activities for each of the periods indicated.
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Year Ended December 31, 2020 |
| Cash Flow from Operating Activities | | | | | |
| Net cash provided by operating activities | $ | 263,095 | | | $ | 2,880 | | | $ | 265,975 | |
| Changes in current assets and liabilities | (695,436) | | | (1,907) | | | (697,343) | |
| Discretionary Cash Flow | $ | (432,341) | | | $ | 973 | | | $ | (431,368) | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | $ | (239,261) | | | $ | (5,840) | | | $ | (245,101) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | 74,247 | | | 2,210 | | | 76,457 | |
| Adjusted Cash Flow used in Investing | $ | (165,014) | | | $ | (3,630) | | | $ | (168,644) | |
| | | | | |
| Other Non-Recurring Adjustments (1) | $ | 1,729 | | | $ | — | | | $ | 1,729 | |
| Other Non-Recurring Adjustments (2) | $ | 582,439 | | | $ | — | | | $ | 582,439 | |
| | | | | |
| Free Cash Flow | $ | (13,187) | | | $ | (2,657) | | | $ | (15,844) | |
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Year Ended December 31, 2019 |
| Cash Flow from Operating Activities | | | | | |
| Net cash provided by operating activities | $ | 554,171 | | | $ | 3,786 | | | $ | 557,957 | |
| Changes in current assets and liabilities | 10,589 | | | 829 | | | 11,418 | |
| Discretionary Cash Flow | $ | 564,760 | | | $ | 4,615 | | | $ | 569,375 | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | $ | (623,506) | | | $ | (226,647) | | | $ | (850,153) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | 23,372 | | | 428 | | | 23,800 | |
| Adjusted Cash Flow used in Investing | $ | (600,134) | | | $ | (226,219) | | | $ | (826,353) | |
| | | | | |
| Other Non-Recurring Adjustments (1) | $ | 16,496 | | | $ | — | | | $ | 16,496 | |
| | | | | |
| Free Cash Flow | $ | (18,878) | | | $ | (221,604) | | | $ | (240,482) | |
(1) Amount incurred for the construction of our field office that is included in other property and equipment in our consolidated statements of cash flows.
(2) Amount of accrued damages for rejected and settled contracts within changes in current assets and liabilities on the consolidated statements of cash flows.
Items Affecting the Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, for the reasons described below:
On December 22, 2017,•During the TCJA was enacted making significant changes to the Internal Revenue Code. WeChapter 11 Cases, our financial results have calculatedbeen volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impacted our best estimate of the impact of the TCJA in our year-end income tax provision in accordance with our understanding of the TCJA and guidance available as of the date of this filing. Many of the provisions in the TCJA have an effective date for years beginning after December 31, 2017, including the lowering of the U.S. corporate rate from 35% to 21%. However, as a result of the enactment date of December 22, 2017, we are required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. We provisionally recorded an income tax benefit in the amount of $23.4 million related to the remeasurement of the net deferred tax liability.
In connection with the consummation of the IPO, we issued 185,280 shares of our Series A Preferred Stock to the holders of Holdings’ Series B Preferred Units in conversion of such units. The Series A Preferred Stock are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and we have the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are paid in cash).
We incur additional general and administrative expenses related to being a public company, including Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley Act compliance; expenses associated with listing on the NASDAQ Global Select Market; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and directors compensation.
Prior to our initial public offering, we were not subject to federal or state income taxes. Accordingly, the financial data attributable to us prior to such corporate reorganization contain no provision for federal or state income taxes
because the tax liability with respect to Holdings’ taxable income was passed through to its members. Beginning October 12, 2016, we began to be taxed as a C corporation under the Code and subject to federal and state income taxes at a blended statutory rate of approximately 38% of pretax earnings.
In October 2016, our board of directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan ("LTIP") and subsequently granted awards to certain directors, officers and employees, including stock options, restricted stock units and performance stock awards. We recognized $48.3 million and $8.5 million of stock-based compensation expense for years ended December 31, 2017 and 2016, respectively, related to these awards.
On October 3, 2016, we acquired additional oil and gas properties primarily located in the Wattenberg Field located primarily around our existing Greeley and Windsor areas. The October 2016 Acquisition consisted of working interest in approximately 6,400 net acres and 31 gross (19 net) drilled but uncompleted wells, as of the date of acquisition. The October 2016 Acquisition provided net daily production of approximately 6,900 BOE/d.
In 2015, we granted certain members of management incentive units pursuant to Holdings’ 2014 Membership Unit Incentive Plan and its limited liability company agreement. These equity-based awards are subject to time-based vesting requirements, as well as accelerated vesting upon the occurrence of a change of control. In connection with the IPO, the Board of Managers of Holdings accelerated the vesting of the Holdings’ Incentive Units. Our IPO and change of control triggered the conversion of these units into approximately 9.1 million of our common shares based on the 10-day volume weighted average price of our common stock following its IPO as set forth in the 2014 Plan and the Holdings LLC Agreement.results. For the year ended December 31, 2016,2020, we incurred $676.9 million of reorganization items net as compared to none in 2019. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. The Company emerged from the Chapter 11 proceedings on January 20, 2021, however claim assessments will continue for months longer.
•Elevation Midstream, LLC was deconsolidated as of March 16, 2020 and accounted for as an equity method investment. We elected the fair value option to remeasure the Elevation Midstream, LLC equity method investment and determined it had no fair value. We recorded a $73.1 million loss on deconsolidation of Elevation Midstream, LLC in the consolidated statements of operations for the year ended December 31, 2020. Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for information related to the deconsolidation of Elevation Midstream, LLC.
•For the years ended December 31, 2020 and 2019 we recognized approximately $172.1$194.3 million and $1.3 billion, respectively, in non-cash, share-based compensationimpairment expense on our oil and gas properties related to assets in connection withour Core DJ Basin field and to a much lesser extent in our northern field.
•For the conversionyears ended December 31, 2020 and 2019, respectively, exploration and abandonment expenses increased primarily due to the abandonment of the Holdings’ Incentive Units into our common stock.$253.1 million and $73.7 million of unproved properties.
On March 10, 2015, we acquired interests in approximately 39,000 net acres
Table of leasehold and related producing properties located primarily in Adams, Broomfield, Boulder and Weld Counties, Colorado, along with various related rights, permits, contracts, equipment and other assets (the "March 2015 Acquisition"). The March 2015 Acquisition included 444 producing wells and, at the time of acquisition, had net daily production of approximately 1,100 BOE/d.Contents
Historical Results of Operations and Operating Expenses
Oil, Natural Gas and NGL Sales Revenues, Operating Expenses and Other Income (Expense).
The following table provides theFor components of our revenues, operating expenses, other income (expense) and net loss for the periods indicated (in thousands):
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Revenues: | | | | | |
| Oil sales | $ | 419,904 |
| | $ | 194,059 |
| | $ | 157,024 |
|
| Natural gas sales | 92,322 |
| | 48,652 |
| | 26,019 |
|
| NGL sales | 92,070 |
| | 35,378 |
| | 14,707 |
|
| Total Revenues | 604,296 |
| | 278,089 |
| | 197,750 |
|
| Operating Expenses: | |
| | |
| | |
|
| Lease operating expenses | 111,306 |
| | 62,043 |
| | 30,628 |
|
| Production taxes | 51,367 |
| | 20,730 |
| | 17,035 |
|
| Exploration expenses | 36,256 |
| | 36,422 |
| | 18,636 |
|
| Depletion, depreciation, amortization and accretion | 314,999 |
| | 205,348 |
| | 146,547 |
|
| Impairment of long lived assets | 1,647 |
| | 23,425 |
| | 15,778 |
|
| Other operating expenses | 451 |
| | 10,891 |
| | 2,353 |
|
| Acquisition transaction expenses | — |
| | 2,719 |
| | 6,000 |
|
| General and administrative expenses | 110,167 |
| | 232,388 |
| | 37,149 |
|
| Total Operating Expenses | 626,193 |
| | 593,966 |
| | 274,126 |
|
| Operating Loss | (21,897 | ) | | (315,877 | ) | | (76,376 | ) |
| Other Income (Expense): | |
| | |
| | |
|
| Commodity derivatives gain (loss) | (36,332 | ) | | (100,947 | ) | | 79,932 |
|
| Interest expense | (51,889 | ) | | (68,843 | ) | | (51,030 | ) |
| Other income | 2,010 |
| | 386 |
| | 210 |
|
| Total Other Income (Expense) | (86,211 | ) | | (169,404 | ) | | 29,112 |
|
| Net Loss Before Income Taxes | (108,108 | ) | | (485,281 | ) | | (47,264 | ) |
| Income Tax Benefit | 63,700 |
| | 29,280 |
| | — |
|
| Net Loss | $ | (44,408 | ) | | $ | (456,001 | ) | | $ | (47,264 | ) |
income (loss), please see our consolidated statements of operations in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report. The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2020 | | 2019 |
| Sales (MBoe): (1) | 32,540 | | | 32,385 | |
| Oil sales (MBbl) | 12,543 | | | 15,436 | |
| Natural gas sales (MMcf) | 72,311 | | | 64,710 | |
| NGL sales (MBbl) | 7,945 | | | 6,164 | |
| Sales (BOE/d): (1) | 88,907 | | | 88,728 | |
| Oil sales (Bbl/d) | 34,270 | | | 42,291 | |
| Natural gas sales (Mcf/d) | 197,570 | | | 177,288 | |
| NGL sales (Bbl/d) | 21,708 | | | 16,889 | |
| Average sales prices: (2) | | | |
| Oil sales (per Bbl) (3) | $ | 30.50 | | | $ | 46.74 | |
| Oil sales with derivative settlements (per Bbl) (3) | 37.15 | | | 45.16 | |
| Natural gas sales (per Mcf) | 1.34 | | | 1.68 | |
| Natural gas sales with derivative settlements (per Mcf) | 1.47 | | | 1.68 | |
| NGL sales (per Bbl) | 9.72 | | | 12.18 | |
| Average price (per BOE) (3) | 17.10 | | | 27.96 | |
| Average price with derivative settlements (per BOE) (3) | 19.95 | | | 27.19 | |
| Expense per BOE: (1) | | | |
| Lease operating expenses | $ | 2.39 | | | $ | 3.00 | |
| Transportation and gathering | 4.26 | | | 1.64 | |
| Production taxes | 0.89 | | | 2.11 | |
| Exploration and abandonment expenses | 7.96 | | | 2.74 | |
| Depletion, depreciation, amortization, and accretion | 10.21 | | | 16.20 | |
| General and administrative expenses | 1.70 | | | 3.05 | |
| Cash general and administrative expenses | 1.50 | | | 1.69 | |
| Stock-based compensation | 0.20 | | | 1.36 | |
| Total operating expenses per BOE (4) | 27.41 | | | 28.74 | |
| | | |
| Production taxes as a percentage of revenue | 5.2 | % | | 7.5 | % |
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
Sales (MBoe)(1): | 18,894 |
| | 10,940 |
| | 7,084 |
|
| Oil sales (MBbl) | 9,593.7 |
| | 5,287.4 |
| | 3,945.6 |
|
| Natural gas sales (MMcf) | 32,395.2 |
| | 20,211.5 |
| | 10,823.0 |
|
| NGL sales (MBbl) | 3,900.9 |
| | 2,284.0 |
| | 1,334.6 |
|
Sales (BOE/d)(1): | 51,764 |
| | 29,891 |
| | 19,408 |
|
| Oil sales (Bbl/d) | 26,284 |
| | 14,446 |
| | 10,810 |
|
| Natural gas sales (Mcf/d) | 88,754 |
| | 55,223 |
| | 29,652 |
|
| NGL sales (Bbl/d) | 10,687 |
| | 6,240 |
| | 3,656 |
|
Average sales prices(2): | | | | | |
| Oil sales (per Bbl) | $ | 43.77 |
| | $ | 36.70 |
| | $ | 39.80 |
|
| Oil sales with derivative settlements (per Bbl) | 41.67 |
| | 40.59 |
| | 53.29 |
|
| Natural gas sales (per Mcf) | 2.85 |
| | 2.41 |
| | 2.40 |
|
| Natural gas sales with derivative settlements (per Mcf) | 2.90 |
| | 2.81 |
| | 2.82 |
|
| NGL sales (per Bbl) | 23.60 |
| | 15.49 |
| | 11.02 |
|
| Average price per BOE | 31.98 |
| | 25.42 |
| | 27.92 |
|
| Average price per BOE with derivative settlements | 31.00 |
| | 28.04 |
| | 36.06 |
|
Expense per BOE(1): | |
| | |
| | |
|
| Lease operating expenses | $ | 5.89 |
| | $ | 5.67 |
| | $ | 4.32 |
|
| Operating expenses | 3.19 |
| | 3.36 |
| | 3.39 |
|
| Transportation and gathering | 2.70 |
| | 2.31 |
| | 0.93 |
|
| Production taxes | 2.72 |
| | 1.89 |
| | 2.40 |
|
| Exploration expenses | 1.92 |
| | 3.33 |
| | 2.63 |
|
| Depletion, depreciation, amortization, and accretion | 16.67 |
| | 18.77 |
| | 20.69 |
|
| Impairment of long lived assets | 0.09 |
| | 2.14 |
| | 2.23 |
|
Other operating expenses (3) | 0.02 |
| | 1.00 |
| | 0.33 |
|
| Acquisition transaction expenses | — |
| | 0.25 |
| | 0.85 |
|
| General and administrative expenses | 5.83 |
| | 21.24 |
| | 5.24 |
|
| Cash general and administrative expenses | 2.36 |
| | 2.93 |
| | 4.40 |
|
| Unit and stock-based compensation | 3.47 |
| | 18.31 |
| | 0.84 |
|
| Total operating expenses per BOE | 33.14 |
| | 54.29 |
| | 38.69 |
|
| | | | | | |
| Production taxes as a percentage of revenue | 8.5 | % | | 7.5 | % | | 8.6 | % |
| |
(1) | One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. |
| |
(2) | Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity derivative contracts. Our calculation of such effects includes both gains and losses on cash settlements for commodity derivatives and premiums paid or received on options that settled during the period. |
| |
(3) | During the year ended December 31, 2016, we wrote off $10.0 million non-refundable deposit associated with the option to acquire additional assets from the October 2016 Acquisition. |
(1)One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2)Average prices shown in the table reflect prices both before and after the effects of our settlements of commodity derivative contracts. Our calculation of such effects includes both gains and losses on settlements for commodity derivatives and amortization of premiums paid or received on options that settled during the period.
(3)Includes amounts allocated to a satisfied performance obligation, recognized within oil sales for the years ended December 31, 2020 and December 31, 2019, pursuant to ASC 606, Revenue Recognition.
(4)Excludes midstream operating expenses, impairment of long lived assets, gain on sale of property and equipment and other operating expenses.
Year Ended December 31, 20172020 Compared to Year Ended December 31, 20162019
Oil sales revenues. Crude oil sales revenues increaseddecreased by $225.8$338.9 million to $419.9$382.5 million for the year ended December 31, 20172020 as compared to crude oil sales of $194.1$721.4 million for the year ended December 31, 2016. An increase2019. A decrease in sales volumes between these periods contributed to a $158.0$135.2 million positivenegative impact, while an increaseand a decrease in crude oil prices contributed a $67.8$203.7 million positivenegative impact. Additionally, for the year ended December 31, 2020 crude oil revenue decreased by approximately $12.3 million as compared to a crude oil revenue decrease of approximately $24.7 million for the year ended December 31, 2019 due to a contract term impacting the amount of consideration that can be included in the transaction price which reduced oil sales revenue pursuant to ASC 606.
For the year ended December 31, 2017,2020, our crude oil sales averaged 26.334.3 MBbl/d. Our crude oil sales volumes increased 81%decreased 19% to 9,593.7 MBbl in the year ended December 31, 2017 compared to 5,287.412,543 MBbl for the year ended December 31, 2016.2020 compared to 15,436 MBbl for the year ended December 31, 2019. The volume increasedecrease was primarily due to the developmentnatural decline of our properties. Forexisting producing properties, which was partially offset by an increase in production from the completion of 45 wells during the year ended December 31, 2017, we completed 198 gross wells. The increased production from these new wells was offset by the normal decline on the existing producing properties.2020.
The average price we realized on the sale of crude oil was $43.77$30.50 per Bbl for the year ended December 31, 20172020 compared to $36.70$46.74 per Bbl for the year ended December 31, 2016.2019, primarily due to changes in market prices for crude oil and the $12.3 million and $24.7 million decrease of crude oil revenue explained above.
Natural gas sales revenues. Natural gas sales revenues increaseddecreased by $43.6$12.2 million to $92.3$96.7 million for the year ended December 31, 20172020 as compared to natural gas sales revenues of $48.7$108.9 million for the year ended December 31, 2016.2019. An increase in sales volumes between these periods contributed a $29.3$12.8 million positive impact, while an increasea decrease in natural gas prices contributed a $14.3$25.0 million positivenegative impact.
For the year ended December 31, 2017,2020, our natural gas sales averaged 88.8197.6 MMcf/d. Natural gas sales volumes increased by 60%12% to 32,395.272,311 MMcf for the year ended December 31, 20172020 as compared to 20,211.564,710 MMcf for the year ended December 31, 2016.2019. The volume increase was primarily due to the developmentcompletion of our properties. For45 gross wells for the year ended December 31, 2017, we completed 198 gross wells.2020. The increased production from these new wells was partially offset by the normalnatural decline on theof our existing producing properties.
The average price we realized on the sale of our natural gas was $2.85$1.34 per Mcf for the year ended December 31, 20172020 compared to $2.41$1.68 per Mcf for the year ended December 31, 2016.2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative commodity price environment due to oversupply and a decrease in demand.
NGL sales revenues. NGL sales revenues increased by $56.7$2.1 million to $92.1$77.2 million for the year ended December 31, 20172020 as compared to NGL sales revenues of $35.4$75.1 million for the year ended December 31, 2016.2019. An increase in sales volumes between these periods contributed a $25.0$21.6 million positive impact, while an increasea decrease in price contributed a $31.7$19.4 million positivenegative impact.
For the year ended December 31, 2017,2020, our NGL sales averaged 10.721.7 MBbl/d. NGL sales volumes increased by 70%29% to 3,900.97,945 MBbl for the year ended December 31, 20172020 as compared to 2,284.06,164 MBbl for the year ended December 31, 2016.2019. The volume increase wasis primarily due to the developmentcompletion of 45 gross wells for the year ended December 31, 2020. The increased production from these new wells was partially offset by the natural decline of our existing producing properties. Our NGL sales are directly associated with our natural gas sales since the majority ofbecause our natural gas volumes are processed by third parties which return a percentage of the proceeds fromfor both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $23.60$9.72 per Bbl for the year ended December 31, 20172020 compared to $15.49$12.18 per Bbl for the year ended December 31, 2016.2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative commodity price environment due to oversupply and a decrease in demand.
Lease operating expenses ("LOE"). Our LOE, increaseddecreased by $49.3$19.5 million to $111.3$77.8 million for the year ended December 31, 2017,2020, from $62.0$97.3 million for the year ended December 31, 2016.2019. The increasedecrease in LOE was comprisedprimarily the result of an increase in transportation and gathering (“T&G”) expenseoptimization of $25.6 million forour field cost structure during the year ended December 31, 2017 compared to the year ended December 31, 2016 and an increase in operating expenses of $23.7 million for the year ended December 31, 2017 compared to the year ended December 31, 2016. These increases were primarily due to the development of our properties. For the year ended December 31, 2017, we completed 198 gross wells.
2020. On a per unit basis, LOE increased $0.22 per BOE from $5.67decreased to $2.39 per BOE sold for the year ended December 31, 2016 to $5.892020 from $3.00 per BOE sold for the year ended December 31, 2017. The increase was comprised2019.
Transportation and gathering. Our T&G expense of $0.39 per BOE from $2.31 per BOE for the year ended December 31, 2016 to $2.70 per BOE for the year ended December 31, 2017 and a decrease in operating expenses of $0.17 per BOE from $3.36 per BOE for the year ended December 31, 2016 to $3.19 per BOE for the year ended December 31, 2017. The increase in LOE was primarily the result of an increase in both residue natural gas and NGL sales volumes and realized prices, resulting in collectively higher T&G expense. As a result of the January 1, 2018 adoption of Accounting Standard Update 2014-09, Revenue from Contracts with Customers (Topic 606), we expect T&G expense to decrease as a result of a change in accounting methodology for certain contracts where title of
production transfers to customers at the wellhead, in these circumstances T&G expense will be netted against the associated sales revenue.
Production taxes. Our production taxes increased by $30.7$85.5 million to $51.4$138.6 million for the year ended December 31, 2017 as compared to $20.72020, from $53.1 million for the year ended December 31, 2016.2019. The increase in T&G is primarily attributable to an increase of volumes on a certain gathering system and a change in oil contracts.
On a per unit basis, T&G increased to $4.26 per BOE sold for the year ended December 31, 2020 from $1.64 per BOE sold for the year ended December 31, 2019.
Production taxes. Our production taxes decreased by $39.2 million to $29.0 million for the year ended December 31, 2020 as compared to $68.2 million for the year ended December 31, 2019. The decrease was attributable to increaseddecreased revenue as State of Colorado production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 8.5%5.2% for the year ended December 31, 20172020 as compared to 7.5% for the year ended December 31, 2016.2019. The increasedecrease in production taxes as a percentage of sales revenue relates to an increasea decrease in the estimated ad valorem and severance tax rates forand an adjustment to the year endedestimated ad valorem tax payable as of December 31, 2017.2020.
Exploration and abandonment expenses. Our exploration and abandonment expenses were $36.3$258.9 million and $36.4$88.8 million for the years ended December 31, 20172020 and 2016,2019, respectively. We recognized $18.7$4.9 million in expense attributable to the extension of certain leases $15.8and $253.1 million in expense attributable to the abandonment and impairment of unproved properties and $1.4 million of costs associated with exploratory geological and geophysical costs for the year ended December 31, 2017. We recognized $14.1 million in expense attributable to the extension of leases and $22.3 million in expense attributable to the abandonment and impairment of unproved properties for the year ended December 31, 2016.2020. We recognized $12.4 million in expense attributable to the extension of certain leases and $73.7 million in expense attributable to the abandonment of unproved properties for the year ended December 31, 2019.
Depletion, depreciation, amortization and accretion expense (“DD&A”).expense. Our DD&A expense increased $109.7decreased $192.2 million to $315.0$332.3 million for the year ended December 31, 20172020 as compared to $205.3$524.5 million for the year ended December 31, 2016.2019. This increasedecrease was due to higher volumes sold foran impairment of $1.3 billion of proved oil and gas properties that occurred during the year ended December 31, 2017 as sales increased by approximately 7,954.0 MBoe.fourth quarter of 2019. On a per unit basis, DD&A expense decreased from $18.77$16.20 per BOE for the year ended December 31, 20162019 to $16.67$10.21 per BOE for the year ended December 31, 2017. The decrease in DD&A per BOE is due to an increase in reserves related to an increase in prices and extensions, slightly offset by increased production for the year ended December 31, 2017.2020.
Impairment of long lived assets. For the year ended December 31, 2017,2020, our impairment expense was $1.6$208.5 million, associated withrelated to the impairment onof other property and equipment, and certain well equipment inventory, evaluated to have a net realizable value less thanand the impairment of oil and gas properties in our Core DJ Basin field as the field’s fair values did not exceed the carrying value, as the equipment was determined to no longer be useful inamounts associated with our current drilling operations.proved oil and gas properties. For the year ended December 31, 2016, we recognized $22.5 million in2019, our impairment expense on proved oil and gas properties in our northern field. The future undiscounted cash flows did not exceed its carrying amount associated with itswas $1.3 billion. We recognized $14.5 million related to impairment of the proved oil and gas properties in our northern field and it$1.3 billion of impairment expense was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties were impaired at June 30, 2016. Additionally,recognized for the year ended December 31, 2016 we recognized $0.9 million2019 on proved oil and gas properties in our Core DJ Basin field.
(Gain) loss on sale of impairment on other property and equipment.
Other operating expenses. Other operating expenses for the year ended December 31, 2017 is comprisedequipment and assets of a $0.5 million lossunconsolidated subsidiary. Our gain on the sale of insignificant property and equipment. Other operating expenses for the year ended December 31, 2016 includes $10.0 million on the write off of a non-refundable payment related to an option to acquire additional acreage. In March 2017, we entered into an amendment to this agreement with Bayswater to terminate both our and Bayswater’s options for no further consideration. Also included in other operating expenses for the year ended December 31, 2016 is a $0.9 million rig termination fee related to the early termination of a rig in February 2016.
Acquisition transaction expenses. There were no significant acquisition transaction expenses for the year ended December 31, 2017. As part of the acquisition of properties in August 2016 and October 2016, we incurred $2.7 million of transaction costs associated with a finder’s fee, legal expenses and due diligence for the year ended December 31, 2016.
General and administrative expenses (“G&A”). General and administrative expenses decreased by $122.2 million to $110.2was $0.1 million for the year ended December 31, 20172020, as compared to $232.4a $0.4 million loss for the year ended December 31, 2019, which was related to our March 2019 Divestiture, August 2019 Divestiture and December 2019 Divestitures.
General and administrative expenses (“G&A”). General and administrative expenses decreased by $43.6 million to $55.2 million for the year ended December 31, 2016.2020 as compared to $98.8 million for the year ended December 31, 2019. This decrease was comprisedprimarily due to a decrease of $37.6 million in stock based compensation and a decrease in unit and stock-based compensationemployed workforce of $134.7 million, offset by an increase in other general and administrative expenses of $12.5 million.61%, or 198 employees during the year ended December 31, 2020 compared to the year ended December 31, 2019. On a per unit basis, G&A expenses decreased by $1.35 per BOE from $21.24$3.05 per BOE sold for the year ended December 31, 20162019 to $5.83$1.70 per BOE sold for the year ended December 31, 2017.2020.
Our G&A expenses includesinclude the non-cash expense for unit and stock-based compensation for equity awards granted to our employees directors, officers and non-employee consultants.directors. For the year ended December 31, 2017,2020, stock-based compensation expense was $65.6$6.4 million as compared to unit and stock-based compensation expense of $200.3$44.0 million for the year ended December 31, 2016.2019. On a per unit basis, unit and stock-based compensation decreased $14.84$1.16 per BOE from $18.31$1.36 per BOE sold for the year ended December 31, 20162019 to $3.47$0.20 per BOE sold for the year ended December 31, 2017. The decrease in unit and stock-based compensation expense was due to accelerated vesting of outstanding Holdings RUAs in connection with our Corporate Reorganization and IPO in 2016. Additionally, as a result of the IPO in 2016, Holdings incentive2020.
unitsOther operating expenses. Other operating expenses were converted to common stock resulting in the recognition of $172.1$79.6 million of unit-based compensation expense. Also in 2016, we created a Long Term Incentive Plan, which resulted in the granting of RSUs, stock options and performance stock awards to certain board members, officers, and employees.
Our other G&A expenses increased by $12.5 million during the year ended December 31, 2017 compared to the year ended December 31, 2016, primarily due to the growth of the Company, including an increase in employed workforce of 41.0%, or 66 additional employees. However on a per BOE basis, other G&A expenses per BOE sold decreased $0.57 per BOE sold from $2.93 per BOE sold for the year ended December 31, 20162020. This amount is made up of a $46.8 million loss contingency related to $2.36 per BOE soldan alleged breach in contract, $4.2 million of accrued interest related to the aforementioned breach in contract, a $13.2 million early termination fee related to the termination of our crude oil marketing contract, $7.6 million incurred due to workforce reductions, $4.1 million incurred in production tax interest expense, a $2.4 million early termination fee related to the termination of a drilling rig contract, and $1.3 million in expenses related to legal accruals and other.
Commodity derivative gain (loss). Primarily due to the unwinding of trades due to the commencement of the Chapter 11 Cases, coupled with the decrease in NYMEX crude oil futures prices at December 31, 2020 as compared to December 31, 2019 and change in fair value from the execution of new positions, we incurred a net gain on our commodity derivatives of $165.0 million for the year ended December 31, 2017. The decrease in other G&A expenses on a per BOE basis is due to higher production volumes for the year ended December 31, 2017.
Commodity derivative gain (loss).2020. Primarily due to the increase in NYMEX crude oil futures prices at December 31, 20172019 as compared to December 31, 2016 and change in fair value from the execution of new positions during each period, we incurred a net loss on our commodity derivatives of $36.3 million and $100.9 million for the years ended December 31, 2017 and 2016, respectively. These losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. For the year ended December 31, 2017, we distributed cash settlements of commodity derivatives totaling $18.0 million. For the year ended December 31, 2016, we received cash settlements of commodity derivatives totaling $34.2 million.
Interest expense. Interest expense consists of interest paid and accrued on our long term debt, amortization of debt discount and debt issuance costs, net of capitalized interest. For the year ended December 31, 2017, we recognized interest expense of approximately $51.9 million as compared to $68.8 million for the year ended December 31, 2016, as a result of borrowings under our revolving credit facility, our Second Lien Notes in 2016, our 2021 Senior Notes, our 2024 Senior Notes in 2017 and the amortization of debt issuance costs and debt discount.
We incurred interest expense for the year ended December 31, 2017 of approximately $58.7 million related to our 2024 Senior Notes, 2021 Senior Notes and credit facility. We incurred interest expense for the year ended December 31, 2016 of approximately $50.4 million related to our Second Lien Notes, our 2021 Senior Notes and credit facility. Also included in interest expense for the years ended December 31, 2017 and 2016 was the amortization of debt issuance costs and debt discount of $4.3 million and $4.2 million, respectively. For the years ended December 31, 2017 and 2016, we capitalized interest expense of $11.1 million and $5.2 million, respectively. Also included in interest expense for the year ended December 31, 2016 is a prepayment penalty of $4.3 million and the accelerated amortization of our remaining unamortized debt discount and debt issuance costs of $15.1 million related to the our repayment of the Second Lien Notes in July 2016.
Income tax benefit. We recorded an income tax benefit of approximately $63.7 million and $29.3 million resulting in an effective tax rate of approximately 58.9% and 6.0% for the years ended December 31, 2017 and 2016, respectively. Our effective tax rate for 2017 differs from the U.S. statutory income tax rate of 38.0% primarily due to the effects of state income taxes, estimated permanent taxable differences and a one-time remeasurement of net deferred tax liabilities from 38.0% to 24.7% due to the Tax Cuts and Jobs Act. During the year ended December 31, 2017, our income tax benefit increased $34.4 million compared to the same period in 2016, which was primarily due to the one-time remeasurement of net deferred tax liabilities in 2017 and our corporate reorganization to a C-Corp in 2016. Excluding the impact of the one-time remeasurement of net deferred tax liabilities required in 2017, our overall effective tax rate was 37.3% for the year ended December 31, 2017.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Oil sales revenues. Crude oil sales revenues increased by $37.1 million to $194.1 million for the year ended December 31, 2016 as compared to crude oil sales of $157.0 million for the year ended December 31, 2015. An increase in sales volumes between these periods contributed a $53.4 million positive impact, while a decrease in crude oil prices contributed a $16.3 million negative impact.
For the year ended December 31, 2016, our crude oil sales averaged 14.4 MBbl/d. Our crude oil sales volume increased 34% to 5,287.4 MBbl in the year ended December 31, 2016 compared to 3,945.6 MBbl for the year ended December 31, 2015. The volume increase was primarily due to the development of our properties. For the year ended December 31, 2016, we completed 72 gross wells. The increased production from these new wells was offset by the normal decline on the existing producing properties.
The average price we realized on the sale of crude oil was $36.70 per Bbl for the year ended December 31, 2016 compared to $39.80 per Bbl for the year ended December 31, 2015.
Natural gas sales revenues. Natural gas sales revenues increased by $22.7 million to $48.7 million for the year ended December 31, 2016 as compared to natural gas sales revenues of $26.0 million for the year ended December 31, 2015. An increase in sales volumes between these periods contributed $22.7 million positive impact, while the change in natural gas prices had a de minimis impact.
For the year ended December 31, 2016, our natural gas sales averaged 55.2 MMcf/d. Natural gas sales volumes increased by 87% to 20,211.5 MMcf for the year ended December 31, 2016 as compared to 10,823.0 MMcf for the year ended December 31, 2015. The volume increase was primarily due to the development of our properties. For the year ended December 31, 2016, we completed 72 gross wells. The increased production from these new wells was offset by the normal decline on the existing producing properties.
The average price we realized on the sale of our natural gas was $2.41 per Mcf for the year ended December 31, 2016 compared to $2.40 per Mcf for the year ended December 31, 2015.
NGL sales revenues. NGL revenues increased by $20.7 million to $35.4 million for the year ended December 31, 2016 as compared to NGL revenues of $14.7 million for the year ended December 31, 2015. An increase in sales volumes between these periods contributed a $10.5 million positive impact, while an increase in price contributed a $10.2 million positive impact.
For the year ended December 31, 2016, our NGL sales averaged 6.2 MBbl/d. NGL sales volumes increased by 71% to 2,284.0 MBbl for the year ended December 31, 2016 as compared to 1,334.6 MBbl for the year ended December 31, 2015. The volume increase was due to the development of our properties. Our NGL sales are directly associated with our natural gas sales since the majority of our natural gas volumes are processed by third parties which return a percentage of the proceeds from both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $15.49 per Bbl for the year ended December 31, 2016 compared to $11.02 per Bbl for the year ended December 31, 2015.
Lease operating expenses. Our LOE, increased by $31.4 million to $62.0 million for the year ended December 31, 2016, from $30.6 million for the year ended December 31, 2015. The increase in LOE was comprised of an increase in transportation and gathering (“T&G”) expense of $18.7 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 and an increase in operating expenses of $12.7 million for the year ended December 31, 2016 compared to the year ended December 31, 2015.
On a per unit basis, LOE, increased $1.35 per BOE from $4.32 per BOE sold for the year ended December 31, 2015 to $5.67 per BOE sold for the year ended December 31, 2016. The increase was comprised of an increase in T&G expense of $1.38 per BOE from $0.93 per BOE for the year ended December 31, 2015 to $2.31 per BOE for the year ended December 31, 2016. The increase in T&G per BOE was offset by a decrease in operating expenses of $0.03 per BOE from $3.39 per BOE for the year ended December 31, 2015 to $3.36 per BOE for the year ended December 31, 2016. The increase in LOE was primarily the result of an increase in T&G fees on gas sales as a result of us entering into more fee-type gas transportation contracts versus percent of proceeds gas transportation contracts.
Production taxes. Our production taxes increased by $3.7 million to $20.7 million for the year ended December 31, 2016 as compared to $17.0 million for the year ended December 31, 2015. The increase was attributable to increased revenue as State of Colorado production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 7.5% for the year ended December 31, 2016 as compared to 8.6% for the year ended December 31, 2015. Production tax rates can vary depending on the location and the volumes produced from our properties.
Exploration expenses. Our exploration expenses were $36.4 million and $18.6 million for the years ended December 31, 2016 and 2015. We recognized $14.1 million in expense attributable to the extension of leases and $22.3 million in expense attributable to the abandonment and impairment of unproved properties for the year ended December 31, 2016. We recognized $2.2 million in expense attributable to the extension of leases and $16.4 million in expense attributable to the abandonment and impairment of unproved properties for the year ended December 31, 2015.
Depletion, depreciation, amortization and accretion expense (“DD&A”). Our DD&A expense increased $58.8 million to $205.3 million for the year ended December 31, 2016 as compared to $146.5 million for the year ended
December 31, 2015. This increase was due to higher volumes sold for the year ended December 31, 2016 as sales increased by approximately 3,856.0 MBoe. On a per unit basis, DD&A expense decreased from $20.69 per BOE for the year ended December 31, 2015 to $18.77 per BOE for the year ended December 31, 2016.
Impairment of long lived assets. For the year ended December 31, 2016, we recognized $22.5 million in impairment expense on proved oil and gas properties in our northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in our northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties were impaired at June 30, 2016. Additionally, for the year ended December 31, 2016 we recognized $0.9 million of impairment on other property and equipment. During 2015, we sold proved oil and gas properties for proceeds of $4.7 million. In connection with the sale, we determined that assets’ net book value exceeded the fair value of such properties by $2.7 million. We recognized that amount as an impairment expense for the year ended December 31, 2015. During 2015, we also recorded impairment expense of $9.5 million related to impairment of a subsidiary. Our subsidiary had negative future undiscounted cash flows associated with its proved oil and gas properties as of December 31, 2015, and it was determined that our subsidiary’s proved oil and gas properties had no remaining fair value. Therefore, our subsidiary’s full net book value of proved oil and gas properties were impaired. Additionally, we recognized $3.6 million in impairment expense related to a specifically proposed gas processing plant that is no longer being pursued.
Other operating expenses. Other operating expenses for the year ended December 31, 2016 includes $10.0 million on the write off of a non-refundable payment related to an option to acquire additional acreage. In March 2017, we entered into an amendment to this agreement with Bayswater to terminate both our and Bayswater’s options for no further consideration. Also included in other operating expenses for the year ended December 31, 2016 is a $0.9 million rig termination fee related to the early termination of a rig in February 2016. Other operating expenses for the year ended December 31, 2015 were comprised of a $1.7 million rig termination fee related to the early termination of a rig in March 2015 and a rig standby fee of $0.7 million in September 2015.
Acquisition transaction expenses. As part of the acquisition of properties in August 2016 and October 2016, respectively, we incurred $2.7 million of transaction costs associated with a finder’s fee, legal expense and due diligence for the year ended December 31, 2016. For the year ended December 31, 2015, we incurred $6.0 million of non-cash transaction costs associated with a finder’s fee to an unaffiliated third-party as part of the acquisition of properties in March 2015. We assigned an overriding royalty interest in the proved and unproved oil and gas properties acquired in March 2015, which had a fair value of $6.0 million on the measurement date, as payment for the finder’s fee.
General and administrative expenses (“G&A”). General and administrative expenses increased by $195.3 million to $232.4 million for the year ended December 31, 2016 as compared to $37.1 million for the year ended December 31, 2015. This increase was comprised of an increase in unit and stock-based compensation of $194.3 million and an increase in other general and administrative expenses of $1.0 million. On a per unit basis, G&A expenses increased from $5.24 per BOE sold for the year ended December 31, 2015 to $21.24 per BOE sold for the year ended December 31, 2016.
Our G&A expenses includes the non-cash expense for unit and stock-based compensation for equity awards granted to our employees and non-employee consultants. For the year ended December 31, 2016, unit and stock-based compensation expense was $200.3 million as compared to $6.0 million for the year ended December 31, 2015. On a per unit basis, unit and stock-based compensation increased $17.47 per BOE from $0.84 per BOE sold for the year ended December 31, 2015 to $18.31 per BOE sold for the year ended December 31, 2016. The increase in unit and stock-based compensation expense was due to accelerated vesting of outstanding Holdings RUAs in connection with our Corporate Reorganization and IPO. Additionally, as a result of the IPO, Holdings incentive units were converted to common stock resulting in $172.1 million of stock-based compensation expense. Also, we created a Long Term Incentive Plan, which resulted in the granting of RSUs and stock options to certain board members, officers, and employees.
Our other G&A expenses increased by $1.0 million during the year ended December 31, 2016 compared to the year ended December 31, 2015, primarily due to the growth of the Company, however on a per BOE basis, other G&A expenses per BOE sold decreased $1.47 per BOE sold from $4.40 per BOE sold for the year ended December 31, 2015 to $2.93 per BOE sold for the year ended December 31, 2016. The decrease in other G&A expenses on a per BOE basis is due to increases in production volumes for the year ended December 31, 2016.
Commodity derivative gain (loss). Primarily due to the increase in NYMEX crude oil futures prices at December 31, 2016 as compared to December 31, 20152018 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of $100.9 million for the year ended December 31, 2016. Primarily due to the decrease in NYMEX crude oil futures prices at December 31, 2015 as compared to December 31, 2014$37.1 million. These gains and change in fair value
from the execution of new positions, we incurred a net gain on our commodity derivatives of $79.9 million for the year ended December 31, 2015. These losses and gains are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program.program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. For the years ended December 31, 20162020 and 2015,2019, we received and paid cash settlements of commodity derivatives totaling $34.2$188.8 million and $59.8$5.8 million, respectively.
Loss on deconsolidation of Elevation Midstream, LLC. On March 16, 2020, we deconsolidated Elevation Midstream, LLC. Upon deconsolidation, we elected the fair value option to remeasure the Elevation equity method investment and determined it had no fair value. The Company recorded a $73.1 million loss on deconsolidation of Elevation Midstream, LLC in the consolidated statements of operations for the year ended December 31, 2020.
Reorganization items, net. Due to the commencement of the Chapter 11 Cases during the second quarter of 2020, we have incurred and will continue to incur significant costs associated with our reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. For the year ended December 31, 2020, we recognized $676.9 million in reorganization items. No reorganization items were recognized during the same period in the preceding year. Please see Note 6 — Reorganization Items, Net in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
Interest expense. Interest expense consists of interest paid and accruedexpense on our long termlong-term debt amortization of debt discount and debt issuance costs, net of capitalized interest. For the year ended December 31, 2016,2020, we recognized interest expense of approximately $68.8$57.1 million as compared to $51.0$79.2 million for the year ended December 31, 2015,2019, as a result of borrowings under our revolving credit facility, borrowings onPrior Credit Facility, our Second LienDIP Credit Facility, our 2024 Senior Notes, our 2026 Senior Notes, and the amortization of remaining unamortizedother debt issuance costs and debt discount upon the repayment of our Second Lien Notes.costs.
We incurred interest expense the year ended December 31, 2016 of approximately $50.4 million related to our revolving credit facility, our Senior Notes in 2016 and our Second Lien Notes. Interest expense for the year ended December 31, 2016 included the accelerated amortization of our remaining unamortized debt discount and debt issuance costs of $15.1 million upon the repayment of our Second Lien Notes in July 2016, and the amortization of debt issuance costs on our Second Lien Notes, Senior Notes and credit facility of $4.2 million, excluding the accelerated amortization of the remaining unamortized debt discount and debt issuance costs on our Second Lien Notes. Also included in interest expense for the year ended December 31, 2016 was a prepayment penalty in the amount2020 of $4.3approximately $58.8 million related to our 2024 Senior Notes, 2026 Senior Notes, Prior Credit Facility and DIP Credit Facility. We incurred upon the repayment of our Second Lien Notes. Interestinterest expense for the year ended December 31, 2015 includes $50.72019 of approximately $91.5 million of interest expense related to our revolving credit facility2024 Senior Notes, 2026 Senior Notes and Second Lien NotesPrior Credit Facility. Also included in interest expense for the years ended December 31, 2020 and 2019 was the amortization of debt discount and debt issuance costs of $5.6 million.$3.7 million and $5.5 million, respectively, and a gain on the sale of extinguishment of debt of $10.5 million for the year ended December 31, 2019. For the years ended December 31, 20162020 and 2015,2019, we capitalized interest expense of $5.2$5.3 million and $5.3$7.2 million, respectively.
Income tax (expense) benefit. We recorded no income tax expense (benefit) for the year ended December 31, 2020 resulting in an effective tax rate of approximately zero. We recorded an income tax benefit of approximately $109.2 million for the year ended December 31, 2016 of $29.3 million,2019 resulting in an effective tax rate of approximately 6%7.4%. Our effective tax rate for 20162020 and 2019 differs from the U.S. statutory income tax rate of 21% primarily due to the effects of state income taxes, estimated permanent taxable differences, nondeductible stock-based compensation, and the Corporate Reorganization. Nondeductible stock compensation expense made uprecording of a valuation allowance against deferred tax assets.
Gathering and facilities segment. Prior to March 31, 2020, we had two operating segments, (i) the majorityexploration, development and production of oil, natural gas and NGL (the “exploration and production segment”) and (ii) the permanent items whichconstruction, operation and support of midstream assets to gather and process crude oil and gas production (the “gathering and facilities segment”). Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report for further information related to the conversiondeconsolidation of incentive units to common stock. See Note 11 — Unit and Stock-Based Compensation in the notes to our consolidated financial statements for additional discussion of Holdings’ Incentive Units. Prior to the Corporate Reorganization we were organizedElevation Midstream, LLC. After March 31, 2020, Extraction began reporting as a limited liability company thatsingle reportable segment.
Our consolidated statements of operations for the year ended December 31, 2020 contains the following amounts, which were incurred during the first quarter of 2020. The gathering and facilities segment had revenues of $6.0 million and direct operating expenses of $3.9 million. General and administrative expenses were $0.7 million and depreciation expense was not subject to U.S. federal income tax. Excluding$1.1 million as the impactgathering facility was placed into service during the fourth quarter of 2019. Please see Note 18 — Segments in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report.
Our consolidated statements of operations for the Corporate Reorganizationyear ended December 31, 2019 contains the following amounts. The gathering and nondeductible stock compensation, our overall effective tax ratefacilities segment had revenues of $6.9 million and direct operating expenses of $2.3 million. General and administrative expenses were $4.6 million and depreciation expense was 35%. For 2016, our combined federal and state statutory tax rate$1.4 million as the gathering facility was 38%.placed into service during the fourth quarter of 2019.
Liquidity and Capital Resources
Chapter 11 Cases and Effect of Automatic Stay
On June 14, 2020, we filed for relief under Chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Prior Credit Agreement (defined below) and the indentures governing our Senior Notes, resulting in the automatic and immediate acceleration of all of our outstanding debt under the Prior Credit Agreement and the Senior Notes. Any efforts to enforce payment obligations related to the acceleration of our debt were automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. On June 14, 2020, we also entered into the Restructuring Support Agreement (“RSA”) with certain holders of our Senior Notes to support a restructuring in accordance with the terms set forth therein. As more fully disclosed in Note 1 — Business and Organization and Note 8 — Long-Term Debt in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report, the RSA contemplated a financial restructuring which would provide for the treatment of holders of certain claims and existing equity interests. The Plan, which included substantially all terms set forth in the RSA, was approved by the Bankruptcy Court on December 23, 2020 and we emerged from bankruptcy on January 20, 2020.
We continued operations in the ordinary course for the duration of the Chapter 11 Cases funding operations with our DIP Credit Facility (as defined in Note 8 — Long-Term Debt in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report along with all capitalized debt terms in this paragraph). Upon emergence from bankruptcy, our Prior Credit Facility and DIP Credit Facility were paid off and we obtained a RBL Credit Facility discussed below.
As a result of the Chapter 11 Cases, our total available liquidity as of December 31, 2020 consisted of cash on hand of $205.9 million and $11.5 million of availability on the DIP Credit Facility. With this liquidity and funds generated from ongoing operations, we funded cash requirements throughout 2020 during the Chapter 11 proceedings. As such, we paid and expect to continue paying vendor and royalty obligations according to the terms of our current contracts.
Sources of Liquidity and Capital Resources
Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. Depending upon market conditions and other factors, we may also issue equity and debt securities if needed.
Historically, our primary sources of liquidity have been borrowings under our revolving credit facility, our Second Lien Notes, our 2021 Senior Notes, our 2024 Senior Notes (please refer to Note 5 — Long Term Debt),Prior Credit Facility, proceeds from notes offerings and preferred stock offerings, equity provided by investors, including our management team, cash from the IPO and Private Placementissuance of preferred stock, and cash flows from operations. To date, ourdivestitures and from the sale of oil, gas and NGL production. Our primary useuses of capital hashave been for the acquisition of oil and gas properties to increase our acreage position, as well as development and exploration of oil and gas properties. As of December 31, 2020, our DIP Credit Facility borrowings were $106.7 million, with $75.0 million total outstanding including amounts that were rolled over from the Prior Credit Facility. Our Prior Credit Facility borrowings net of unamortized debt issuance costs, were approximately $1,023.4$453.7 million and $538.1$470.0 million at December 31, 2017,2020, and December 31, 2016,2019, respectively. We had senior notes totaling $1.1 billion outstanding at December 31, 2020 and December 31, 2019. We also have other contractual commitments, which are described in Note 1316 — Commitments and Contingencies.Contingencies in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report.
Upon emergence from bankruptcy on January 20, 2021 indebtedness under our 2024 and 2026 Senior Notes was discharged in exchange for equity as is explained in Note 1 — Business and Organization in Part II, Item 8. Financial Information and Supplementary Data of this Annual Report. Our Prior Credit Facility and DIP Credit Facility were paid off, terminated and replaced by our RBL Credit Facility that has a maximum commitment of $1.0 billion with an initial borrowing base and current elected lending commitments of $500.0 million. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year, with one interim “wildcard” redetermination available to us and our administrative agent between scheduled redeterminations during any 12-month period. The next scheduled redetermination will be on or around May 1, 2021.
As of the date of this filing, we have drawn $253.7 million on the RBL Credit Facility. Total funds available for borrowing under our RBL Credit Facility, after giving effect to an aggregate of $0.5 million of undrawn letters of credit, were $245.8 million as of the date of this filing.
We plan to continue our practice of enteringenter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy,operations, or alternatively, we intendmay decide to enter into commodity derivative contracts at times and on terms desiredunwind or restructure the hedging arrangements we previously entered into. The RBL Credit Agreement requires us to maintain commodity hedges covering a portfoliominimum of commodity derivative contracts covering approximately 50% to 70%65% of our projectedanticipated oil and natural gas production over a one to two year period at a given point in time, although we may from time to time hedge more or less than this approximate range.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operationsPDP reserves for the succeeding twelve months and available borrowings under our revolving credit facility to execute our current capital program, excluding
any acquisitions we may consummate, make our interest payments on the 2024 Senior Notes and 2026 Senior Notes, and pay dividends on our Series A Preferred Stock.
If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures and/or fund a portion50% of our capital expenditures using borrowings under our revolving credit facility, issuancesanticipated oil and gas production from PDP reserves for the next succeeding twelve months.
Our 20182021 capital budget for the drilling and completion of operated and non-operated wells is approximately $890$140 million to $990$180 million, substantially all of which we intend to allocate to the Core DJ Basin. We intend to allocate approximately $770 million to $840 million of our 2018 capital budget to operated and non-operated drilling and completion of new wells. We expect to drill 170 to 17534 gross operated wells, complete 49 gross operated wells and complete 185 to 190turn-in-line 44 gross operated wells. Approximately $120 million to $150 million is expected to be allocated to acreage leasing, midstream, and other capital expenditures. Our 2021 capital budget anticipates a two to three operated rigone-rig drilling program we expect to operate most of the year.
We had a Stock Repurchase Program in place that ended in 2019. Spending under this program was $137.0 million and excludes any amounts thatwe repurchased 34.1 million shares during the year ended December 31, 2019. We also had a Senior Notes Repurchase Program in place. Spending under this program during the year ended December 31, 2019 was $39.3 million. No common stock or Senior Notes were or may be paid for potential acquisitions.repurchased during the year ended December 31, 2020.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in thousands):
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 |
| Net cash provided by operating activities | $ | 265,975 | | | $ | 557,957 | |
| Net cash used in investing activities | (245,101) | | | (850,153) | |
| Net cash provided by financing activities | 160,362 | | | 89,592 | |
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Net cash provided by operating activities | $ | 316,965 |
| | $ | 116,388 |
| | $ | 166,683 |
|
| Net cash used in investing activities | (1,362,328 | ) | | (915,808 | ) | | (520,006 | ) |
| Net cash provided by financing activities | 463,395 |
| | 1,291,050 |
| | 371,404 |
|
Year Ended December 31, 20172020 Compared to the Year Ended December 31, 20162019
Net cash provided by operating activitiesactivities.For the year ended December 31, 20172020 as compared to the year ended December 31, 2016, our net cash provided by operating activities increased by $200.6 million, primarily driven by an increase in sales volume of 7,953.8 MBoe and increase in realized price of $6.56 per BOE resulting in a reduction in net loss of $411.6 million. An increase in deferred income tax benefit of $34.4 million and increase in changes in current assets and liabilities of $14.7 million also contributed to this increase. This increase was offset by a decrease of stock-based compensation of $134.7 million and settlements on commodity derivatives of $54.8 million.
Net cash used in investing activities. For the year ended December 31, 2017 as compared to the year ended December 31, 2017, our net cash used in investing activities increased by $446.5 million primarily due to an increase of $935.7 million in cash expended for drilling and completion activities and other property and equipment. This increase was offset by a decrease in acquired oil and gas properties of $401.8 million and decrease of $84.4 million in cash held in escrow for acquisitions.
Net cash provided by financing activities. For the year ended December 31, 2017 as compared to the year ended December 31, 2016, our net cash provided by financing activities decreased by $827.7 million, primarily as a result of a decrease of $1,243.1 million in proceeds from the issuance of common stock and members units, net of issuance costs, and a decrease of $171.6 million in proceeds from the issuance of preferred units and stock in the year ended December 31, 2016. This decrease was offset by an increase of $315.0 million in borrowings under the credit facility and an increase of $274.0 million in net proceeds and repayments of 2021 Senior Notes, 2026 Senior Notes and Second Lien Notes.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Net cash provided by operating activities. For the year ended December 31, 2016 as compared to the year ended December 31, 2015,2019, our net cash provided by operating activities decreased by $50.3$292.0 million primarily due to a decrease in changes in current assets and liabilitiesoperating revenues net of $59.6expenses of $377.3 million along withas a result of a decrease in commodity prices and a decrease of $126.3 million related to changes in working capital when excluding the $582.4 million change in accrued damages for rejected and settled contracts. Also, cash settlements, including changes to accounts receivable and accounts payable on commodity derivatives of $12.9paid for reorganization items during 2020 increased $34.4 million. These decreasesreductions to cash inflows were partially offset by an increase of $90.5 million in sales volumecommodity derivative settlement payments, a decrease of 3,856.0 MBOE$46.1 million in cash paid for interest and the associated increasea decrease of $6.1 million in revenue less operatingcash paid for general and administrative expenses.
Net cash used in investing activities.For the year ended December 31, 20162020 as compared to the year ended December 31, 2015,2019, our net cash used in investing activities increaseddecreased by $395.8$605.1 million primarily due to $298.5decreased spending of $385.9 million on oil and gas property additions, $206.7 million on our gathering systems and facilities, $35.4 million on other property and equipment, and $20.0 million on investments in additional acquisition of properties, an increase of $52.3 million in cash held in escrow for acquisitions as required under the related purchase and sale agreements, and a reduction ofunconsolidated subsidiary. During 2020, cash received from the sale of property and equipment decreased $41.9 million and cash received from the sale of $2.0 million in 2016 compared to 2015. Additionally, there was an increaseassets of $43.0 million inunconsolidated subsidiary decreased $1.0 million.
Net cash expended for drilling and completion activities and other property and equipment forprovided by financing activities. For the year ended December 31, 20162020 as compared to the year ended December 31, 2015.
Net cash provided by financing activities. For the year ended December 31, 2016 as compared to the year ended December 31, 2015,2019, our net cash provided by financing activities increased by $919.6$70.8 million. Net borrowings on the Prior Credit Facility decreased $54.5 million, primarily as a result of an increase of $990.0 millionand no cash was received in proceeds2020 from the issuance of common stock and members units, net of issuance costs in the year ended December 31, 2016Elevation Preferred Units compared to December 31, 2015. Additionally, we issued preferred equity securities, net of repayments and dividends, in the amount of $170.8 million.$99.0 million received during 2019. These increasesdecreases were offset by an increase in net borrowings on the DIP Credit Facility of $241.2$31.7 million, a decrease in the net repaymentcash spent on payroll withholding taxes of debt due$1.7 million, a decrease in Series A Preferred Stock dividends of $10.9 million, and a decrease of Preferred Unit Issuance costs of $2.5 million during 2020 compared to the repayment2019. Additionally, during 2020 no cash was spent repurchasing common stock and senior notes, but during 2019 cash spent to repurchase common stock was $137.7 million, as result of our credit facilityShare Repurchase Program, and Second Lien Notes during the year ended December 31, 2016 with proceeds fromsenior notes was $39.3 million, as a result of our Senior Notes and IPO.Repurchase Program.
Working Capital
Our working capital surplus (deficit)deficit at December 31, 2020 was $(236.7)$369.4 million and $379.1at December 31, 2019 was $240.8 million. However, as of December 31, 2020, many of our current liabilities in the amount of $279.6 million were classified as liabilities subject to compromise (excluding approximately $1.8 billion of debt, accrued interest, damages for rejected and settled contracts and other). Our cash balances totaled $205.9 million and $32.4 million at December 31, 20172020 and 2016, respectively. Our cash balances totaled $6.8 million and $588.7 million at December 31, 2017 and December 31, 2016,2019, respectively.
Due to the amounts that we incur related to our drilling and completion program and the timing of such expenditures, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our revolving credit facility after application of the net proceeds from the 2026 Senior NotesRBL Credit Facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil, natural gas and NGL production will be the largest variables affecting our working capital.
Debt Arrangements
Our revolving credit facility has a maximum credit amount of $1.5 billion, subject to a borrowing base of $700.0 million, subject to the current maximum lending commitments of $650.0 million, and allFor details of our currentdebt arrangements including our RBL Credit Facility, DIP Credit Facility, Prior Credit Facility, 2024 Senior Notes and future subsidiaries will be guarantors under such facility, with the exception of Elevation Midstream, LLC. Amounts repaid under our revolving credit facility may be re-borrowed from time to time, subject to the terms of the facility. For more information on the revolving credit facility,2026 Senior Notes, please see Note 58 — Long-Term Debt in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report. The revolving credit facility is secured by liens on substantially all
Equity Arrangements
For details of our properties.
In July 2016, we closed a private offering of our unsecured 7.875% Senior Notes due 2021 that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bear interest at an annual rate of 7.875%. Interest on our 2021 Senior Notes is payable on January 15 and July 15 of each year, and the first interest payment was made on January 15, 2017. Our 2021 Senior Notes will mature on July 15, 2021. Our 2021 Senior Notes are guaranteed by all of our current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of our 2021 Senior Notes). In the first quarter of 2018 we closed a tender offer and redemption for the 2021 Senior Notes and subsequently redeemed any remaining outstanding 2021 Senior Notes after such tender offer. No 2021 Senior Notes remain outstanding.
In August 2017, we closed a private offering of our unsecured 7.375% Senior Notes due 2024 that resulted in net proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable on May 15 and November 15 of each year commencing on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024. Our 2024 Senior Notes are guaranteed by all of our current and future restricted subsidiaries.
In January 2018, we closed a private offering of our unsecured 5.625% Senior Notes due 2026 that resulted in net proceeds of approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on our 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment will be made on August 1, 2018. Our 2026 Senior Notes will mature on February 1, 2026. Our 2026 Senior Notes are guaranteed by all of our current and future restricted subsidiaries.
Revolving Credit Facility
The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of our proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under our revolving credit facility. As of December 31, 2017, the borrowing base was $525.0 million, and we had $90.0 million of borrowings outstanding under our revolving credit facility. In January 2018, we completed the November 1, 2017 borrowing base redetermination. As a result of the redetermination, the borrowing base increased to $750.0 million. The borrowing base was automatically reduced to $700.0 million in connection with the issuance of the 2026 Senior Notes and is subject to current maximum lending commitments of $650.0 million.
Principal amounts borrowed will be payable on the maturity date, and interest will be payable quarterly for alternate base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to the product of: (a) the LIBOR rate, multiplied by (b) a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the reserve percentages (expressed as a decimal) on such date at which the administrative agent under our revolving credit facility is required to maintain reserves on ‘Eurocurrency Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 200 to 300 basis points, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the adjusted one-month LIBOR rate (as calculated above) plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the percentage of our borrowing base utilized. As of December 31, 2017, we had $90.0 million of outstanding borrowings under our revolving credit facility. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
The revolving credit facility is secured by liens on substantially all of our properties and guarantees from us and our current and future subsidiaries, with the exception of Elevation Midstream, LLC. The revolving credit facility contains restrictive covenants that may limit our ability to, among other things:
incur additional indebtedness;
sell assets;
make loans to others;
make investments;
make certain changes to our capital structure;
make or declare dividends;
hedge future production or interest rates;
enter into transactions with our affiliates;
incur liens; and
engage in certain other transactions without the prior consent of the lenders.
The revolving credit facility requires us to maintain the following financial ratios:
a current ratio, which is the ratio of our consolidated current assets (includes unused commitments under our revolving credit facility and unrestricted cash and excludes derivative assets) to our consolidated current liabilities (excludes obligations under our revolving credit facility, the senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and
a net leverage ratio, which is the ratio of (i) consolidated debt less cash balances to (ii) our consolidated EBITDAX for the four fiscal quarter period most recently ended, not to exceed 4.0 to 1.0 as of the last day of such fiscal quarter; provided that (a) for the quarter ending December 31, 2017, consolidated EBITDAX will be based on the last nine months' consolidated EBITDAX multiplied by 4/3 and (b) for the quarters ending on or after March 31, 2018, consolidated EBITDAX will be based on the last twelve months’ consolidated EBITDAX.
2021 Senior Notes
In July 2016, we closed a private offering of our 2021 Senior Notes that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bore interest at an annual rate of 7.875% and matured on July 15, 2021.
Concurrent with the 2026 Notes Offering, we commenced a cash tender offer to purchase any and all of its 2021 Senior Notes. On January 24, 2018 we received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 we made a cash payment of approximately $534.2 million, which included principal of approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, we redeemed the approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which includes a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.
2024 Senior Notes
In August 2017, we closed a private offering of our 2024 Senior Notes that resulted in net proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable on May 15 and November 15 of each year, and the first interest payment was paid on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024.
We may, at our option, redeem all or a portion of our 2024 Senior Notes at any time on or after May 15, 2020 at the redemption prices set forth in the indenture governing the 2024 Senior Notes. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2024 Senior Notes before May 15, 2020, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.375% of the principal amount of our 2024 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to May 15, 2020, we may redeem some or all of our 2024 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our 2024 Senior Notes may have the right to require us to repurchase their 2024 Senior Notes at 101% of the principal amount of the 2024 Senior Notes, plus accrued and unpaid interest, if any, to the date of purchase.
Our 2024 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current subsidiaries and by certain future restricted subsidiaries that guarantees our indebtedness under a credit facility. The 2024 Senior Notes are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of our future subsidiaries that do not guarantee the 2024 Senior Notes.
2026 Senior Notes
On January 25, 2018, closed a private offering of our 2026 Senior Notes that resulted in net proceeds of approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment will be made on August 1, 2018. Our 2026 Senior Notes will mature on February 1, 2026.
We may, at our option, redeem all or a portion of our 2026 Senior Notes at any time on or after February 1, 2021 at the redemption prices set forth in the indenture governing the 2026 Senior Notes. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2026 Senior Notes before February 1, 2021, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 105.625% of the principal amount of our 2026 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to February 1, 2021, we may redeem some or all of our 2026 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our 2026 Senior Notes may have the right to require us to repurchase their 2026 Senior Notes at 101% of the principal amount of the 2026 Senior Notes, plus accrued and unpaid interest, if any, to the date of purchase.
Our 2026 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current subsidiaries and by certain future restricted subsidiaries that guarantee our indebtedness under a credit facility. The 2026 Senior Notes are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of our future subsidiaries that do not guarantee the 2026 Senior Notes.
Convertible Preferred Securities
We previously issued to affiliates of Apollo $75.0 million in Series A Preferred Units to fund a portion of the purchase price for the Bayswater Acquisition. The Series A Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears. We used $90.0 million of the net proceeds from the IPO to redeem the Series A Preferred Units in full, which included a premium of $15.0 million.
In addition, we issued to, among others, investment funds affiliated with OZ Management LP and Yorktown $185.3 million in Series B Preferred Units to fund a portion of the purchase price for the Bayswater Acquisition. The Series B Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears, and we had the ability to pay up to 50% of the quarterly dividend in kind. The Series B Preferred Units were converted in connection with the closing of the IPO into shares ofarrangements including our Series A Preferred Stock that are entitled to receive a cash dividend of 5.875% per year, payable quarterlyand Elevation Preferred Units, please see Note 12 — Equity in arrears, and we have the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are partially paid in cash). The Series A Preferred Stock is convertible into shares of our common stock at the election of the Series A Preferred Holders at a conversion ratio per share of Series A Preferred Stock of 61.9195. Until the three year anniversary of the closing of the IPO, we may elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of our common stock trades at or above a certain premium to our initial offering price, such premium to decrease with time. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock mature on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference. See Note 9 — Equity— Series A Preferred Stock and Series B Preferred Units” inPart II, Item 8. Financial StatementsInformation and Supplementary Data of this Annual Report.
Commitments, Contingencies and Contractual Obligations
A summaryThe information responsive to Item 303 (a)(5) of our commitments, contingencies and contractual obligations asRegulation S-K is not required of December 31, 2017 is provided in the following table (in thousands).smaller reporting companies.
|
| | | | | | | | | | | | | | | | | | | |
| | Payments due by Period |
| | | | Less than | | | | | | More than |
| | Total | | 1 year | | 1 - 3 years | | 3 - 5 years | | 5 years |
| Contractual Obligations | | | | | | | | | |
Office lease(1) | $ | 35,700 |
| | $ | 3,000 |
| | $ | 6,900 |
| | $ | 6,700 |
| | $ | 19,100 |
|
Drilling rig obligations(2) | 8,900 |
| | 8,900 |
| | — |
| | — |
| | — |
|
Volume commitment(3)(4) | 927,300 |
| | 95,600 |
| | 212,500 |
| | 215,100 |
| | 404,100 |
|
Revolving credit facility and interest payable(5) | 94,300 |
| | 94,300 |
| | — |
| | — |
| | — |
|
Senior Notes and Interest Payable(6) | 1,315,000 |
| | 72,800 |
| | 145,600 |
| | 652,300 |
| | 444,300 |
|
| Total | $ | 2,381,200 |
| | $ | 274,600 |
| | $ | 365,000 |
| | $ | 874,100 |
| | $ | 867,500 |
|
| |
(1) | We lease two office spaces in Denver, Colorado, two office spaces in Greeley, Colorado and one office space in Houston, Texas under four separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020 and May 31, 2028. The Greeley, Colorado and Houston, Texas leases expire on August 19, 2019, June 30, 2019 and January 31, 2022, respectively. Total rental commitments under non-cancelable leases for office space were $35.7 million at December 31, 2017. |
| |
(2) | As of December 31, 2017, we were subject to commitments on three drilling rigs. The three drilling rigs are under contract and are set to expire on February 15, 2018, August 21, 2018 and November 23, 2018. |
| |
(3) | As of December 31, 2017, our oil marketer is subject to a firm transportation agreement that commenced in November 2016 and has a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, we amended our agreement with our oil marketer that requires us to sell all of our crude oil from an area of mutual interest in exchange for a make-whole provision that allows us to satisfy any minimum volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2018. In December 2017, we extended the term of this agreement through October 31, 2019 and posted a letter of credit in the amount of $35.0 million. We evaluate our contracts for loss contingencies and accrue for such losses, if the loss can be reasonably estimated and deemed probable. We also have one long-term crude oil gathering commitment with an unconsolidated subsidiary, in which we have a minority ownership interest. It has a term of ten years with a minimum volume commitment of an average 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The remaining aggregate amount of estimated payments under these agreements is approximately $927.3 million. |
| |
(4) | In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, we agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes two new processing plants as well as the expansion of related gathering systems, which are currently expected to be completed by mid-2018 and mid-2019, respectively, although the exact start-up dates are undetermined at this time. Our share of these commitments will require 51.5 MMcf and 20.6 MMcf per day, respectively, to be delivered after the plants' in-service dates for a period of seven years thereafter. We may be required to pay a shortfall fee for any volumes under these commitments. These contractual obligations can be reduced by our proportionate share of the collective volumes delivered to the plants by other third party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. We are also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold. Under its current drilling plans, we expect to meet these volume commitments and they have therefore not been reflected in the table above. |
| |
(5) | Calculated based on balance of $90.0 million outstanding borrowings under our revolving credit facility as of December 31, 2017 and paid during the first quarter of 2018 and assumes no borrowings until the maturity date of the notes. Interest on our revolving credit facility is payable at one of the following two variable rates as selected by us: a base rate based on the Prime Rate or the Eurodollar rate based in LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the Pricing Grid. Additionally, our revolving credit facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. |
| |
(6) | Calculated based on the December 31, 2017 outstanding aggregate principal amount on our 2021 Senior Notes of $550.0 million outstanding, at a fixed interest rate of 7.875%, and outstanding principal amount on our 2024 Senior Notes of $400.0 million outstanding, at a fixed rate of 7.375%. Interest is payable on our 2021 Senior Notes and 2024 Senior Notes on a semi-annual basis through the maturity dates of July 15, 2021 and May 15, 2024, respectively. The 2026 Senior Notes are not included in the table above, as they were issued in January 2018. |
The above contractual obligations schedule does not include the Series A Preferred Stock, future anticipated settlement of derivative contracts or estimated amounts expected to be incurred in the future associated with the abandonment of our oil and gas properties, as we cannot determine with accuracy the timing of such payments. For further discussion regarding our derivative contracts and estimated future costs associated with the abandonment of our oil and gas properties, please refer to Note 9 — Equity, Note 6 — Commodity Derivative Instruments and Note 7 — Asset Retirement Obligations of our historical audited financial statements for the years ended December 31, 2017 and 2016. Additionally, for further information regarding our contractual obligations as of December 31, 2017, please refer to Note 13 — Commitments and Contingencies to our historical unaudited financial statements for the year ended December 31, 2017 and 2016.
As is customary in the oil and gas industry, we may at times have commitments in place to reserve or earn certain acreage positions or wells. If we do not meet such commitments, the acreage positions or wells may be lost or we may be required to pay damages if certain performance conditions are not met.
Off‑BalanceOff-Balance Sheet Arrangements
As of December 31, 2017,2020, we do not have material off-balance sheet arrangements, except for our agreement with our oil marketer. Our oil marketer is subject to a firm transportation agreement with a make-whole provision that allows us to satisfy any minimum volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2019. Please see Note 13 - Commitments and Contingencies in Part II, Item 8 of this Annual Report.arrangements.
Impact of Inflation/Deflation and Pricing
All of our transactions are denominated in U.S. dollars. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, as prices for oil and natural gas decrease, costs decline. Cost declines tend to lag and may not adjust downward in proportion to decline commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the year ended December 31, 2015,2020, commodity prices decreased while during the yearsfirst and second quarters and subsequently increased in the third and fourth quarters. During the year ended December 31, 2017 and 2016,2019, commodity prices increased.decreased during the first quarter, increased in the second quarter, and subsequently decreased in the third quarter and fourth quarter. Changes in commodity prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel.
Critical Accounting Policies and Estimates
Use of Estimates in the Preparation of Financial Statements
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include include:
(1) oil and gas reserves;
(2) depreciation, depletion, amortization and accretion;
(3) cash flow estimates used in impairment testing of oil and gas propertiesproved and goodwill; (3) depreciation, depletion, amortization and accretion; unproved properties;
(4) asset retirement obligations; valuation of commodity derivative instruments;
(5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill;
(6) asset retirement obligations;
(7) accrued revenue and related receivables; (7)
(8) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of unit and stock-based payments,
(9) income taxes, and
(10) income taxes. bankruptcy proceedings.
Although management believes these estimates are reasonable, actual results could differ from these estimates. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe our estimates are reasonable.
Successful Efforts Method of Accounting
We follow the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
We capitalize interest, if debt is outstanding, during drilling operations in our exploration and development activities.
Oil and Gas Reserves
Our estimates of proved reserves are based on the quantities of oil, natural gas and NGL, 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 under existing economic 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. Our independent petroleum
engineers, Ryder Scott, prepare a reserve and economic evaluation of all of our properties on a well-by-well basis. The accuracy of reserve estimates is a function of the:
•quality and quantity of available data;
•interpretation of that data;
•accuracy of various mandated economic assumptions; and
•judgment of the independent reserve engineer.
One of the most significant estimates we make is the estimate of oil, natural gas and NGL reserves. Oil, natural gas and NGL reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, projected future production, economic assumptions relating to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation costs and these estimates are inherently uncertain. For example, if estimates of proved reserves decline, our DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of oil and gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. We cannot predict what reserve revisions may be required in future periods.
Ryder Scott estimated all of our proved reserve quantities as of December 31, 2017, 20162020 and 2015.2019. In connection with Ryder Scott performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.
The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 |
| Revisions resulting from price changes (MBOE) | (27,204) | | | (18,049) | |
| Revisions resulting from production, performance and other (MBOE) | (60,105) | | | (72,488) | |
| Total revisions (MBOE) | (87,309) | | | (90,537) | |
|
| | | | | | | | |
| | For the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Revisions resulting from price changes (MBOE) | 12,767 |
| | (6,666 | ) | | (48,578 | ) |
| Revisions resulting from production, performance and other (MBOE) | (9,873 | ) | | (955 | ) | | 47,428 |
|
| Total revisions (MBOE) | 2,894 |
| | (7,621 | ) | | (1,150 | ) |
The recent significant declineDeclines in oil, natural gas and NGL prices increasesincrease the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market. A prolonged period of depressed commodity prices may have a significant impact on the value and volumetric quantities of our proved reserve portfolio, assuming no other changes to our development plans or costs.
Depreciation, Depletion, Amortization and Accretion.Accretion
Our DD&A rate is dependent upon our estimates of total proved and proved developed reserves, which incorporate various assumptions and future projections. If our estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, which in turn reduces our net income. Such a decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploration and development program, as well as future economic conditions.
Impairment of Proved Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of itsour oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future
capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets and goodwill in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization.
For the year endedFuture commodity pricing for oil is based on five-year West Texas Intermediate strip prices, which decreased 14.0% from an average of $53.65/Bbl at December 31, 2017, we recognized no impairment expense on proved oil and gas properties. For the years ended2019 to an average of $46.14/Bbl at December 31, 2016 and 2015, we recognized $22.5 million and $9.5 million, respectively, in impairment expense2020. Future commodity pricing for natural gas is based on proved oil and gas properties in our northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in its northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book valuefive-year Henry Hub strip prices, which increased 4.9% from an average of these proved oil and gas properties were impaired$2.42/MMBtu at June 30, 2016 and 2015. In December 2015, we sold proved oil and gas properties for proceeds of $4.7 million. As a result, these assets were fair valued on the date of the transaction in accordance with ASC 360, Property, Plant and Equipment. The net book value of these assets exceeded the fair value by $2.7 million, which we recognized as impairment expense. We recognized $12.2 million in impairment expense that was attributable to proved oil and gas properties for the year ended December 31, 2015.2019 to an average of $2.54/MMBtu at December 31, 2020. Future commodity pricing for NGLs is based on five-year WTI strip prices, which decreased 10.7% from an average of $14.40/Bbl at December 31, 2019 to an average of $12.85/Bbl at December 31, 2020.
Our impairment analysesanalysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.
For the year ended December 31, 2020, our impairment expense related to oil and gas properties was $197.9 million. We recognized $3.6 million related to impairment of the proved oil and gas properties in our northern field and $194.3 million related to assets in one of our Core DJ Basin fields, as the fields’ fair values did not exceed the carrying amounts associated with our proved oil and gas properties. For the year ended December 31, 2019, our impairment expense was $1.3 billion. We recognized $14.5 million related to impairment of the proved oil and gas properties in our northern field and $1.3 billion related to assets in one of our Core DJ Basin fields as the fields’ fair values did not exceed the carrying amounts associated with our proved oil and gas properties.
Forward commodity prices and estimates of future production also play a significant role in determining impairment of proved oil and gas properties. As a result of lower commodity prices and their impact on our estimated future cash flows, we have continuedwill continue to review our proved oil and gas properties for impairment. After our fourth quarter 2020 impairment charges in two of our Core DJ Basin fields at December 31, 2020, the carrying value of our oil and gas properties exceeded our expected undiscounted future cash flows for proved and risk-adjusted probable and possible reserves by approximately $56.8 million and $340.3 million, in each field. After our fourth quarter 2019 impairment charges in two of our Core DJ Basin fields at
December 31, 2019, the carrying value of our oil and gas properties exceeded our expected undiscounted future cash flows for proved and risk-adjusted probable and possible reserves by approximately $33.8 million and $1.2 billion, in each field. At December 31, 2017,2018, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $1.6$0.8 billion, or 68%30%. At December 31, 2016, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $1.7 billion, or 108%. The key assumptions used to determine the undiscounted future cash flows include estimates of future production, future commodity pricing, differentials, net estimated operating costs, anticipated capital expenditures and new wells on production. Future commodity pricing for oil and NGL is based on five-year West Texas Intermediate strip prices, which decreased 3% from an average of $56.23/Bbl at December 31, 2016 to an average of $54.66/Bbl at December 31, 2017, and on five-year Henry Hub strip prices, which increased 1.9% from an average of $3.08/MMBtu at December 31, 2016 to an average of $3.14/MMBtu at December 31, 2017.
ImpairmentAbandonment of Unproved Oil and Gas Properties
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. We evaluate significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration and abandonment expenses in the consolidated statements of operations. As a result of the abandonment and impairment of unproved properties, we recognized $15.8 million, $22.3$253.1 million and $16.4$73.7 million in impairmentabandonment expense for the years ended December 31, 2017, 20162020 and 2015,2019, respectively. To the extent we do not elect to renew current leases, we expect further abandonment charges in 2021.
Goodwill and Other Intangible Assets
We apply the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated value of the net assets acquired in business combinations. We test goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents our oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of our common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. We performed an assessment as of September 30, 2017, which concluded the fair value of the reporting unit was greater than its carrying amount.
We performed a qualitative assessment as of December 31, 2017 and 2016, which concluded the fair value of the reporting unit was more-likely-than-not greater than its carrying amount.
Costs relating to the acquisition of internal-use software licenses are capitalized when incurred and amortized over the estimated useful life of the license.
Commodity Derivative Instruments
We have entered into commodity derivative instruments as described below. We have utilizedutilizing swaps put options, and call options to reduce the effect of price changes on a portion of our future oil and natural gas production. A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. A put option has an established floor price. The buyer of the put option pays the sellerFor a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Somedescription of our purchased put options have deferred premiums. For the deferred premium puts,derivative instruments that we agree to payutilize and a premium to the counterparty at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
We combine swaps, purchased put options, sold put options, and sold call options in order to achieve various hedging strategies. Some examplessummary of our hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options, and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap.
The objective of our use ofopen commodity derivative instruments is to achieve more predictable cash flows contracts as of December 31, 2020, please see Note 9 — Commodity Derivative Instruments in an environmentPart II, Item 8. Financial Statements and Supplementary Data of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit our ability to benefit from favorable price movements. We may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. We do not enter into derivative contracts for speculative purposes.this Annual Report.
The commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets.assets or liabilities. We have not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, we do not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivative gain (loss) line on the consolidated statements of operations. Our cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in our consolidated statements of cash flows.
Our valuation estimate takes into consideration the counterparties’ credit worthiness, our credit worthiness, and the time value of money. The consideration of the factors resultresults in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believesWe believe that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please see “—How We Evaluate Our Operations—Derivative Arrangements.”
Accounting for Business Combinations
We account for all of our business combinations using the purchaseacquisition method, which is the only method permitted under FASB ASC 805,, Business Combinations,, and involves the use of significant judgment. In connection with a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and gas
properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, we must prepare estimates. To estimate the fair values of these properties, we prepare estimates of gas, oil and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows 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 subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future net cash flows of probable and possible reserves are reduced by additional risk factors. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.
Asset Retirement Obligations
Our asset retirement obligations (“ARO”) consist of estimated future costs associated with the plugging and abandonment of oil, natural gas and NGL wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws, and applicable lease terms. The fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free discount rate to be used; and inflation rates. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property.
Revenue Recognition
RevenuesRevenue from the sale of oil, natural gas and NGL areNGLs is recognized whenin accordance with ASC 606 - Revenue from Contracts with Customers five-step revenue recognition model to depict the product is delivered at a fixedtransfer of goods or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. Weservices to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. To account for producer imbalances, we recognize revenues from the saleon all sales of oil, natural gas and NGL usingNGLs to third party customers regardless of their ownership percentage and adjust the sales method of accounting, wherebyunderlifter or overlifter’s claim on the asset’s remaining reserves. In other words, revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. We receive payment one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A 10% change in our revenue accrual would have impacted total operating revenues by approximately $9.3$6.3 million and $3.4$10.5 million for the years ended December 31, 20172020 and 2016,2019, respectively.
Unit and Stock‑BasedStock-Based Payments
The CompanyWe granted awards under the 2016 LTIP and its predecessor, Holdings, has granted restricted unit awards (“RUAs”)2021 LTIP (as defined in Note 14 — Stock-Based Compensation in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report) to certain directors, officers and employees, and nonemployee consultants of the Company,including stock options, restricted stock units, (“RSUs”), stock option awards and performance stock awards, ("PSAs) to certain employees of the Company,performance stock units, performance cash awards and cash awards which therefore required the Companyus to recognize the expense in itsour consolidated financial statements.
All unit and stock‑basedstock-based payments to employees are measured at fair value on the grant date and expensed over the relevant service period. Unit‑based payments to nonemployees are measured at fair value at each financial reporting date and expensed over the period of performance, such that aggregate expense recognized is equal to the fair value of the restricted units on the date performance is completed. The fair value of stock option awards is determined by using the Black-Scholes option pricing model. The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. All unit and stock‑basedstock-based payment expense is recognized using the straight‑linestraight-line method and is included within general and administrative expenses in the consolidated statements of operations and unit and stock-based compensation
in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 1114 — UnitStock-Based Compensation in Part II, Item 8. Financial Statements and Stock‑Based CompensationSupplementary Data of this Annual Report for additional discussion on unit and stock‑basedstock-based payments.
Income Taxes
We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by deferralfederal and state taxing authorities.
We periodically assess whether it is more likely than not that itthe Company will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses.NOLs. In making this determination, we consider all the available positive and negative evidence and makesmake certain assumptions. We consider, among other things, our deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. We believe it is more likely than not that certain net operating losses canthe benefit from NOL carryforwards will not be carried forward and utilized.fully realized. In recognition of this risk, we have provided a valuation allowance on the deferred tax assets.
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 consolidated 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. We do not currently have uncertain tax positions.
On December 22, 2017, United States legislation referredThe CARES Act provides relief to corporate taxpayers by permitting a five year carryback of 2018-2020 NOLs, removing the 80% limitation on the carryback of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020 as the "Tax Cutswell as allowing 2019 adjusted taxable income to be utilized for 2020 limitation purposes, and Jobs Act" (the "TCJA") was signed into law. Many of the provisions of the TCJA are effectiveaccelerating refunds for taxable years beginning after December 31, 2017. The TCJA includes changes to the Internal Revenue Code of 1986 (as amended, the "Code"). The most significant change included in the TCJA isminimum tax credit carryforwards, along with a reduction in the corporate federal income tax rate from 35% to 21%. Asfew other provisions.
Bankruptcy Proceedings
Effective June 14, 2020, as a result of the enactment datefiling of December 22, 2017,the Chapter 11 Cases, we began accounting and reporting according to ASC Topic 852 — Reorganizations in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 Cases, distinguish transactions and events that are required to remeasuredirectly associated with the deferred tax assetsreorganization from the ongoing operations of the business. Accordingly, certain professional fees, damages from rejected and liabilities at the rate in which they are expected to reverse. This re-measurement of deferred tax assets and liabilities will require us to analyze and record a one-time adjustment to reduce the overall deferred tax liabilitysettled contracts incurred in the bankruptcy proceedings, including losses related to executory contracts that were approved for rejection by the Bankruptcy Court, and unamortized deferred financing costs associated with debt classified as liabilities subject to compromise, are recorded in reorganization items, net on our accompanying consolidated statements of operations. In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on our consolidated balance sheets and affect a corresponding income tax benefit in the consolidated statementsas of operations for the year ended December 31, 2017. We believe2020 as liabilities subject to compromise. These liabilities are reported at the accounting is complete regardingamounts we anticipate will be allowed by the revaluationBankruptcy Court, even if they may be settled for lesser amounts. Please refer to Note 2 —Basis of the deferred tax balances. This resulted Presentation and Significant Accounting Policies — Significant Accounting Policies in the recordingPart II, Item 8. Financial Statements and Supplementary Data of an income tax benefit of $23.4 million, as well as a corresponding reduction in the deferred tax liability. We are currently evaluating other potential impacts of the TCJA.this Annual Report.
Extraction Oil & Gas Holdings, LLC, our accounting predecessor, was a limited liability company that was not subject to U.S. federal income tax.
Recent Accounting Pronouncements
Please refer to Recent Accounting Pronouncements in Note 2 —Basis of Presentation and Significant Accounting Policies — Recent Accounting Pronouncements in Part II, Item 88. Financial Statements and Supplementary Data of this Annual Report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGL has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.
To reduce the impact of fluctuations in oil prices on our revenues, we have periodically entered into commodity derivative contracts with respect to certain of our oil and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil prices at targeted levels and to manage our exposure to oil price fluctuations.
The following tables present our derivative positions relatedinformation responsive to crude oil and natural gas sales in effect asItem 305 of December 31, 2017:Regulation S-K is not required of smaller reporting companies.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended |
| | March 31, | | June 30, | | September 30, | | December 31, | | March 31, | | June 30, |
| | 2018 | | 2018 | | 2018 | | 2018 | | 2019 | | 2019 |
NYMEX WTI Crude Swaps: | | | | | | | | | | | |
| Notional volume (Bbl) | 1,500,000 |
| | 1,500,000 |
| | 1,050,000 |
| | 1,050,000 |
| | — |
| | — |
|
| Weighted average fixed price ($/Bbl) | $ | 50.70 |
| | $ | 50.70 |
| | $ | 52.91 |
| | $ | 52.91 |
| | | | |
NYMEX WTI Crude Sold Calls: | |
| | |
| | |
| | |
| | |
| | |
|
| Notional volume (Bbl) | 1,885,000 |
| | 1,485,000 |
| | 2,460,000 |
| | 2,460,000 |
| | 2,550,000 |
| | 2,550,000 |
|
| Weighted average fixed price ($/Bbl) | $ | 55.89 |
| | $ | 56.52 |
| | $ | 56.20 |
| | $ | 56.20 |
| | $ | 55.93 |
| | $ | 55.93 |
|
NYMEX WTI Crude Sold Puts: | |
| | |
| | |
| | |
| | |
| | |
|
| Notional volume (Bbl) | 3,419,400 |
| | 3,419,400 |
| | 3,300,000 |
| | 3,300,000 |
| | 2,550,000 |
| | 2,550,000 |
|
| Weighted average purchased put price ($/Bbl) | $ | 38.22 |
| | $ | 38.22 |
| | $ | 40.00 |
| | $ | 40.00 |
| | $ | 39.82 |
| | $ | 39.82 |
|
NYMEX WTI Crude Purchased Puts: | |
| | | | |
| | |
| | |
| | |
|
| Notional volume (Bbl) | 4,063,800 |
| | 3,763,800 |
| | 2,250,000 |
| | 2,250,000 |
| | 2,550,000 |
| | 2,550,000 |
|
| Weighted average purchased put price ($/Bbl) | $ | 42.20 |
| | $ | 41.66 |
| | $ | 49.81 |
| | $ | 49.81 |
| | $ | 49.69 |
| | $ | 49.69 |
|
NYMEX HH Natural Gas Swaps: | |
| | |
| | |
| | |
| | |
| | |
|
| Notional volume (MMBtu) | 10,500,000 |
| | 10,500,000 |
| | 9,900,000 |
| | 9,900,000 |
| | — |
| | — |
|
| Weighted average fixed price ($/MMBtu) | $ | 3.30 |
| | $ | 3.03 |
| | $ | 3.03 |
| | $ | 3.03 |
| | | | |
NYMEX HH Natural Gas Purchased Puts: | |
| | |
| | |
| | |
| | |
| | |
|
| Notional volume (MMBtu) | 600,000 |
| | 600,000 |
| | 600,000 |
| | 600,000 |
| | — |
| | — |
|
| Weighted average fixed price ($/MMBtu) | $ | 3.00 |
| | $ | 3.00 |
| | $ | 3.00 |
| | $ | 3.00 |
| | | | |
NYMEX HH Natural Gas Sold Calls: | |
| | |
| | |
| | |
| | |
| | |
|
| Notional volume (MMBtu) | 600,000 |
| | 600,000 |
| | 600,000 |
| | 600,000 |
| | — |
| | — |
|
| Weighted average fixed price ($/MMBtu) | $ | 3.15 |
| | $ | 3.15 |
| | $ | 3.15 |
| | $ | 3.15 |
| | | | |
CIG Basis Gas Swaps: | |
| | |
| | |
| | |
| | |
| | |
|
| Notional volume (MMBtu) | 6,300,000 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Weighted average fixed basis price ($/MMBtu) | $ | (0.31 | ) | | | | | | | | | | |
AsTable of December 31, 2017, the fair market value of our oil derivative contracts was a net liability of $92.3 million. Based on our open oil derivative positions at December 31, 2017, a 10% increase in the NYMEX WTI price would increase our net oil derivative liability by approximately $90.9 million, while a 10% decrease in the NYMEX WTI price would decrease our net oil derivative liability by approximately $81.8 million. As of December 31, 2017, the fair market value of our natural gas derivative contracts was a net asset of $11.7 million. Based upon our open commodity derivative positions at December 31, 2017, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately $11.8 million, while a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas derivate asset by approximately $11.8 million. Please see “—Derivative Arrangements.”ContentsCounterparty and Customer Credit Risk
Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.
We sell oil, natural gas and NGL to various types of customers, including oil marketers, pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside of our control, none of which can be predicted with certainty. For the year ended December 31, 2017, we had certain major customers that exceeded 10% of total oil, natural gas and NGL revenues. We do not believe the loss of any single purchaser would materially impact its operating results because oil, natural gas and NGL are fungible products with well‑established markets and numerous purchasers.
At December 31, 2017, we had commodity derivative contracts with seven counterparties, all of whom are lenders under our credit agreement. We do not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market‑makers. Additionally, we use master netting agreements to minimize credit‑risk exposure. The creditworthiness of our counterparties is subject to periodic review. Three of the seven counterparties to the derivative instruments are highly rated entities with corporate ratings at A3 classifications or above by Moody’s. Three additional counterparties have a corporate rating of Baa1 by Moody’s. One counterparty is a private entity and has a corporate rating of NAIC-2 by the National Association of Insurance Commissioners. For the years ended December 31, 2017, 2016 and 2015, we did not incur any losses with respect to counterparty contracts. None of our existing derivative instrument contracts contains credit‑risk related contingent features.
Interest Rate Risk
At December 31, 2017, we had $90.0 million of variable‑rate debt outstanding. The impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $0.9 million. We may begin entering into interest rate swap arrangements on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR if we have variable-rate debt outstanding in the future. See “—Liquidity and Capital Resources—Debt Arrangements.”
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EXTRACTION OIL & GAS, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | |
| Financial Statements: | Page |
| |
| |
| |
| |
| |
| |
| |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Extraction Oil & Gas, Inc.
OpinionsOpinion on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Extraction Oil & Gas, Inc. and its subsidiaries (the “Company”) as of December 31, 20172020 and 2016,2019 and the related consolidated statements of operations, of changes in members’stockholders’ equity (deficit) and stockholders’ equitynoncontrolling interest and of cash flows for each of the three years in the period ended December 31, 2017,2020, including the related notes (collectively referred to as the “consolidated financial statements”).We also have audited the Company's internal control over financial reporting as of December 31, 2017, 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 consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172020 and 2016, 2019 and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20172020 in conformity with accounting principles generally accepted in the United States of America. Also
Change in our opinion,Accounting Principle
As discussed in Note 2 to the consolidated financial statements, the Company maintained,changed the manner in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria establishedwhich it accounts for leases in Internal Control - Integrated Framework(2013)issued by the COSO.2019.
Basis for OpinionsOpinion
The Company's management is responsible for theseThese consolidated financial statements for maintaining effective internal control over financial reporting, and for its assessmentare the responsibility of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A.Company’s management. Our responsibility is to express opinionsan opinion on the Company’s consolidatedfinancial statements and on the Company'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")(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 of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditsaudit to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effectivefraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting was maintained in all material respects.
Our auditsbut not for the purpose of expressing an opinion on the effectiveness of the consolidatedCompany's internal control over financial statementsreporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial 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 consolidatedfinancial 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 consolidatedfinancial 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.opinion.
DefinitionCritical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and Limitationsthat (i) relate 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 Internal Control over Financial Reportingcritical 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
A company’s internal control overThe Impact of Proved Oil, Natural Gas, and Natural Gas Liquids (NGL) Reserves on Net Oil and Gas Properties
As described in Note 3 to the consolidated financial reportingstatements, the Company’s consolidated proved oil and gas properties balance was $4,743.5 million as of December 31, 2020, and depletion, depreciation, amortization and accretion expense was $332.3 million for the year ended December 31, 2020. As disclosed by management, estimates of proved reserves are based on the quantities of oil, natural gas and NGL, 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 under existing economic 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. The accuracy of reserve estimates is a process designedfunction of the quality and quantity of available data; interpretation of that data; accuracy of various mandated economic assumptions; and judgment of the independent reserve engineer. The Company follows the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Oil, natural gas and NGL reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, provide reasonable assurance regardingadditional development activity, production history, projected future production, economic assumptions relating to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation costs and these estimates are inherently uncertain. Independent petroleum engineers prepare a reserve and economic evaluation of all of the reliabilityCompany’s properties on a well-by-well basis.
The principal considerations for our determination that performing procedures relating to the impact of proved oil, natural gas, and NGL reserves on net oil and gas properties is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved oil, natural gas and NGL reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil, natural gas, and NGL reserves and the preparationassumptions applied to the data related to the projected future production, commodity prices, future development costs, and operating expenses.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of proved oil, natural gas, and NGL reserves. 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’ findings. These procedures also included, among others, testing the completeness and accuracy of data related to commodity prices, future development costs, and operating expenses. Additionally, these procedures included evaluating whether the assumptions applied to the data related to projected future production, commodity prices, future development costs, and operating costs were reasonable considering the past performance of the Company.
Impairment Assessments of Certain Net Oil and Gas Properties
As described in Notes 2, 3, and 11 to the consolidated financial statements, as of December 31, 2020, the Company’s proved crude oil and gas properties were approximately $4,743.5 million, which includes impairment expense related to oil and gas properties of $197.9 million for external purposesthe year then ended. Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policiesthe recoverability of the carrying amount of such property. For all of its fields, the Company estimates the expected future cash flows of its oil and procedures that (i) pertaingas properties and compares these undiscounted cash flows to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositionscarrying amount of the assetsoil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the company;oil and gas properties to fair value. To determine fair value, the Company uses an income approach analysis based on the net discounted future cash flows of proved property. The Company calculates the estimated fair values of its proved property oil and gas assets using a discounted future cash flow model. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) provide reasonable assurance that transactions are recorded as necessaryfuture operating and development costs, (iii) future commodity prices, and (iv) a market-based weighted average cost of capital. The Company recognized $3.6 million related to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expendituresimpairment of the company are being made onlyproved oil and gas properties in accordance with authorizations of managementthe Company’s northern field and directors$194.3 million related to assets in one of the company;Company’s Core DJ Basin fields, as the fields’ fair values did not exceed the carrying amounts associated with the proved oil and gas properties.
The principal considerations for our determination that performing procedures relating to the impairment assessments of certain net oil and gas properties is a critical audit matter are (i) the significant judgment by management when developing the undiscounted and net discounted future cash flow analyses for the impairment assessments, (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s assumptions related to recoverable reserves, future operating and development costs, future commodity prices, and the market-based weighted average cost of capital, and (iii) provide reasonable assurance regarding prevention or timely detectionthe audit effort involved the use of unauthorized acquisition, use, or dispositionprofessionals with specialized skill and knowledge.
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, among others (i) testing management’s process for developing the undiscounted and net discounted future cash flow analyses; (ii) evaluating the appropriateness of the company’s assets that could haveundiscounted and net discounted cash flow analyses; (iii) testing the completeness and accuracy of the underlying data used in the models; and (iv) evaluating the significant assumptions used by management related to recoverable reserves, future operating and development costs, future commodity prices, and the market-based weighted average cost of capital. Evaluating the reasonableness of management’s assumptions related to (i) future operating and development costs involved consideration of the past and anticipated performance of the Company and (ii) future commodity prices involved consideration of observable market data. The work of specialists was used in performing the procedures to evaluate the reasonableness of the recoverable reserves, as stated in the Critical Audit Matter titled “The Impact of Proved Oil, Natural Gas, and Natural Gas Liquids (NGL) Reserves on Net Oil and Gas Properties”. As a material effect onbasis for using this work, the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyspecialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of effectivenessthe methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings. Professionals with specialized skill and knowledge were used to future periods are subject toassist in evaluating the risk that controls may become inadequate becausereasonableness of changes in conditions, or that the degreemarket-based weighted average cost of compliance with the policies or procedures may deteriorate.capital.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 27, 2018March 18, 2021
We have served as the Company’s auditor since 2014.
EXTRACTION OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(Debtor-In-Possession)
(In thousands, except share data)
| | | | | | | | | | | |
| | December 31,
2020 | | December 31,
2019 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 205,890 | | | $ | 32,382 | |
| Accounts receivable, net | | | |
| Trade | 13,266 | | | 32,009 | |
| Oil, natural gas and NGL sales | 63,429 | | | 105,103 | |
| Inventory, prepaid expenses and other | 36,382 | | | 36,702 | |
| Commodity derivative asset | 6,971 | | | 17,554 | |
| Total Current Assets | 325,938 | | | 223,750 | |
| Property and Equipment (successful efforts method), at cost: | | | |
| Proved oil and gas properties | 4,743,463 | | | 4,530,934 | |
| Unproved oil and gas properties | 220,380 | | | 524,214 | |
| Wells in progress | 129,058 | | | 149,733 | |
| Less: accumulated depletion, depreciation, amortization and impairment charges | (3,459,689) | | | (2,985,983) | |
| Net oil and gas properties | 1,633,212 | | | 2,218,898 | |
| Gathering systems and facilities, net of accumulated depreciation—Note 2 | 0 | | | 315,777 | |
| Other property and equipment, net of accumulated depreciation and impairment charges—Note 2 | 56,701 | | | 72,542 | |
| Net Property and Equipment | 1,689,913 | | | 2,607,217 | |
| Non-Current Assets: | | | |
| Commodity derivative asset | 0 | | | 13,229 | |
| Other non-current assets | 9,348 | | | 82,761 | |
| Total Non-Current Assets | 9,348 | | | 95,990 | |
| Total Assets | $ | 2,025,199 | | | $ | 2,926,957 | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Accounts payable and accrued liabilities | $ | 80,082 | | | $ | 190,864 | |
| Revenue payable | 49,376 | | | 108,493 | |
| Production taxes payable | 2,595 | | | 115,489 | |
| Commodity derivative liability | 2,147 | | | 1,998 | |
| Accrued interest payable | 692 | | | 20,625 | |
| Asset retirement obligations | 0 | | | 27,058 | |
| DIP Credit Facility—Note 8 | 106,727 | | | 0 | |
| Prior Credit Facility—Note 8 | 453,747 | | | 0 | |
| Total Current Liabilities | 695,366 | | | 464,527 | |
| Non-Current Liabilities: | | | |
| Prior Credit Facility—Note 8 | 0 | | | 470,000 | |
| Senior Notes, net of unamortized debt issuance costs—Note 8 | 0 | | | 1,085,777 | |
| Production taxes payable | 33,627 | | | 98,740 | |
| Commodity derivative liability | 0 | | | 108 | |
| Other non-current liabilities | 0 | | | 54,579 | |
| Asset retirement obligations | 0 | | | 68,850 | |
| | | |
| Total Non-Current Liabilities | 33,627 | | | 1,778,054 | |
| Liabilities Subject to Compromise | 2,143,497 | | | 0 | |
| Total Liabilities | 2,872,490 | | | 2,242,581 | |
| Commitments and Contingencies—Note 16 | | | |
| Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding | 191,754 | | | 175,639 | |
| Stockholders’ Equity (Deficit): | | | |
| Common stock, $0.01 par value; 900,000,000 shares authorized; 136,588,900 and 137,657,922 issued and outstanding, respectively | 1,336 | | | 1,336 | |
| Treasury stock, at cost, 38,859,078 shares | (170,138) | | | (170,138) | |
| Additional paid-in capital | 2,140,499 | | | 2,156,383 | |
| Accumulated deficit | (3,010,742) | | | (1,743,208) | |
| Total Extraction Oil & Gas, Inc. Stockholders’ Equity (Deficit) | (1,039,045) | | | 244,373 | |
| Noncontrolling interest—Note 12 | 0 | | | 264,364 | |
| Total Stockholders’ Equity (Deficit) | (1,039,045) | | | 508,737 | |
| Total Liabilities and Stockholders’ Equity | $ | 2,025,199 | | | $ | 2,926,957 | |
|
| | | | | | | |
| | December 31,
2017 | | December 31,
2016 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 6,768 |
| | $ | 588,736 |
|
| Accounts receivable | | | |
| Trade | 46,047 |
| | 23,154 |
|
| Oil, natural gas and NGL sales | 93,301 |
| | 34,066 |
|
| Inventory and prepaid expenses | 13,017 |
| | 7,722 |
|
| Commodity derivative asset | 4,132 |
| | — |
|
| Total Current Assets | 163,265 |
| | 653,678 |
|
| Property and Equipment (successful efforts method), at cost: | | | |
| Proved oil and gas properties | 3,011,526 |
| | 1,851,052 |
|
| Unproved oil and gas properties | 686,968 |
| | 452,577 |
|
| Wells in progress | 127,418 |
| | 98,747 |
|
| Less: accumulated depletion, depreciation and amortization | (709,662 | ) | | (402,912 | ) |
| Net oil and gas properties | 3,116,250 |
| | 1,999,464 |
|
| Other property and equipment, net of accumulated depreciation (Note 2) | 37,318 |
| | 32,721 |
|
| Net Property and Equipment | 3,153,568 |
| | 2,032,185 |
|
| Non-Current Assets: | | | |
| Cash held in escrow | — |
| | 42,200 |
|
| Goodwill and other intangible assets, net of accumulated amortization | 55,453 |
| | 54,489 |
|
| Other non-current assets | 12,383 |
| | 2,224 |
|
| Total Non-Current Assets | 67,836 |
| | 98,913 |
|
| Total Assets | $ | 3,384,669 |
| | $ | 2,784,776 |
|
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | |
| Current Liabilities: | | | |
| Accounts payable and accrued liabilities | $ | 211,581 |
| | $ | 131,134 |
|
| Revenue payable | 52,805 |
| | 35,162 |
|
| Production taxes payable | 37,444 |
| | 27,327 |
|
| Commodity derivative liability | 67,428 |
| | 56,003 |
|
| Accrued interest payable | 23,807 |
| | 19,621 |
|
| Asset retirement obligations | 6,873 |
| | 5,300 |
|
| Total Current Liabilities | 399,938 |
| | 274,547 |
|
| Non-Current Liabilities: | | | |
| Credit facility | 90,000 |
| | — |
|
| Senior Notes, net of unamortized debt issuance costs (Note 5) | 933,361 |
| | 538,141 |
|
| Production taxes payable | 57,982 |
| | 35,838 |
|
| Commodity derivative liability | 17,274 |
| | 6,738 |
|
| Other non-current liabilities | 5,973 |
| | 3,466 |
|
| Asset retirement obligations | 62,667 |
| | 50,808 |
|
| Deferred tax liability | 42,326 |
| | 106,026 |
|
| Total Non-Current Liabilities | 1,209,583 |
| | 741,017 |
|
| Total Liabilities | 1,609,521 |
| | 1,015,564 |
|
| Commitments and Contingencies—Note 13 | | | |
| Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 and 185,280 issued and outstanding, respectively | 158,383 |
| | 153,139 |
|
| Stockholders' Equity: | | | |
| Common Stock, $0.01 par value; 900,000,000 shares authorized; 172,059,814 and 171,834,605 issued and outstanding, respectively | 1,718 |
| | 1,718 |
|
Treasury Stock, at cost, 165,385 and 0 shares
| (2,105 | ) | | — |
|
| Additional paid-in capital | 2,114,795 |
| | 2,067,590 |
|
| Accumulated deficit | (497,643 | ) | | (453,235 | ) |
| Total Stockholders' Equity | 1,616,765 |
| | 1,616,073 |
|
| Total Liabilities and Stockholders' Equity | $ | 3,384,669 |
| | $ | 2,784,776 |
|
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART
OF THESE CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Debtor-In-Possession)
(In thousands, except per share data)
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Revenues: | | | | | |
| Oil sales | $ | 382,526 | | | $ | 721,429 | | | $ | 840,687 | |
| Natural gas sales | 96,701 | | | 108,873 | | | 105,629 | |
| NGL sales | 77,204 | | | 75,072 | | | 114,427 | |
| Gathering and compression | 1,473 | | | 1,261 | | | 0 | |
| Total Revenues | 557,904 | | | 906,635 | | | 1,060,743 | |
| Operating Expenses: | | | | | |
| Lease operating expenses | 77,836 | | | 97,254 | | | 79,413 | |
| Midstream operating expenses | 3,935 | | | 2,258 | | | 0 | |
| Transportation and gathering | 138,552 | | | 53,140 | | | 39,411 | |
| Production taxes | 29,038 | | | 68,182 | | | 90,345 | |
| Exploration and abandonment expenses | 258,932 | | | 88,794 | | | 31,611 | |
| Depletion, depreciation, amortization and accretion | 332,319 | | | 524,537 | | | 435,775 | |
| Impairment of long lived assets and goodwill | 208,463 | | | 1,337,996 | | | 70,928 | |
| (Gain) loss on sale of property and equipment and assets of unconsolidated subsidiary | (122) | | | 421 | | | (136,834) | |
| General and administrative expenses | 55,182 | | | 98,845 | | | 134,604 | |
| Other operating expenses | 79,615 | | | 0 | | | 0 | |
| Total Operating Expenses | 1,183,750 | | | 2,271,427 | | | 745,253 | |
| Operating Income (Loss) | (625,846) | | | (1,364,792) | | | 315,490 | |
| Other Income (Expense): | | | | | |
| Commodity derivatives gain (loss) | 164,968 | | | (37,107) | | | (8,554) | |
| Loss on deconsolidation of Elevation Midstream, LLC | (73,139) | | | 0 | | | 0 | |
| Reorganization items, net | (676,855) | | | 0 | | | 0 | |
| Interest expense (1) | (57,143) | | | (79,232) | | | (123,330) | |
| Other income | 481 | | | 4,535 | | | 5,099 | |
| Total Other Expense | (641,688) | | | (111,804) | | | (126,785) | |
| Income (Loss) Before Income Taxes | (1,267,534) | | | (1,476,596) | | | 188,705 | |
| Income tax (expense) benefit | 0 | | | 109,176 | | | (66,850) | |
| Net Income (Loss) | $ | (1,267,534) | | | $ | (1,367,420) | | | $ | 121,855 | |
| Net income attributable to noncontrolling interest | 6,160 | | | 19,992 | | | 7,287 | |
| Net Income (Loss) Attributable to Extraction Oil & Gas, Inc. | (1,273,694) | | | (1,387,412) | | | 114,568 | |
| Adjustments to reflect Series A Preferred Stock dividends and accretion of discount | (16,115) | | | (19,436) | | | (16,869) | |
| Net Income (Loss) Available to Common Shareholders, Basic and Diluted | $ | (1,289,809) | | | $ | (1,406,848) | | | $ | 97,699 | |
| | | | | |
| Net Income (Loss) Per Common Share—Note 15 | | | | | |
| Basic and diluted | $ | (9.34) | | | $ | (9.29) | | | $ | 0.56 | |
| Weighted Average Common Shares Outstanding | | | | | |
| Basic and diluted | 138,149 | | | 151,481 | | | 174,748 | |
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Revenues: | | | | | |
| Oil sales | $ | 419,904 |
| | $ | 194,059 |
| | $ | 157,024 |
|
| Natural gas sales | 92,322 |
| | 48,652 |
| | 26,019 |
|
| NGL sales | 92,070 |
| | 35,378 |
| | 14,707 |
|
| Total Revenues | 604,296 |
| | 278,089 |
| | 197,750 |
|
| Operating Expenses: | |
| | |
| | |
|
| Lease operating expenses | 111,306 |
| | 62,043 |
| | 30,628 |
|
| Production taxes | 51,367 |
| | 20,730 |
| | 17,035 |
|
| Exploration expenses | 36,256 |
| | 36,422 |
| | 18,636 |
|
| Depletion, depreciation, amortization and accretion | 314,999 |
| | 205,348 |
| | 146,547 |
|
| Impairment of long lived assets | 1,647 |
| | 23,425 |
| | 15,778 |
|
| Other operating expenses | 451 |
| | 10,891 |
| | 2,353 |
|
| Acquisition transaction expenses | — |
| | 2,719 |
| | 6,000 |
|
| General and administrative expenses | 110,167 |
| | 232,388 |
| | 37,149 |
|
| Total Operating Expenses | 626,193 |
| | 593,966 |
| | 274,126 |
|
| Operating Loss | (21,897 | ) | | (315,877 | ) | | (76,376 | ) |
| Other Income (Expense): | |
| | |
| | |
|
| Commodity derivatives gain (loss) | (36,332 | ) | | (100,947 | ) | | 79,932 |
|
| Interest expense | (51,889 | ) | | (68,843 | ) | | (51,030 | ) |
| Other income | 2,010 |
| | 386 |
| | 210 |
|
| Total Other Income (Expense) | (86,211 | ) | | (169,404 | ) | | 29,112 |
|
| Net Loss Before Income Taxes | (108,108 | ) | | (485,281 | ) | | (47,264 | ) |
| Income tax benefit | 63,700 |
| | 29,280 |
| | — |
|
| Net Loss | $ | (44,408 | ) | | $ | (456,001 | ) | | $ | (47,264 | ) |
| Loss Per Common Share (Note 12) | |
| | |
| | |
|
| Basic and diluted | $ | (0.35 | ) | | $ | (1.54 | ) | | |
|
| Weighted Average Common Shares Outstanding | |
| | |
| | |
|
| Basic and diluted | 171,910 |
| | 149,029 |
| | |
|
(1) Absent the automatic stay described in Note 8—Long-Term Debt, interest expense for the year ended December 31, 2020 would have been $94.5 million.
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Debtor-In-Possession)
(In thousands)
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | (1,267,534) | | | $ | (1,367,420) | | | $ | 121,855 | |
| Reconciliation of net income (loss) to net cash provided by operating activities: | | | | | |
| Depletion, depreciation, amortization and accretion | 332,319 | | | 524,537 | | | 435,775 | |
| Abandonment of unproved properties | 253,142 | | | 73,729 | | | 25,704 | |
| Impairment of long lived assets and goodwill | 208,463 | | | 1,337,996 | | | 70,928 | |
| (Gain) loss on sale of property and equipment | (122) | | | 1,431 | | | (53,222) | |
| Gain on sale of assets of unconsolidated subsidiary | 0 | | | (1,010) | | | (83,612) | |
| Gain on repurchase of 2026 Senior Notes | 0 | | | (10,486) | | | 0 | |
| Amortization of debt issuance costs and debt discount | 3,685 | | | 5,482 | | | 13,250 | |
| Non-cash lease expenses | 11,724 | | | 11,146 | | | 0 | |
| Non-cash reorganization items, net | 10,636 | | | 0 | | | 0 | |
| Contract asset | 12,317 | | | 24,700 | | | 0 | |
| Deferred rent | 0 | | | 0 | | | 348 | |
| (Gain) loss on commodity derivatives | (164,968) | | | 37,107 | | | 8,554 | |
| Settlements on commodity derivatives | 89,800 | | | (678) | | | (134,624) | |
| Premiums paid on commodity derivatives | 0 | | | (2,852) | | | (22,749) | |
| Loss on deconsolidation of Elevation Midstream, LLC | 73,139 | | | 0 | | | 0 | |
| Earnings in unconsolidated subsidiaries | (480) | | | (2,285) | | | (2,862) | |
| Distributions from unconsolidated subsidiary | 0 | | | 3,200 | | | 1,684 | |
| Make-whole premium expense on 2021 Senior Notes | 0 | | | 0 | | | 35,600 | |
| Deferred income tax expense (benefit) | 0 | | | (109,176) | | | 66,850 | |
| Stock-based compensation | 6,511 | | | 43,954 | | | 68,349 | |
| Changes in current assets and liabilities: | | | | | |
| Accounts receivable—trade | 16,900 | | | 3,630 | | | 8,562 | |
| Accounts receivable—oil, natural gas and NGL sales | 41,674 | | | (12,996) | | | 2,076 | |
| Inventory, prepaid expenses and other | (17,555) | | | (332) | | | (853) | |
| Accounts payable and accrued liabilities | 87,228 | | | (5,753) | | | (6,835) | |
| Accrued damages for rejected and settled contracts | 582,439 | | | 0 | | | 0 | |
| Revenue payable | (147) | | | (7,598) | | | 66,276 | |
| Production taxes payable | (3,631) | | | 40,957 | | | 79,106 | |
| Accrued interest payable | 11,743 | | | (1,624) | | | (1,558) | |
| Asset retirement expenditures | (21,308) | | | (27,702) | | | (13,669) | |
| Net cash provided by operating activities | 265,975 | | | 557,957 | | | 684,933 | |
| Cash flows from investing activities: | | | | | |
| Oil and gas property additions | (249,984) | | | (635,853) | | | (958,399) | |
| | | | | |
| Sale of property and equipment | 14,420 | | | 56,305 | | | 80,879 | |
| Gathering systems and facilities additions, net of cost reimbursements | 4,193 | | | (202,513) | | | (81,406) | |
| Other property and equipment additions | (3,697) | | | (39,090) | | | (15,991) | |
| Investment in unconsolidated subsidiaries | (10,033) | | | (30,012) | | | (6,000) | |
| | | | | |
| Sale of assets of unconsolidated subsidiary | 0 | | | 1,010 | | | 83,612 | |
| Net cash used in investing activities | (245,101) | | | (850,153) | | | (897,305) | |
| Cash flows from financing activities: | | | | | |
| Borrowings under Prior Credit Facility | 200,500 | | | 465,000 | | | 635,000 | |
| Repayments under Prior Credit Facility | (70,000) | | | (280,000) | | | (440,000) | |
| Borrowings under DIP Credit Facility | 35,000 | | | 0 | | | 0 | |
| Repayments under DIP Credit Facility | (3,273) | | | 0 | | | 0 | |
| Repurchase of 2026 Senior Notes | 0 | | | (39,325) | | | 0 | |
| Repurchase of common stock | 0 | | | (137,743) | | | (30,672) | |
| Payment of employee payroll withholding taxes | (120) | | | (1,851) | | | (5,327) | |
| Debt issuance costs and other financing fees | (1,745) | | | (2,104) | | | (3,175) | |
| Dividends on Series A Preferred Stock | 0 | | | (10,885) | | | (10,885) | |
| Proceeds from issuance of Preferred Units | 0 | | | 99,000 | | | 148,500 | |
| Preferred Unit issuance costs | 0 | | | (2,500) | | | (6,915) | |
| Proceeds from the issuance of Senior Notes | 0 | | | 0 | | | 739,664 | |
| Repayments of 2021 Senior Notes | 0 | | | 0 | | | (550,000) | |
| Make-whole premium paid on 2021 Senior Notes | 0 | | | 0 | | | (35,600) | |
| Net cash provided by financing activities | 160,362 | | | 89,592 | | | 440,590 | |
| Effect of deconsolidation of Elevation Midstream, LLC | (7,728) | | | 0 | | | 0 | |
| Increase (decrease) in cash, cash equivalents and restricted cash | 173,508 | | | (202,604) | | | 228,218 | |
| Cash, cash equivalents and restricted cash at beginning of period | 32,382 | | | 234,986 | | | 6,768 | |
| Cash, cash equivalents and restricted cash at end of the period | $ | 205,890 | | | $ | 32,382 | | | $ | 234,986 | |
| Supplemental cash flow information: | | | | | |
| Property and equipment included in accounts payable and accrued liabilities | $ | 14,878 | | | $ | 118,152 | | | $ | 141,952 | |
| Cash paid for interest | 47,032 | | | 93,084 | | | 84,224 | |
| Cash paid for reorganization items | 34,356 | | | 0 | | | 0 | |
| Preferred Units commitment fees and dividends paid-in-kind | 6,160 | | | 19,992 | | | 7,287 | |
| Series A Preferred Stock dividends paid-in-kind | 8,749 | | | 4,632 | | | 0 | |
| Accretion of beneficial conversion feature of Series A Preferred Stock | 7,366 | | | 6,640 | | | 5,984 | |
| Derivative unwinds decreasing Prior Credit Facility | 96,065 | | | 0 | | | 0 | |
| Draw on letter of credit increasing Prior Credit Facility | 24,311 | | | 0 | | | 0 | |
| Issuance of promissory note to unconsolidated subsidiary | 0 | | | 0 | | | 35,329 | |
| Extinguishment of promissory note in exchange for equity with unconsolidated subsidiary | 0 | | | 0 | | | (35,329) | |
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’STOCKHOLDERS’ EQUITY (DEFICIT) AND STOCKHOLDERS’ EQUITYNONCONTROLLING INTEREST
(Debtor-In-Possession)
(In thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Treasury Stock | | | | | | Extraction Oil & Gas, Inc. | | Noncontrolling Interest | | Total |
| | Shares | | Amount | | Shares | | Amount | | Additional Paid in Capital | | (Accumulated Deficit) | | Stockholders’
Equity (Deficit) | | Amount | | Stockholders’
Equity (Deficit) |
| Balance at January 1, 2018 | 172,060 | | | $ | 1,718 | | | 165 | | | $ | (2,105) | | | $ | 2,114,795 | | | $ | (497,643) | | | $ | 1,616,765 | | | $ | 0 | | | $ | 1,616,765 | |
| Preferred Units issued | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 148,500 | | | 148,500 | |
| Preferred Units issuance costs | — | | | — | | | — | | | — | | | — | | | — | | | — | | | (7,915) | | | (7,915) | |
| Preferred Units commitment fees and dividends paid-in-kind | — | | | — | | | — | | | — | | | (7,287) | | | — | | | (7,287) | | | 7,287 | | | 0 | |
| Stock-based compensation | 2,794 | | | — | | | — | | | — | | | 68,349 | | | — | | | 68,349 | | | — | | | 68,349 | |
| Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (10,885) | | | — | | | (10,885) | | | — | | | (10,885) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (5,984) | | | — | | | (5,984) | | | — | | | (5,984) | |
| Repurchase of common stock | — | | | (40) | | | 4,378 | | | (30,632) | | | — | | | — | | | (30,672) | | | — | | | (30,672) | |
| Restricted stock issued, net of tax withholdings and other | 1,356 | | | — | | | — | | | — | | | (5,327) | | | — | | | (5,327) | | | — | | | (5,327) | |
| Net income | — | | | — | | | — | | | — | | | — | | | 121,855 | | | 121,855 | | | — | | | 121,855 | |
| Balance at December 31, 2018 | 176,210 | | | $ | 1,678 | | | 4,543 | | | $ | (32,737) | | | $ | 2,153,661 | | | $ | (375,788) | | | $ | 1,746,814 | | | $ | 147,872 | | | $ | 1,894,686 | |
| Preferred Units issued | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 99,000 | | | 99,000 | |
| Preferred Units issuance costs | — | | | — | | | — | | | — | | | — | | | — | | | — | | | (2,500) | | | (2,500) | |
| Preferred Units commitment fees and dividends paid-in-kind | — | | | — | | | — | | | — | | | (19,992) | | | — | | | (19,992) | | | 19,992 | | | 0 | |
| Stock-based compensation | — | | | — | | | — | | | — | | | 44,001 | | | — | | | 44,001 | | | — | | | 44,001 | |
| Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (12,796) | | | — | | | (12,796) | | | — | | | (12,796) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (6,640) | | | — | | | (6,640) | | | — | | | (6,640) | |
| Repurchase of common stock | — | | | (342) | | | 34,316 | | | (137,401) | | | — | | | — | | | (137,743) | | | — | | | (137,743) | |
| Restricted stock issued, net of tax withholdings and other | 307 | | | — | | | — | | | — | | | (1,851) | | | — | | | (1,851) | | | — | | | (1,851) | |
| Net loss | — | | | — | | | — | | | — | | | — | | | (1,367,420) | | | (1,367,420) | | | — | | | (1,367,420) | |
| Balance at December 31, 2019 | 176,517 | | | $ | 1,336 | | | 38,859 | | | $ | (170,138) | | | $ | 2,156,383 | | | $ | (1,743,208) | | | $ | 244,373 | | | $ | 264,364 | | | $ | 508,737 | |
| Preferred Units commitment fees and dividends paid-in-kind | — | | — | | — | | — | | (6,160) | | — | | (6,160) | | | 6,160 | | 0 | |
| Stock-based compensation | — | | — | | — | | — | | 6,511 | | — | | 6,511 | | | — | | 6,511 | |
| Series A Preferred Stock dividends | — | | — | | — | | — | | (8,749) | | — | | (8,749) | | | — | | (8,749) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | — | | — | | — | | (7,366) | | — | | (7,366) | | | — | | (7,366) | |
| Restricted stock issued, net of tax withholdings and other | 714 | | — | | — | | — | | (120) | | — | | (120) | | | — | | (120) | |
| Cancellation of Performance Stock Awards - Note 14 | (1,783) | | — | | — | | — | | — | | — | | — | | | — | | — | |
| Net loss | — | | — | | — | | — | | — | | (1,267,534) | | (1,267,534) | | | — | | (1,267,534) | |
| Effects of deconsolidation of Elevation Midstream, LLC | — | | — | | — | | — | | — | | — | | — | | | (270,524) | | (270,524) | |
| Balance at December 31, 2020 | 175,448 | | | $ | 1,336 | | | 38,859 | | | $ | (170,138) | | | $ | 2,140,499 | | | $ | (3,010,742) | | | $ | (1,039,045) | | | $ | 0 | | | $ | (1,039,045) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Members' Units | | Common Stock | | Treasury Stock | | | | | | |
| | | | Preferred | | | | | | | | | | | | Additional | | Retained | | |
| | Tranche A | | Tranche C | | | | | | | | | | | | Paid in | | Earnings | | Total |
| | Units | | Units | | Amount | | Shares | | Amount | | Shares | | Amount | | Capital | | (Deficit) | | Equity |
| Balance at January 1, 2015 | 227,903 |
| | — |
| | $ | 495,158 |
| | — |
| | $ | — |
| | — |
| | $ | — |
| | $ | — |
| | $ | 50,030 |
| | $ | 545,188 |
|
| Units issued | — |
| | 78,444 |
| | 254,986 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 254,986 |
|
| Unit issuance costs | — |
| | — |
| | (4,648 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4,648 | ) |
| Restricted units issued | 3,198 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Unit-based compensation | — |
| | — |
| | 5,970 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5,970 |
|
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (47,264 | ) | | (47,264 | ) |
| Balance at December 31, 2015 | 231,101 |
| | 78,444 |
| | $ | 751,466 |
| | — |
| | $ | — |
| | — |
| | $ | — |
| | $ | — |
| | $ | 2,766 |
| | $ | 754,232 |
|
| Units issued | — |
| | 37,345 |
| | 121,370 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 121,370 |
|
| Units repurchased | (1,327 | ) | | (82 | ) | | (8,429 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (8,429 | ) |
| Settlement of promissory notes issued to officers | — |
| | — |
| | 5,562 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5,562 |
|
| Unit issuance costs | — |
| | — |
| | (1,022 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1,022 | ) |
| Restricted units issued | 7,661 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Unit-based compensation | — |
| | — |
| | 14,922 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 14,922 |
|
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 185,386 |
| | — |
| | 185,386 |
|
| Corporate Reorganization of Extraction Oil & Gas Holdings and Extraction Oil & Gas, Inc. | (237,435 | ) | | (115,707 | ) | | (883,869 | ) | | 108,461 |
| | 1,085 |
| | — |
| | — |
| | 882,784 |
| | — |
| | — |
|
| Net deferred tax liability due to Corporate Reorganization | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (135,306 | ) | | — |
| | (135,306 | ) |
| Issuance of common stock in initial public offering | — |
| | — |
| | — |
| | 38,333 |
| | 383 |
| | — |
| | — |
| | 727,950 |
| | — |
| | 728,333 |
|
| Issuance of common stock in private placement | — |
| | — |
| | — |
| | 25,041 |
| | 250 |
| | — |
| | — |
| | 456,749 |
| | — |
| | 456,999 |
|
| Common stock issuance costs | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (62,437 | ) | | — |
| | (62,437 | ) |
| Series A Preferred Units | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Dividends paid on Series A Preferred Units | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (15,000 | ) | | — |
| | (15,000 | ) |
| Series A Preferred Units issuance costs | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1,233 | ) | | — |
| | (1,233 | ) |
| Series B Preferred Unit and Series A Preferred Stock dividends | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2,958 | ) | | — |
| | (2,958 | ) |
| Beneficial conversion feature on Series A Preferred Stock | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32,696 |
| | — |
| | 32,696 |
|
| Accretion of beneficial conversion feature on Series A Preferred Stock | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1,041 | ) | | — |
| | (1,041 | ) |
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (456,001 | ) | | (456,001 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Members' Units | | Common Stock | | Treasury Stock | | | | | | |
| | | | Preferred | | | | | | | | | | | | Additional | | Retained | | |
| | Tranche A | | Tranche C | | | | | | | | | | | | Paid in | | Earnings | | Total |
| | Units | | Units | | Amount | | Shares | | Amount | | Shares | | Amount | | Capital | | (Deficit) | | Equity |
| Balance at December 31, 2016 | — |
| | — |
| | $ | — |
| | 171,835 |
| | $ | 1,718 |
| | — |
| | $ | — |
| | $ | 2,067,590 |
| | $ | (453,235 | ) | | $ | 1,616,073 |
|
| Common stock issuance costs | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (319 | ) | | — |
| | (319 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 65,607 |
| | — |
| | 65,607 |
|
| Issuance costs on Series A Preferred Stock | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Series A Preferred Stock dividends | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (10,885 | ) | | — |
| | (10,885 | ) |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (5,394 | ) | | — |
| | (5,394 | ) |
| Repurchase of common stock | — |
| | — |
| | — |
| | — |
| | — |
| | 165 |
| | (2,105 | ) | | — |
| | — |
| | (2,105 | ) |
| Shares issued under LTIP, including payment of tax withholdings using withheld shares | — |
| | — |
| | — |
| | 225 |
| | — |
| | — |
| | — |
| | (1,804 | ) | | — |
| | (1,804 | ) |
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (44,408 | ) | | (44,408 | ) |
| Balance at December 31, 2017 | — |
| | — |
| | $ | — |
| | 172,060 |
| | $ | 1,718 |
| | 165 |
| | $ | (2,105 | ) | | $ | 2,114,795 |
| | $ | (497,643 | ) | | $ | 1,616,765 |
|
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Cash flows from operating activities: | | | | | |
| Net loss | $ | (44,408 | ) | | $ | (456,001 | ) | | $ | (47,264 | ) |
| Reconciliation of net loss to net cash provided by operating activities: | | | | | |
| Depletion, depreciation, amortization and accretion | 314,999 |
| | 205,348 |
| | 146,547 |
|
| Abandonment and impairment of unproved properties | 15,808 |
| | 22,318 |
| | 16,414 |
|
| Impairment of long lived assets | 1,647 |
| | 23,425 |
| | 15,778 |
|
| Loss on sale of property and equipment | 451 |
| | — |
| | — |
|
| Non-cash acquisition transaction expenses | — |
| | — |
| | 6,000 |
|
| Amortization of debt issuance costs and debt discount | 4,260 |
| | 19,088 |
| | 5,604 |
|
| Deferred rent | (294 | ) | | 551 |
| | 488 |
|
| Commodity derivatives (gain) loss | 36,332 |
| | 100,947 |
| | (79,932 | ) |
| Settlements on commodity derivatives | (11,985 | ) | | 42,827 |
| | 55,770 |
|
| Premiums paid on commodity derivatives | (475 | ) | | (611 | ) | | (5,744 | ) |
| Earnings in unconsolidated subsidiary | (415 | ) | | — |
| | — |
|
| Distributions from unconsolidated subsidiary | 415 |
| | — |
| | — |
|
| Deferred income tax benefit | (63,700 | ) | | (29,280 | ) | | — |
|
| Unit and stock-based compensation | 65,607 |
| | 200,308 |
| | 5,970 |
|
| Changes in current assets and liabilities: | | | | | |
| Accounts receivable—trade | (22,634 | ) | | (574 | ) | | 7,723 |
|
| Accounts receivable—oil, natural gas and NGL sales | (59,235 | ) | | (18,128 | ) | | (4,520 | ) |
| Inventory and prepaid expenses | (523 | ) | | (1,110 | ) | | (1,024 | ) |
| Accounts payable and accrued liabilities | 31,202 |
| | (19,187 | ) | | 24,452 |
|
| Revenue payable | 17,643 |
| | (6,602 | ) | | 2,984 |
|
| Production taxes payable | 32,252 |
| | 14,585 |
| | 19,085 |
|
| Accrued interest payable | 4,186 |
| | 19,171 |
| | 277 |
|
| Asset retirement expenditures | (4,168 | ) | | (687 | ) | | (1,742 | ) |
| Due to related party | — |
| | — |
| | (183 | ) |
| Net cash provided by operating activities | 316,965 |
| | 116,388 |
| | 166,683 |
|
| Cash flows from investing activities: | | | | | |
| Oil and gas property additions | (1,370,787 | ) | | (449,600 | ) | | (391,250 | ) |
| Acquired oil and gas properties | (17,225 | ) | | (419,009 | ) | | (120,524 | ) |
| Sale of property and equipment | 5,155 |
| | 2,656 |
| | 4,742 |
|
| Other property and equipment additions | (22,189 | ) | | (7,655 | ) | | (23,045 | ) |
| Distributions from unconsolidated subsidiary, return of capital | 518 |
| | — |
| | — |
|
| Cash held in escrow | 42,200 |
| | (42,200 | ) | | 10,071 |
|
| Net cash used in investing activities | (1,362,328 | ) | | (915,808 | ) | | (520,006 | ) |
| Cash flows from financing activities: | | | | | |
| Borrowings under credit facility | 565,000 |
| | 263,000 |
| | 125,000 |
|
| Repayments under credit facility | (475,000 | ) | | (488,000 | ) | | — |
|
| Proceeds from the issuance of Senior Notes | 394,000 |
| | 550,000 |
| | — |
|
| Repayments of Second Lien Notes | — |
| | (430,000 | ) | | — |
|
| Proceeds from the issuance of units | — |
| | 121,370 |
| | 254,986 |
|
| Repurchase of units | (2,105 | ) | | (2,867 | ) | | — |
|
| Payment of employee payroll withholding taxes | (1,804 | ) | | — |
| | — |
|
| Issuance of common stock | — |
| | 1,185,332 |
| | — |
|
| Issuance of Series A Preferred Units | — |
| | 75,000 |
| | — |
|
| Redemption of Series A Preferred Units | — |
| | (88,688 | ) | | — |
|
| Dividends on Series A Preferred Stock | (10,401 | ) | | — |
| | — |
|
| Proceeds from the issuance of Series B Preferred Units | — |
| | 185,280 |
| | — |
|
| Dividends on Series B Preferred Units | — |
| | (721 | ) | | — |
|
| Debt issuance costs | (4,627 | ) | | (14,102 | ) | | (2,876 | ) |
|
| | | | | | | | | | | |
| Unit and common stock issuance costs | (1,668 | ) | | (64,554 | ) | | (5,706 | ) |
| Net cash provided by financing activities | 463,395 |
| | 1,291,050 |
| | 371,404 |
|
| Increase (decrease) in cash and cash equivalents | (581,968 | ) | | 491,630 |
| | 18,081 |
|
| Cash and cash equivalents at beginning of period | 588,736 |
| | 97,106 |
| | 79,025 |
|
| Cash and cash equivalents at end of the period | $ | 6,768 |
| | $ | 588,736 |
| | $ | 97,106 |
|
| Supplemental cash flow information: | | | | | |
| Property and equipment included in accounts payable and accrued liabilities | $ | 151,571 |
| | $ | 105,450 |
| | $ | 72,236 |
|
| Acquisition transaction expenses paid through oil and gas properties | $ | — |
| | $ | — |
| | $ | 6,000 |
|
| Cash paid for interest | $ | 54,492 |
| | $ | 31,280 |
| | $ | 50,380 |
|
| Cash paid for Second Lien Notes prepayment penalty | $ | — |
| | $ | 4,300 |
| | $ | — |
|
| Write-off of deposit on acquisition | $ | — |
| | $ | 10,000 |
| | $ | — |
|
| Accretion of beneficial conversion feature | $ | 5,394 |
| | $ | 1,041 |
| | $ | — |
|
| Noncash settlement of promissory notes issued to officers | $ | — |
| | $ | 5,562 |
| | $ | — |
|
| Increase in dividends payable | $ | 484 |
| | $ | — |
| | $ | — |
|
| Non-cash contribution to unconsolidated subsidiary | $ | 8,738 |
| | $ | — |
| | $ | — |
|
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Business and Organization
Extraction Oil & Gas, Inc. (the “Company” or “Extraction”) is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGLnatural gas liquids (“NGLs”) reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. The
As described in the section below titled Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, during the second quarter of 2020, the Company filed for bankruptcy and, its subsidiaries are focusedas a result, was delisted from the NASDAQ Global Select Market on June 25, 2020 and began trading on the acquisition, development and production of oil, natural gas and NGL reservesPink Open Market under the symbol “XOGAQ.”
As described in the Rocky Mountain region,section below titled Emergence from Chapter 11 Bankruptcy, on January 20, 2021 the Company emerged from bankruptcy as wella reorganized entity and, as the design and support of midstream assets to gather and process crude oil and gas production focused in the DJ Basin of Colorado. Extraction is a public company listed for tradingresult, was relisted on the NASDAQ Global Select Market on January 21, 2021 and began trading under the symbol "XOG".“XOG.”
TheTo facilitate our financial statement presentations, the Company refers to the post-emergence reorganized company in these consolidated financial statements and footnotes as the Successor Company for periods subsequent to January 20, 2021 and to the pre-emergence company as the Predecessor Company for periods on or prior to January 20, 2021.
Voluntary Reorganization under Chapter 11 of the Bankruptcy Code
As previously disclosed, on June 14, 2020 (the “Petition Date”), Extraction and its wholly owned subsidiaries (collectively, the “Debtors”), filed voluntary petitions for relief under chapter 11 (“Chapter 11”) of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the period January 1, 2016 through October 12, 2016 and forDistrict of Delaware (the “Bankruptcy Court”). The Debtors’ Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered under the year ended December 31, 2015 are based on the financial statements of the Company's accounting predecessor,caption In re Extraction Oil & Gas Holdings, LLC ("Holdings"Gas., et al. Case No. 20-11548 (CSS).
While in Chapter 11, the Debtors continued to operate their businesses and manage their properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Predecessor Credit Agreement (as defined in Note 8—Long-Term Debt) and the indentures governing the Company’s Senior Notes (as defined in Note 2—Basis of Presentation and Significant Accounting Policies), resulting in the automatic and immediate acceleration of all of the Company’s debt outstanding under the Predecessor Credit Agreement and Senior Notes. Accordingly, the Company has classified its outstanding Senior Notes debt as liabilities subject to compromise on its consolidated balance sheet as of December 31, 2020. The Prior Credit Facility (as defined in Note 8—Long-Term Debt) was not classified as liabilities subject to compromise because it was fully secured and unimpaired before being paid off as part of the Company’s emergence from bankruptcy described below. Please refer to Note 5—Liabilities Subject to Compromise for more information. Pursuant to the Bankruptcy Code and as described in Note 8—Long-TermDebt, the filing of the Chapter 11 Cases automatically stayed most actions against the Debtors, including most actions to collect indebtedness incurred prior to the corporate reorganization (the "Corporate Reorganization"), pursuantPetition Date or to which, in connection withexercise control over the initial public offeringDebtors’ property.
Plan, Disclosure Statement, and Backstop Commitment Agreement
On July 30, 2020, the Debtors filed a proposed Plan of Reorganization (as amended, modified, or supplemented from time to time, the “Plan”) and related Disclosure Statement (as amended or modified, the “Disclosure Statement”) describing the Plan and the solicitation of votes to approve the same from certain of the Company (the "Offering" or "IPO"), (i)Debtors’ creditors with respect to the Chapter 11 Cases. Subsequently on October 22, 2020 and November 5, 2020, the Debtors filed first and second amendments, respectively, to the Disclosure Statement. The hearing to consider approval of the Disclosure Statement was held on November 6, 2020. On November 6, 2020, the Bankruptcy Court approved the adequacy of the Disclosure Statement and the Debtors commenced a solicitation process to receive votes on the Plan. Pursuant to the terms of the Plan and as described in the Disclosure Statement, the Debtors also commenced a rights offering (the “Equity Rights Offering”), which was backstopped by certain holders of the Senior Notes. On November 6, 2020, the Bankruptcy Court approved the Backstop Commitment Agreement (the “Backstop Commitment Agreement”), which provided a commitment of $200 million. The hearing on the confirmation of the Plan was held on December 23, 2020, in which the Plan was approved.
Emergence from Chapter 11 2016, a former subsidiaryBankruptcy
On December 23, 2020, the Company filed the Sixth Amended Joint Plan of Reorganization of Extraction Oil & Gas, Holdings, LLC, Extraction Oil & Gas, LLC, convertedInc. pursuant to Chapter 11 of the Bankruptcy Code. Also on December 23, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Plan. The Plan is attached to the Confirmation Order as Exhibit A. The sixth-amended Plan and the Confirmation Order were previously filed as Exhibits 2.1 and 99.1 to the Company’s Current Report on Form 8-K filed with the U.S. Securities and Exchange Commission on December 30, 2020. On January 20, 2021 (the “Emergence Date”) the Plan became effective in accordance with its terms and the Company emerged from the Chapter 11 Cases. On the Emergence Date and pursuant to the Plan:
•The Company amended and restated its certificate of incorporation and bylaws;
•The Company constituted a new board of directors;
•The Company appointed a new Chief Executive Officer, President and Chief Operating Officer, and Chief Financial Officer;
•The Company issued new common stock in the Successor Company (the “New Common Stock”) and New Warrants (as defined in Note 12—Equity):
◦2,832,833 shares of New Common Stock pro rata to holders of the 2024 Notes;
◦4,854,017 shares of New Common Stock pro rata to holders of the 2026 Notes;
◦179,472 shares of New Common Stock, 1,454,832 Tranche A Warrants to purchase 1,454,832 shares of New Common Stock and 727,420 Tranche B Warrants to purchase 727,420 shares of New Common Stock pro rata to holders of the Predecessor Company’s Series A Preferred Stock (the “Predecessor Preferred Stock”) outstanding prior to the Emergence Date;
◦179,496 shares of New Common Stock, 1,454,854 Tranche A Warrants to purchase 1,454,854 shares of New Common Stock and 727,443 Tranche B Warrants to purchase 727,443 shares of New Common Stock pro rata to holders of the Predecessor Company’s existing common stock (the “Predecessor Common Stock”) outstanding prior to the Emergence Date;
◦1,169,322 shares of New Common Stock to commitment parties under the Backstop Commitment Agreement in respect of the commitment premium due thereunder;
◦844,760 shares of New Common Stock to the commitment parties under the Backstop Commitment Agreement in connection with their backstop obligation thereunder to purchase unsubscribed shares of New Common Stock;
◦11,478,670 shares of New Common Stock were issued to participants in the Equity Rights Offering extended by the Company to the applicable classes under the Plan (including to the commitment parties party to the Backstop Commitment Agreement); and
◦13,392 shares of New Common Stock were issued to participants in rights offering extended by the Company to certain holders of general unsecured claims.
•The Company entered into the RBL Credit Facility (as defined in Note 8—Long-Term Debt—RBL Credit Facility);
•The Company terminated the Prior Credit Facility (as defined in Note 8—Long-Term Debt—Prior Credit Facility), and the holders of claims under the Prior Credit Facility each received its ratable portion of the RBL Credit Facility for its allowed claims. All liens and security interests granted to secure such obligations were automatically terminated and are of no further force and effect;
•The Company terminated the DIP Credit Facility (as defined in Note 8—Long-Term Debt—DIP Credit Facility), and the holders of claims under the DIP Credit Facility received payment in full, in cash, for allowed claims. All liens and security interests granted to secure such obligations were automatically terminated and are of no further force and effect;
•The holders of certain trade claims, administrative claims, other secured claims and other priority claims that were allowed by the Bankruptcy Court received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date.
Tax Attributes and Net Operating Loss (“NOL”) Carryforwards
As of December 31, 2020, the Company had substantial tax NOL carryforwards and other tax attributes. Under the U.S. Internal Revenue Code of 1986, as amended (the “Code”), our ability to use these NOLs and other tax attributes may be limited if the Company experiences an “ownership change,” as determined under Section 382 of the Code. Accordingly, on July 13, 2020, the Company obtained a final order from the Bankruptcy Court that was intended to prevent an ownership change during the pendency of the Chapter 11 Cases and therefore protect the Company’s ability to use its tax attributes by imposing certain notice procedures and transfer restrictions on the trading of the Company’s Predecessor Common Stock and Predecessor Preferred Stock.
In general, the order applied to any person or entity that, directly or indirectly, beneficially owned (or would beneficially own as a result of a proposed transfer) at least 4.5% of the Company’s common stock or preferred stock. Such persons were required to notify the Company and (ii) on October 17, 2016, Holdings merged withthe Bankruptcy Court before effecting a transaction involving the Company’s Predecessor Common Stock and intoPredecessor Preferred Stock, and the Company had the right to seek an injunction to prevent the transaction if it might have adversely affected the Company’s ability to use its tax attributes. The order also required any person or entity that, directly or indirectly, beneficially owned at least 50% of the Company’s Predecessor Common Stock and Predecessor Preferred Stock to notify the Company and the Bankruptcy Court prior to claiming any deduction for worthlessness of the Company’s Predecessor Common Stock and Predecessor Preferred Stock for a tax year ending before the Company’s emergence from chapter 11 protection and the Company had the right to seek an injunction to prevent the transaction if it might have adversely affected the Company’s ability to use its tax attributes.
Any purchase, sale or other transfer of, or any claim of a deduction for worthlessness with respect to, the Company’s Predecessor Common Stock and Predecessor Preferred Stock in violation of the restrictions of the order would have been null and void ab initio as an act in violation of a Bankruptcy Court order and would therefore have conferred no rights on a proposed transferee or such holder, as applicable.
However, the Company expects that it will be required to substantially reduce or eliminate certain of its tax attributes, including NOL carryforwards, as a result of cancellation of indebtedness income realized in connection with the ExtractionChapter 11 Cases. Additionally, the consummation of the Plan on the Emergence Date resulted in an “ownership change” under Section 382 of the Code. Absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its pre-ownership change NOLs that may be utilized to offset future taxable income generally will be subject to an annual limitation equal to the value of its stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate, plus an additional amount calculated based on certain “built in gains” in its assets that may be deemed to be realized within a 5-year period following any ownership change. This limitation, in the case of the ownership change that occurred as a result of the consummation of the Plan, will be subject to additional rules under Sections 382(l)(5) or (l)(6) of the Code, depending upon whether we are eligible for the application of Section 382(l)(5) of the Code and, if so eligible, whether we affirmatively elect not to apply Section 382(l)(5) of the Code. As a result of such limitation, the Company’s ability to utilize any NOLs or other tax attributes that are not eliminated as a result of cancellation of indebtedness income arising from the consummation of the Plan may be materially limited in the future.
Fresh-Start Reporting
Upon the Emergence Date, we began our assessment of our qualifications for fresh-start reporting. In order to qualify for fresh-start reporting, under Accounting Standards Codification (“ASC”) Topic 852 — Reorganizations, (i) the holders of existing voting shares of the Company prior to its emergence must receive less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the plan of reorganization must be less than the post-petition liabilities and allowed claims. If we qualify for fresh-start reporting, a new reporting entity will be considered to have been created, and, as a result, the Company will allocate the reorganization value of the Company to its individual assets, including property, plant and equipment, based on their estimated fair values. The process of estimating the fair value of the Company’s assets, liabilities and equity upon emergence is currently ongoing and, therefore, neither the amounts nor the qualification for this accounting treatment have been finalized. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $875 million to $1.275 billion. On the Emergence Date, pursuant to the terms of the Plan, the Successor Company entered into a $1.0 billion reserve-based credit agreement with an initial borrowing base of $500.0 million. Please see Note 8—Long-Term Debt for discussion of the Successor Company’s debt.
Deconsolidation of Elevation Midstream, LLC
Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company, is focused on the construction and operation of gathering systems and facilities to serve the development of acreage in the Company’s Hawkeye and Southwest Wattenberg areas. Midstream assets of Elevation are represented as the survivinggathering systems and facilities line item within the consolidated balance sheets for any periods ended on or prior to December 31, 2019.
During the first quarter of 2020, Elevation’s then non-controlling interest owner, which owned 100% of Elevation’s preferred stock, per contractual agreement, expanded Elevation’s then five member board of managers by four seats and filled them with managers of their choosing (the “Board Expansion”). Because Extraction had the right to appoint only three of the managers of Elevation before and after Board Expansion, Extraction determined the Company had lost voting control of Elevation, and on March 16, 2020 deconsolidated Elevation and began accounting for the entity as an equity method investment. Though Extraction determined control of Elevation was lost under the voting interest model of consolidation, the Company also determined significant influence was not lost due to (1) Extraction owning 100% of the common stock, (2) Extraction appointing three of the nine managers of Elevation and (3) Extraction’s continuing involvement in the day-to-day operation of Elevation through a management services agreement. Because Extraction also determined the Company is not the primary beneficiary, Elevation Midstream, LLC is not a variable interest entity.
Extraction elected the fair value option to remeasure the Elevation equity method investment and determined it had no fair value. The Company recorded a $73.1 million loss on deconsolidation of the investment in the consolidated statements of operations for the three months ended March 31, 2020. Also during the three months ended March 31, 2020, Elevation determined certain gathering systems and facilities were impaired by $50.3 million as a result of the abandonment of certain projects. In accordance with ASC Topic 323-10-35-20: Investments—equity method and joint ventures, Extraction discontinued applying the equity method for Elevation as the impairment charge would have reduced the investment below zero.
On May 1, 2020, Elevation’s board of managers issued 1,530,000,000 common units at a price of $0.01 per unit to certain of Elevation’s members other than Extraction (the “Capital Raise”). The Capital Raise caused Extraction’s ownership of Elevation to be diluted to less than 0.01%. As a result of the Capital Raise, beginning in May 2020 Extraction began accounting for Elevation under the cost method of accounting. In December 2020, the Company reached a settlement with Elevation (as discussed in Note 16—Commitments and Contingencies — Elevation Gathering Agreements) which was approved by the Bankruptcy Court. As part of the settlement, the Company relinquished its remaining ownership in Elevation and has no more interest in Elevation as of December 31, 2020.
Note 2—Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The consolidated financial statements include the accounts of the Company, including its wholly‑owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. The financial statements included herein were prepared from the records of the Company in accordance with accounting principles generally accepted accounting principles in the United States of America (“GAAP”). In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the consolidated financial information, have been included.
Use of Estimates in the Preparation of Financial Statements
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties and goodwill; (3) depreciation, depletion, amortization and accretion; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of unit and stock-based payments, and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates its estimates on an on‑goingon-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances.
Significant Accounting Policies
Beginning after the Petition Date, the Company has applied ASC Topic 852 — Reorganizations in preparing the consolidated financial statements. ASC 852 requires the financial statements, for periods subsequent to the Chapter 11 Cases’ filing date, to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses incurred during the bankruptcy proceedings, including unamortized debt issuance costs associated with debt classified as liabilities subject to compromise, are recorded as reorganization items. In addition, pre-petition obligations that may be impacted by the chapter 11 process have been classified on the consolidated balance sheets as liabilities subject to compromise. These liabilities are reported at the amounts the Company anticipates will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.
GAAP requires certain additional reporting for financial statements prepared between the Petition Date and the date that the Company emerges from bankruptcy, including:
•Reclassification of pre-petition liabilities that are unsecured, under-secured or where it cannot be determined that the liabilities are fully secured to a separate line item in the consolidated balance sheets called liabilities subject to compromise; and
•Segregation of reorganization items as a separate line in the consolidated statements of operations outside of income from continuing operations.
Debtor-In-Possession
As of December 31, 2020, the Debtors operated as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court approved motions filed by the Debtors that were designed primarily to mitigate the impact of the Chapter 11 Cases on the Company’s operations, customers and employees. As a result, the Company conducted normal business activities during 2020 and paid all associated obligations for the period following its bankruptcy filing in the ordinary course of business and was authorized to pay and have paid certain pre-petition obligations, including, among other things, for employee wages and benefits and certain goods and services provided. During the Chapter 11 Cases, transactions outside the ordinary course of business required prior approval of the Bankruptcy Court.
Automatic Stay
Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 Cases automatically stayed most judicial or administrative actions against the Debtors and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code.
Executory Contracts
Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors from performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Please refer to Note 5—Liabilities Subject to Compromise and Note 16—Commitments and Contingencies — Delivery Commitments for more information.
Potential Claims
The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of each of the Debtors, subject to the assumptions filed in connection therewith. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the bar date of August 14, 2020. As of March 9, 2021, the Debtors’ have received approximately 2,600 proofs of claim, primarily representing general unsecured claims, for an amount of approximately $5.8 billion. The Bankruptcy Court does not allow for claims that have been acknowledged as duplicates. Approximately 1,100 claims totaling approximately $4.2 billion have been withdrawn, disallowed or are pending approval to be
disallowed. These claims will be reconciled to amounts recorded in liabilities subject to compromise in the consolidated balance sheet. Differences in amounts recorded and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court, where appropriate. The Company may ask the Bankruptcy Court to disallow claims that the Company believes are duplicative, have been later amended or superseded, are without merit, are overstated or should be disallowed for other reasons. In light of the substantial number of claims filed, the claims resolution process may take considerable time to complete and is continuing even after the Debtors emerged from bankruptcy.
Financial Statement Classification of Liabilities Subject to Compromise
The accompanying consolidated balance sheets as of December 31, 2020 includes amounts classified as liabilities subject to compromise, which represent liabilities the Company anticipates will be allowed as claims in the Chapter 11 Cases. These amounts represent the Debtors’ current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the chapter 11 process and adjust amounts as necessary. Such adjustments may be material. Please refer to Note 5—Liabilities Subject to Compromise for more information.
Reorganization Items, Net
The Debtors have incurred and will continue to incur significant costs associated with the reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. The amount of these costs, which since the Petition Date, are being expensed as incurred, are expected to significantly affect the Company’s results of operations. In accordance with applicable guidance, costs associated with the bankruptcy proceedings have been recorded as reorganization items within the Company’s accompanying consolidated statements of operations for the year ended December 31, 2020. Please refer to Note 6—Reorganization Items, Net for more information.
Other Operating Expenses
Other operating expenses were $79.6 million for the year ended December 31, 2020, respectively. There were no other operating expenses for the years ended December 31, 2019 and 2018. The total amount in the current year is made up of the following:
•$46.8 million loss contingency from an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. Please see Note 16—Commitments and Contingencies for further details.
•$4.2 million of accrued interest related to the aforementioned alleged breach in contract.
•$13.2 million early termination penalty for the revenue contract terminated in June 2020. Please see the section Contract Balance below for further details.
•$7.6 million of expenses related to workforce reductions in February and May 2020.
•$4.1 million of interest expense on unpaid production taxes recorded in the last half of 2020.
•$2.4 million of expenses related to drilling rig standby charges during the second quarter of 2020.
•$1.3 million of expenses related to legal accruals and other.
Cash and Cash Equivalents
Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased.
Cash Held in Escrow
Cash held in escrow includes deposits for the purchase of certain oil and gas properties as required under the related purchase and sale agreements.
Accounts Receivable
The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. The Company generally has the ability to withhold future revenue disbursements to recover non‑paymentnon-payment of joint interest billings. On an on‑goingon-going basis, management reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables
under the specific identification method. based on expected losses. The Company did not0t record any allowance for uncollectible receivables as of or for the years ended December 31, 20172020 and 2016.2019.
Credit Risk and Other Concentrations
The Company’s cash and cash equivalents are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the federally insured limits.
The Company sells oil, natural gas and NGL to various types of customers, including oil marketers, pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. For the three-yearsyears ended December 31, 2017,2020, 2019 and 2018, respectively, the Company had the following customers that exceeded 10% of total oil, natural gas and NGL revenues. The Company does not believe the loss of any single purchaser would materially impact its operating results because crude oil, natural gas and NGL are fungible products with well‑establishedwell-established markets and numerous purchasers.
| | | | For the Year Ended | | | | | | | | | | | | | | | |
| | December 31, | | For the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2020 | | 2019 | | 2018 |
| Customer A | 65 | % | | 25 | % | | — |
| Customer A | 28 | % | | 77 | % | | 76 | % |
| Customer B | 19 | % | | 19 | % | | 17 | % | Customer B | 16 | % | | <10% | | <10% |
| Customer C | 11 | % | | — | % | | — | % | Customer C | 12 | % | | <10% | | <10% |
| Customer D | — | % | | 23 | % | | 30 | % | Customer D | <10% | | <10% | | 11 | % |
| Customer E | — | % | | 16 | % | | 17 | % | |
| Customer F | — | % | | — | % | | 24 | % | |
At December 31, 2017,2020, the Company had commodity derivative contracts with seven2 counterparties, allboth of whomwhich are lenders under our credit agreement.the Predecessor Credit Agreement. The Company does not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are credit worthy financial institutions deemed by management as competent and competitive market‑makers.market-makers. Additionally, the Company uses master netting agreements to minimize credit‑riskcredit-risk exposure. The credit worthiness of the Company’s counterparties is subject to periodic review. Three of the seven counterparties to the derivative instruments are highly rated entities with corporate ratings at A3 classifications or above by Moody’s. Three additional counterparties have a corporate rating of Baa1 by Moody’s. One counterparty is a private entity and has a corporate rating of NAIC-2 by the National Association of Insurance Commissioners. For the years ended December 31, 2017, 20162020, 2019 and 2015,2018, the Company did not incur any losses with respect to counterparty contracts. None of the Company’s existing derivative instrument contracts contains credit‑riskcredit-risk related contingent features.
Inventory, and Prepaid Expenses and Other
The Company records well equipment inventory at the lower of cost or net realizable value. Prepaid expenses are recorded at cost. Inventory, and prepaid expenses and other are comprised of the following (in thousands):
| | | | | | | | | | | |
| | As of December 31, |
| | 2020 | | 2019 |
| Well equipment inventory | $ | 11,989 | | | $ | 20,960 | |
| Prepaid expenses | 8,456 | | | 5,793 | |
| Line fill | 14,115 | | | 0 | |
| Deposits | 1,822 | | | 0 | |
| Contractual asset under ASC 606 | 0 | | | 9,949 | |
| | $ | 36,382 | | | $ | 36,702 | |
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| Well equipment inventory | $ | 9,971 |
| | $ | 5,135 |
|
| Prepaid expenses | 3,046 |
| | 2,587 |
|
| | $ | 13,017 |
| | $ | 7,722 |
|
Additionally, theThe Company recognized approximately $0.7 million and $0.4 million of impairment expense on well equipment inventory in the amount of $2.1 million for the yearsyear ended December 31, 2017 and 2016, respectively. There2020. NaN such impairment expense was no impairment on inventory recognized for the year ended December 31, 2015.2019. The Company recognized impairment expense on well equipment inventory in the amount $0.1 million for the year ended December 31, 2018.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units‑of‑productionunits-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. For the years ended
December 31, 2017, 20162020, 2019 and 2015,2018, the Company excluded $127.4$129.1 million, $98.7$149.7 million and $59.4$144.3 million, respectively, of capitalized costs from depletion related to wells in progress, respectively.progress. For the years ended December 31, 2017, 20162020, 2019 and 2015,2018, the
Company recorded depletion expense on capitalized oil and gas properties of $306.7$321.0 million, $197.4$513.7 million and $140.2$426.8 million, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed at each period end. Due to the capital‑intensivecapital-intensive nature and the geological characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. As of December 31, 2017,2020 and 2019, the Company had approximately $15.7 million of0 suspended well costs, all capitalized less than one year. The suspended well costs are included in wells in progress at December 31, 2017. These exploratory well costs are pending further engineering evaluation and analysis to determine if economic quantities of oil and gas reserves have been discovered. the Company expects its analysis to be complete in the second half of 2018. As of December 31, 2016, the Company did not have any suspended well costs as the analysis on economic and operating viability of the 2015 project was complete. As of December 31, 2015, the Company had approximately $17.3 million in suspended well costs recorded, all capitalized less than one year, related to four exploratory wells in the northern field. The suspended well costs were included in wells in progress at December 31, 2015. These exploratory well costs were pending further engineering evaluation and analysis to determine if economic quantities of oil and gas reserves had been discovered. At June 30, 2016, the Company completed its evaluation and moved $21.8 million of these suspended well costs to proved oil and gas properties based on the determination of proved reserves.costs.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. The Company expensed $1.4$0.2 million, $0.2 million and $0.4 million of costs associated with exploratory geological and geophysical costs for the year ended December 31, 2017. There were no exploratory geological and geophysical costs incurred for the years ended December 31, 20162020, 2019 and 2015.2018, respectively.
The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development activities. For the years ended December 31, 2017, 20162020, 2019 and 2015,2018, the Company capitalized interest of approximately $11.1$5.3 million, $5.2$7.2 million and $5.3$8.2 million, respectively.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulateaccumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Impairment of Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. For all of its fields, the Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated
undiscounted future cash flows, the Company will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets and goodwill in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization. For the year ended December 31, 2017,2020, the Company recognized no$3.6 million related to impairment expense onof the proved oil and gas properties in our northern field and $194.3 million related to oil and gas properties in one of our Core DJ Basin fields, as the fields’ fair values did not exceed the carrying amounts associated with our oil and gas properties. For the year ended December 31, 2019, the Company recognized $14.5 million related to impairment of the proved oil and gas properties in its northern field and $1.3 billion related to assets in its Core DJ Basin field as the field’s fair values did not exceed the carrying amounts associated with its proved oil and gas properties. For the yearsyear ended December 31, 2016 and 2015,2018, the Company recognized $22.5$16.2 million and $9.5 million, respectively, inrelated to impairment expense onof the proved oil and gas properties in its northern field as the Company's northern field. The future undiscounted cash flowsfair value did not exceed itsthe carrying amount associated with its proved oil and gas properties in its northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties were impaired at June 30, 2016 and 2015. In December 2015, the Company sold proved oil and gas properties for proceeds of $4.7 million. As a result, these assets were fair valued on the date of the transaction in accordance with ASC 360, Property, Plant and Equipment. The net book value of these assets exceeded the fair value by $2.7 million, which the Company recognized as impairment expense. The Company recognized $12.2 million in impairment expense that was attributable to proved oil and gas properties for the year ended December 31, 2015.field.
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are
drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit‑of‑productionunit-of-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration and abandonment expenses in the consolidated statements of operations. As a result of the abandonment and impairment of unproved properties, the Company recognized $15.8$253.1 million, $22.3$73.7 million and $16.4$25.7 million in impairmentof abandonment expense for the years ended December 31, 2017, 20162020, 2019 and 2015,2018, respectively.
Other Property and Equipment
Other property and equipment consists of (i) midstream assets such as rights of way, pipelines, equipment and engineering costs, (ii) compressors, used in Extraction’s oil and gas operations, (iii) land, compressor stations, central tank batteries and disposal well facilities used in Extraction’s oil and gas operations, (ii) land, (iii) rights of ways, pipeline and engineering costs, (iv) office leasehold improvements, (v) the field office, and (vi) other property and equipment including office furniture and fixtures leasehold improvements and computer hardware and software. Impairment expense for other property and equipment is reported in impairment of long lived assets and goodwill in the consolidated statements of operations. No impairment expense was incurred related to midstream facilities for the year ended December 31, 2020. The Company recognized $0.9 million, $0.5$0.1 million and $3.6$0.4 million in impairment expense related to midstream facilities for the yearsyear ended December 31, 2017, 20162019 and 2015,December 31, 2018, respectively, which increased accumulated depreciation recognized in other property and equipment, net of accumulated depreciation. The Company recognized theThese impairment expense for the year ended December 31, 2017expenses were primarily as the result of right-of-way options that were no longer in the Company'sCompany’s plans for developing midstream infrastucture.infrastructure. The Company recognized the impairment expense for the years ended December 31, 2016 and 2015, as the result of contraction in the local oil and gas industry’s near term growth profile, therefore decreasing the need and support for a specifically proposed gas processing facility. Gaingain or loss on the sale of other property and equipment is reported in other operating expensesgain (loss) on sale of property and equipment and assets of unconsolidated subsidiary in the consolidated statementstatements of operations. The Company recognized $0.5$4.5 million, of loss on the sale of other property$3.1 million and equipment related to the disposal of an oil pipeline that was not yet placed into service in the first quarter of 2017. Approximately $7.3$0.8 million of midstream assets, net of impairment expense have not been placed into servicerelated to land, midstream facilities and therefore are not currently being depreciated. Other property andrental equipment, is recorded at cost and depreciated usingrespectively, for the straight‑line method.year ended December 31, 2020. The Company also wrote off $2.6 million of leasehold improvements during the year ended December 31, 2020 due to a consolidation of leased office space.
The estimated useful lives of those assets depreciated under the straight-line basismethod are as follows:
|
| | | | |
| Rental equipment | 1-10 years |
| Office leasehold improvements | 3-10 years |
OtherField office | 30 years |
| Other | 3-5 years |
Other property and equipment is comprised of the following (in thousands):
| | | | | | | | | | | |
| As of December 31, |
| 2020 | | 2019 |
| Rental equipment | $ | 3,251 | | | $ | 4,043 | |
| Land | 39,788 | | | 42,273 | |
| Right-of-ways and pipeline | 8,008 | | | 8,008 | |
| Office leasehold improvements | 4,390 | | | 7,009 | |
| Field office | 18,447 | | | 18,317 | |
| Other | 8,604 | | | 8,884 | |
| Less: accumulated depreciation and impairment charges | (25,787) | | | (15,992) | |
| $ | 56,701 | | | $ | 72,542 | |
Gathering Systems and Facilities
Gathering systems and facilities consisted of midstream assets such as land, rights of way, pipelines, equipment and construction and engineering costs associated with the construction of pipeline infrastructure to serve the development of the Company’s acreage in its Hawkeye and Southwest Wattenberg areas. As discussed in Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC, during the first quarter of 2020 the Company deconsolidated Elevation Midstream, LLC.
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| Rental equipment | $ | 3,805 |
| | $ | 2,910 |
|
| Land | 22,991 |
| | 12,978 |
|
| Midstream facilities | 12,336 |
| | 16,530 |
|
| Office leasehold improvements | 4,405 |
| | 4,360 |
|
| Other | 5,578 |
| | 4,786 |
|
| Less: accumulated depreciation | (11,797 | ) | | (8,843 | ) |
| | $ | 37,318 |
| | $ | 32,721 |
|
| | | | | | | | | | | |
| | As of December 31, |
| | 2020 | | 2019 |
| Gathering systems and facilities | $ | 0 | | | $ | 314,906 | |
| Land associated with gathering systems and facilities | 0 | | | 2,188 | |
| Less: accumulated depreciation | 0 | | | (1,317) | |
| | $ | 0 | | | $ | 315,777 | |
Gathering systems and facilities balances are evaluated for potential impairment when events or changes in circumstances indicate that their carrying amounts may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the carrying amount of the asset is not expected to be recoverable from future undiscounted cash flows, an impairment may be recognized. Any impairment is measured as the excess of the carrying amount of the asset over its estimated fair value.
In assessing gathering systems and facilities assets for impairment, management evaluates changes in business and economic conditions and their implications for recoverability of the assets’ carrying amounts. The measure of impairments to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. Gathering systems and facilities are recorded at historical cost and depreciated using the straight-line method over 30 years.
In March 2020, Elevation determined certain gathering systems and facilities were impaired by $50.3 million as a result of the abandonment of certain projects. In accordance with ASC Topic 323-10-35-20: Investments—equity method and joint ventures, Extraction discontinued applying the equity method investment for Elevation as the impairment charge would have reduced the investment below zero. For further information on the deconsolidation of Elevation Midstream, LLC, please see Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC. No impairment expense was recognized for the years ended December 31, 2019 and 2018 associated with gathering systems and facilities.
Equity Method Investments
Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method.method of accounting. The Company recorded $8.3$44.6 million of such investments included in other non-current assets on the consolidated balance sheets as of December 31, 2017.2019 but had no equity method investment as of December 31, 2020 due to the deconsolidation of Elevation Midstream discussed in Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC. Please refer to Note 16 — Commitments and Contingencies — Delivery Commitments for more information. The Company recognized $0.4$0.5 million, $2.3 million and $2.9 million of net income from such investments, including the accretion of any basis difference between the carrying amount of the investment and the amount of underlying equity in net assets, included in other income on the consolidated statements of operations and equity in earnings of unconsolidated subsidiary, in which we havehad a minority ownership interest on the consolidated statements of cash flows for the years ended December 31, 2020, 2019 and 2018, respectively.
For the year ended December 31, 2017. The Company held no such investments during2019, a gain on sale of unconsolidated subsidiary of $1.0 million was recorded relating to Elevation’s August 2018 Divestiture. In August 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for the yearsyear ended December 31, 2016 and 2015.2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset.
Deferred Lease Incentives
All incentives received from landlords for office leasehold improvements are recorded as deferred lease incentives and amortized over the term of the respective lease on a straight‑linestraight-line basis as a reduction of rental expense. The Company wrote off $2.6 million of leasehold improvements during the year ended December 31, 2020 due to a consolidation of leased office space.
Debt Issuance Costs
Debt issuance costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company’s credit facility, 2021Prior Credit Facility, DIP Credit Facility (as defined in Note 8 — Long Term Debt), 2024 Senior Notes and 20242026 Senior Notes (collectively, the "Senior Notes"“Senior Notes”). Debt issuance costs related to the credit facilityPrior Credit Facility are included in other non-current assets on the consolidated balance sheets and amortized to interest expense on the consolidated statement of operations on a straight‑linestraight-line basis over the respective borrowing term. Debt issuance costs related to the Senior Notes areprior to the Chapter 11 Cases were amortized to interest expense using the effective interest method over the term of the debt. However, as a result of the Chapter 11 Cases, the Company expensed $13.5 million of debt issuance costs pertaining to the Senior Notes to reorganization items, net on the consolidated statements of operations for the year ended December 31, 2020. Debt issuance costs of $1.7 million pertaining to the DIP Credit Facility were expensed to reorganization items, net during the year ended December 31, 2020.
Commodity Derivative Instruments
The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and commodity derivative liabilities. The Company has not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivativederivatives gain (loss) line on the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.
Any premiums paid on derivative contracts are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid. Premium payments are reflected in cash flows from operating activities in the
Company's Company’s consolidated statements of cash flows. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivatederivative contracts, and the cash received is reflected in cash flows from operating activities in the Company'sCompany’s consolidated statements of cash flows.
The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of these factors resultresults in an estimated exit‑priceexit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non‑biased,non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please refer to Note 69 — Commodity Derivative Instruments for additional discussion on commodity derivative instruments.
Goodwill and Other Intangible Assets
The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other.Other. Goodwill represents the excess of the purchase price over the estimated value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil and gas operations in its coreCore DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed ana quantitative assessment as of September 30, 2017,2018, which concluded the fair value of the reporting unit was greater than its carrying amount.
The Company identified triggering events as of December 31, 2018, due to the decrease in commodity pricing and the quoted market price of the Company's common shares compared to September 30, 2018. As such, the Company performed a qualitativequantitative assessment as of December 31, 20172018, utilizing an income approach based on estimates of the expected discounted future cash flows of the reporting unit's oil and 2016,gas properties, which concluded the fair value of the reporting unit was more-likely-than-notnot greater than its carrying amount. As a result, the Company recorded goodwill impairment of $54.2 million, the entirety of the balance, for the year ended December 31, 2018. As such, no test for goodwill impairment was necessary for the year ended December 31, 2020 and 2019.
Costs relating to the acquisition of internal-use software licenses are capitalized when incurred and amortized over the estimated useful life of the license, which is typically one year or less. to three years. The Company recorded $2.3$0.3 million, $2.2 million and $0.3$3.0 million of capitalized internal-use software costs for the years ended December 31, 20172020, 2019 and 20162018, respectively, on the consolidated balance sheets within the goodwill and other intangiblenon-current assets line item. Accumulated amortization for the years ended December 31, 20172020 and 20162019 was $1.1$6.8 million and $0.1$5.3 million, respectively. The Company recognized $1.0$1.6 million, $2.2 million and $0.1$2.1 million of amortization expense for the years ended December 31, 20172020, 2019 and 2016,2018, respectively. There was no capitalized internal-use software, accumulated amortization or amortization expense for the year ended December 31, 2015.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long‑termlong-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short‑termshort-term maturities. The carrying amountamounts of the Company’s credit facilityPrior Credit Facility and DIP Credit Facility approximates fair value as it bears interest at variable rates over the term of the loan.loans. The Company’s Senior Notes are recorded at cost and the fair value is disclosed in Note 811 — Fair Value Measurements. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.
Asset Retirement Obligation
The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long‑livedlong-lived asset are recorded at the time the Company makes the decision to complete the well or a well is acquired. For additional discussion on asset retirement obligations please refer to Note 710 — Asset Retirement Obligations.
Environmental Liabilities
The Company is subject to federal, state and local environmental laws and regulations. These laws regulate the release, disposal or discharge of materials into the environment or otherwise relating to environmental protection and may require the Company to remove or mitigate the environmental effects of the discharge, disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a non‑capitalnon-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or determinable. Management has determined that no significant environmental liabilities existed as of December 31, 2017.2020. Please refer to Note 16 — Commitments and Contingencies for additional discussion on environmental liabilities.
Revenue Recognition
RevenuesRevenue from the sale of oil, natural gas and NGL areNGLs is recognized whenin accordance with ASC 606 - Revenue from Contracts with Customers (“ASC 606”) five-step revenue recognition model to depict the product is delivered at a fixedtransfer of goods or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. Theservices to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. To account for producer imbalances, the Company recognizes revenues from the saleon all sales of oil, natural gas and NGL usingNGLs to third party customers regardless of their ownership percentage and adjusts the sales method of accounting, wherebyunderlifter or overlifter’s claim on the asset’s remaining reserves. In other words, revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no material imbalances atAs of December 31, 2017, 2016 or 2015.2020, 2019, and 2018, the Company had oil imbalances of 1.1, 12.7, and 22.0 MBbl, respectively, which the Company intends to settle with the counterparty in crude oil barrels. On January 1, 2018, the Company adopted ASC 606. See —Adoption of ASC 606 for more information regarding the adoption of this standard.
Unit and Stock‑BasedStock-Based Payments
The Company and its predecessor, Holdings, has granted restricted unit awards ("RUAs") to certain employees and nonemployee consultants ofunder the Company, restricted stock units ("RSUs"), stock option awards and performance stock awards ("PSAs")LTIP to certain directors, officers and employees, of the Company,including stock options, restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards which therefore required the Company to recognize the expense in its consolidated financial statements.
All unit and stock‑basedstock-based payments to directors, officers and employees are measured at fair value on the grant date and expensed over the relevant service period. Unit‑based payments to nonemployees are measured at fair value at each financial reporting date and expensed over the period of performance, such that aggregate expense recognized is equal to the fair value of the restricted units on the date performance is completed. The fair value of stock option awards is determined by using the Black-Scholes option pricing model. The fair value of the PSAsperformance stock awards was measured at the grant date with a stochastic process method using a Monte Carlo simulation. All unit and stock‑basedstock-based payment expense is recognized using the straight‑linestraight-line method and is included within general and administrative expenses in the consolidated statements of operations and unit and stock-based compensation in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 1114 — Unit and Stock‑BasedStock-Based Compensation for additional discussion on unit and stock‑basedstock-based payments.
Income Taxes
The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by deferral and state taxing authorities.
The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses.NOLs. In making this determination, the Company considers all the available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. The Company believes it is more likely than not that certain net operating losses canthe benefit from NOL carryforwards will not be carried forward and utilized.fully realized. In recognition of this risk, the Company has provided a valuation allowance on the deferred tax assets.
The Company recognizes 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 consolidated 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. The Company does not currently have uncertain tax positions.
On December 22, 2017, United States legislation referred to as the "Tax Cuts and Jobs Act" (the "TCJA") was signed into law. Many of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes changes to the Internal Revenue Code of 1986 (as amended, the "Code"). The most significant change included in the TCJA is a reduction in the corporate federal income tax rate from 35% to 21%. As a result of the enactment date of December
22, 2017, the Company is required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. This re-measurement of deferred tax assets and liabilities will require the Company to analyze and record a one-time adjustment to reduce the overall deferred tax liability in the consolidated balance sheets and affect a corresponding income tax benefit in the consolidated statements of operations for the year ended December 31, 2017. The Company believes the accounting is complete regarding the revaluation of the deferred tax balances. This resulted in the recording of an income tax benefit of $23.4 million, as well as a corresponding reduction in the deferred tax liability. The Company currently evaluating other potential impacts of the TCJA.
Extraction Oil & Gas Holdings, LLC, the Company’s accounting predecessor, was a limited liability company that was not subject to U.S. federal income tax.
Earnings Per Share
Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings available to common shareholders of the Company. The Company uses the “if-converted” method to determine the potential dilutive effects of its Series A Preferred Stock, and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock units and stock option awards and performance stock awards. The Company’s EPS calculation for the year ended December 31, 2016 includes only the net income (loss) for the period subsequent to IPO and Corporate Reorganization which occurred on October 12, 2016 and has omitted EPS prior to this date. In addition, the basic weighted average shares outstanding calculation for the year ended December 31, 2016 is based on the actual days in which the shares were outstanding for the period from October 12, 2016, to December 31, 2016.
Segment Reporting
TheBeginning in the fourth quarter of 2018, the Company operates in only one industry segment, which ishad two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the “exploration and relatedproduction segment”) and (ii) the construction of and support of midstream activities. Theassets to gather and process crude oil and gas production (the “gathering and facilities segment”). Elevation Midstream, LLC comprised the gathering and facilities segment. During the fourth quarter of 2019, the Company’s wholly‑owned midstream subsidiaries are currentlygathering and facilities segment commenced operations. Through March 16, 2020, the results of Elevation were included in the design phaseconsolidated financial statements of Extraction. Effective March 17, 2020, the results of Elevation Midstream, LLC are no longer consolidated in Extraction’s results; however, the Company’s prior annual segment disclosures included the gathering and no revenue generating activities have commenced. facilities segment because it was consolidated through March 16, 2020. Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC for further information related to the deconsolidation of Elevation Midstream, LLC. After March 16, 2020, the Company had a single reportable segment.
All of the Company’s operations are conducted in one1 geographic area of the United States. All revenues are derived from customers located in the United States.
Recent Accounting Pronouncements
The accounting standard‑settingstandard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on its consolidated financial statements and related disclosures.
In May 2017,March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-09,2020-04, Reference Rate Reform — Facilitation of the Effects of Reference Rate Reform on Financial Reporting (Topic 848). This ASU provides an optional expedient and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. In response to the concerns about structural risks of interbank offered rates (IBORs) and, particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR), regulators in several jurisdictions around the world have undertaken reference rate reform initiatives to identify alternative reference rates that are more observable or transaction-based and less susceptible to manipulation. The ASU provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates that are expected to be discontinued. In January 2021, the FASB issued ASU No. 2021-01, which provides clarificationclarifies that certain provisions in Topic 848, if elected by an entity, apply to derivative instruments that use an interest rate for margining, discounting, or contract price alignment that is modified as a result of reference rate reform. The amendments in these ASUs are effective for all entities as of March 12, 2020 through December 31, 2022. The Company is still evaluating the effect of adopting this guidance.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses. In May 2019, ASU No. 2016-13 was subsequently amended by ASU No. 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses and reduces both (1) diversity in practiceASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. ASU No. 2016-13, as amended, affects trade receivables, financial assets and (2)certain other instruments that are not measured at fair value through net income. This ASU replaced the incurred loss approach with an expected loss model for instruments measured at amortized cost and complexity when applyingwas effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. ASU No. 2016-13 will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance in Topic 718 Compensation - Stock Compensation, tois effective. The Company adopted this ASU on January 1, 2020, and the adoption did not have a changematerial impact on the consolidated financial statements and related disclosures.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) which removes or modifies current fair value disclosures and adds additional disclosures. The update to the termsguidance is the result of the FASB’s test of the principles developed in its disclosure effectiveness project, which is designed to improve the effectiveness of disclosures in the notes to the financial statements. The disclosures that have been removed or conditions of a share-based payment award.modified may be applied immediately with retrospective application. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2020, and the adoption did not have a material impact on the consolidated financial statements and related disclosures.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40) which aligns 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. For public entities, the guidance is effective for fiscal years beginning after December 15, 2017,2019, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company has completed its evaluation and the adoption of this ASU is not expected to have a significant effect on its consolidated financial statements and related disclosures.
In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the
amendments, only when the transaction has not been reported in the financial statements that have been issued. The Company is currently evaluating this ASU and believes it could have a material impact to its consolidated financial statements and related disclosures, as it may result in more transactions being accounted for as asset acquisitions rather than business combinations.
In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures.
In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. In addition, in November 2016, the FASB issued ASU No. 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company has completed its evaluation and the adoption of this ASU is not expected to have a significant effect on its consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-09, which simplifies the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the consolidated statement of cash flows. ASU No. 2016-09 was effective for public companies for annual and interim reporting beginning after December 15, 2016, including interim periods within those fiscal years. The Company adopted this guidance during the first quarter of 2017. As a result of adoption of this guidance, the Company elected to account for the forfeiture of stock-based compensation forfeitures as they occur. The adoption of this standard did not have a significant impact on the Company's consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four step decision sequence in FASB ASB Topic 815, Derivatives and Hedging, as amended by this ASU. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. The Company adopted this ASU in the first quarter of 2017 and the adoption of this ASUon January 1, 2020 which did not have a material impact on the its consolidated financial statements and related disclosures.disclosures as capitalized costs for internal-use software were not material during 2020.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight linestraight-line basis. Under the new standard, certain lease agreements with terms over one year are classified as right-of-use assets and right-of-use liabilities, which gross up the balance sheet. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted.2018. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10 and ASU No. 2018-01,2018-11, which provided additional implementation guidance. The Company is currently evaluatingadopted these lease accounting standards on January 1, 2019 using a modified retrospective transition approach, which applied the impact this ASU will have on its consolidated financial statements and related disclosures. As a part of the assessment work to-date, the Company formed an implementation team, completed trainingprovisions of the new guidance and is developing a strategyat the effective date without adjusting the comparative periods presented. Upon adoption, the Company elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, requires no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease classification for implementation.existing
leases upon adoption. The Company also elected the optional practical expedient permitted under the transition guidance within the new standard related to land easements that allows it to carry forward its current accounting treatment for land easements on existing agreements. The Company made an accounting policy election to keep leases with an initial term of twelve months or less off of the consolidated balance sheets. Please refer to Note 7 — Leases for further information.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) which establishes a comprehensive new revenue recognition model, referred to as ASC 606, designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and iswas effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-13, ASU No. 2017-14 and ASU No. 2017-14,2019-20, which provided additional implementation guidance. The Company completed its reviewRefer to —Adoption of contracts in eachASC 606 for more information.
Adoption of its revenue streams and has developed accounting policies to address the provisions of this ASU. While the Company does not expect operating income (loss) to be materially impacted, the Company does expect total revenues and total expenses to change as a result of certain contracts where title of production transfers to customers at the wellhead. Further, the Company evaluated the design of its pre-adoption and adoption controls and had developed new or modified certain controls to address risks associated with recognizing revenue under the new standard as the Company continues the implementation process. The Company will continue to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures and has not finalized any estimates of theASC 606
potential impacts. The Company will adopt this new standard onOn January 1, 2018, the Company adopted ASC 606. The Company adopted ASC 606 using the modified retrospective method to apply the new standard to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.
Changes to sales of natural gas and NGL, as well as transportation and gathering expenses, are due to the conclusion that certain midstream processing entities are the Company’s customers in natural gas processing and marketing agreements in accordance with the five-step process in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the Company determined it was the principal, the midstream processor was the agent and the third-party end user was its customer. As a result, the Company modified its presentation of revenues and operating expenses for these agreements. Revenues related to these agreements are now presented on a net basis for proceeds expected to be received from the midstream processing entity. Revenues from the sale of oil, natural gas and NGLs, where the Company is a non-operating interest partner, are considered in the scope of ASC 808 - Collaborative Arrangements. Therefore, ASC 606 did not change the presentation of these revenues.
Transportation and gathering expense related to other agreements incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities will continue to be presented as transportation and gathering expense.
Revenues from Contracts with Customers
Sales of oil, natural gas and NGLs are recognized at the point control of the commodity is transferred to the customer and collectability is reasonably assured. The majority of the Company’s contracts’ pricing provisions are tied to a commodity market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGLs fluctuates to remain competitive with the other available oil, natural gas and NGL supplies.
Oil Sales
Under the Company’s crude purchase and marketing contracts, the Company generally sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received.
To account for producer imbalances, the Company recognizes revenue on all sales to third party customers regardless of their ownership percentage and adjusts the underlifter or overlifter’s claim on the asset’s remaining reserves. As of December 31, 2020, the Company had an oil imbalance of 1.1 MBbl, which the Company intends to settle with the counterparty in crude oil barrels.
Natural Gas and NGL Sales
Under the Company’s natural gas processing contracts, the Company delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction, and the point at which control of the hydrocarbons transfers to the customer. For those contracts where the Company has concluded the midstream processing entity is the Company’s agent and the third-party end user is its customer (generally the Company’s fixed-fee gathering and processing agreements), the Company recognizes revenue on a gross basis, with transportation and gathering expense presented as an operating expense in the consolidated statements of operations. Alternatively, for those contracts where the Company has concluded the midstream processing entity is its customer and controls the hydrocarbons (generally the Company’s percentage of proceeds gathering and processing agreements), the Company recognizes natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing company.
In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when the control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering and processing expense attributable to the gas processing contracts, as well as any transportation expense incurred to deliver the product to the purchaser, are presented as transportation and gathering expense in the consolidated statements of operations.
Performance Obligations
A significant number of the Company’s product sales are short-term in nature with a cumulative adjustmentcontract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price of a contract that has an original expected duration of one year or less.
For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a), which states the Company is not required to retained earnings,disclose the transaction price allocated to remaining performance obligations if necessary.the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The Company records revenue on its oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products. The Company records the differences between the revenue estimated and the actual amounts received for product sales in the month that payment is received from the customer.
Contract Balances
The Company had a certain revenue contract with an initial term beginning on November 1, 2016 and continuing until October 31, 2020 after which the contract was to begin an automatic month-to-month renewal unless terminated by either party giving notice at least six months prior to the effective termination date but in no event could either party give such notice earlier than November 1, 2020. Based on the accounting treatment pursuant to ASC 606 — Revenue from Contracts with Customers, the contract term would end on April 30, 2021 because it could be terminated by either party with no penalty effective as of such date. The contract term impacted the amount of consideration that could be included in the transaction price. The Company recognizes revenue and invoices customers once its performance obligations have been satisfied. When it becomes probable that the Company will not meet its performance obligations, the transaction price allocated to the performance obligation is constrained in the amount of the estimated unmet performance obligation and recognized as a reduction to revenue in the period in which the transaction price changes. On June 12, 2020, the Company and the counterparty to the contract mutually cancelled the contract effective June 30, 2020. As a result of the cancellation, for the year ended December 31, 2020, $12.3 million was recorded as a reduction in the transaction price resulting from unsatisfied performance obligations in the period. For the year ended December 31, 2019, the Company allocated $24.7 million to a satisfied performance obligation recognized within oil sales under ASC 606. As a result of the contract termination, the Company incurred an early termination
fee of $13.2 million recorded in other operating expenses for the year ended December 31, 2020. This amount was settled during the third quarter of 2020, and there are no remaining amounts due to the counterparty.
The following table presents the Company’s revenues disaggregated by revenue source. Transportation and gathering costs in the following table are not all of the transportation and gathering expenses that the Company incurs, only the expenses that are netted against revenues pursuant to ASC 606.
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| Revenues: | | | | | |
| Oil sales | $ | 382,526 | | | $ | 721,429 | | | $ | 840,687 | |
| Natural gas sales | 114,786 | | | 129,969 | | | 121,180 | |
| NGL sales | 89,634 | | | 92,429 | | | 134,558 | |
| Gathering and compression | 1,473 | | | 1,261 | | | 0 | |
| Transportation and gathering included in revenues | (30,515) | | | (38,453) | | | (35,682) | |
| Total Revenues | $ | 557,904 | | | $ | 906,635 | | | $ | 1,060,743 | |
There are no other accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of December 31, 2017,2020 and through the date of this filing that would have a material impact on the Company’s consolidated financial statements and related disclosures.
Note 3—Oil and Gas Properties
The Company’s oil and gas properties are entirely within the United States. The net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
| | | | | | | | | | | | | | |
| | | As of December 31, |
| | | 2020 | | 2019 |
| Proved oil and gas properties | $ | 4,743,463 | | | $ | 4,530,934 | |
| Unproved oil and gas properties (1) | 220,380 | | | 524,214 | |
| Wells in progress (2) | 129,058 | | | 149,733 | |
| Total capitalized costs (3) | $ | 5,092,901 | | | $ | 5,204,881 | |
| Accumulated depletion, depreciation, amortization and impairment charge (4) | $ | (3,459,689) | | | (2,985,983) | |
| Net capitalized costs | | $ | 1,633,212 | | | $ | 2,218,898 | |
| | | | |
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| Proved oil and gas properties | $ | 3,011,526 |
| | $ | 1,851,052 |
|
Unproved oil and gas properties(1) | 686,968 |
| | 452,577 |
|
Wells in progress(2) | 127,418 |
| | 98,747 |
|
Total capitalized costs(3) | $ | 3,825,912 |
| | $ | 2,402,376 |
|
| Accumulated depletion, depreciation and amortization | (709,662 | ) | | (402,912 | ) |
| Net capitalized costs | $ | 3,116,250 |
| | $ | 1,999,464 |
|
(2) Costs from wells in progress are excluded from the amortization base until production commences. (3) Includes accumulated interest capitalized of $45.1 million and $39.8 million as of December 31, 2020 and 2019, respectively. | |
(1) | Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until proved reserves are established or impairment is determined. |
| |
(2) | Costs from wells in progress are excluded from the amortization base until production commences. |
| |
(3) | Includes accumulated interest capitalized of $24.5 million, $13.4 million and $8.2 million as of December 31, 2017, 2016 and 2015, respectively. |
(4) For more information about proved oil and gas properties impairment, see Note 2 — Basis of Presentation and Significant Accounting Policies.
The following table presents information regarding the Company’s net costs incurred in oil and gas property acquisition, exploration and development activities (in thousands):
| | | | | | | | | | | | | | |
| | | For the Year Ended |
| | | December 31, |
| | | 2020 | | 2019 |
| Property acquisition costs: | | | |
| Proved | $ | 8,071 | | | $ | 21,024 | |
| Unproved | 8,970 | | | 35,207 | |
| Exploration costs (1) | 0 | | | 3,569 | |
| Development costs | 173,538 | | | 588,974 | |
| Total | $ | 190,579 | | | $ | 648,774 | |
| Total excluding asset retirement costs | $ | 176,629 | | | $ | 598,778 | |
| | | | |
(1) Exploration costs do not include abandonment costs of unproved properties, which are included in the line item exploration and abandonment expenses in the consolidated statements of operations.
|
| | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 |
| Property acquisition costs: | | | |
| Proved | $ | 139,481 |
| | $ | 319,832 |
|
| Unproved | 382,213 |
| | 220,213 |
|
Exploration costs(1) | 17,074 |
| | 13,588 |
|
| Development costs | 894,040 |
| | 317,228 |
|
| Total | $ | 1,432,808 |
| | $ | 870,861 |
|
| Total excluding asset retirement costs | $ | 1,420,235 |
| | $ | 863,874 |
|
| |
(1) | Exploration costs do not include impairment and abandonment costs of unproved properties, which are included in the line item exploration expenses in the consolidated statements of operations. |
Note 4—Acquisitions and Divestitures
November 2017February 2020 Divestiture
In February 2020, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $12.2 million, subject to customary purchase price adjustments. NaN gain or loss was recognized for the February 2020 Divestiture. The Company continues to explore divestitures, as part of our ongoing initiative to divest of non-strategic assets.
December 2019 Divestiture
In December 2019, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $10.0 million, subject to customary purchase price adjustments. NaN gain or loss was recognized for the December 2019 Divestiture.
August 2019 Divestiture
In August 2019, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $22.0 million, subject to customary purchase price adjustments. NaN gain or loss was recognized for the August 2019 Divestiture.
March 2019 Divestiture
In March 2019, the Company completed the sale of its interests in approximately 5,000 net acres of leasehold and producing properties for aggregate sales proceeds of approximately $22.4 million. The effective date for the March 2019 Divestiture was July 1, 2018 with purchase price adjustments calculated as of the closing date of $5.9 million, resulting in net proceeds of $16.5 million. No gain or loss was recognized for the March 2019 Divestiture.
December 2018 Divestitures
In December 2018, the Company completed various sales of its interests in approximately 31,200 net acres of leasehold and primarily non-producing properties, for aggregate sales proceeds of approximately $8.5 million, subject to customary purchase price adjustments, and recognized a loss of $6.1 million.
August 2018 Divestiture
In August 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for the year ended December 31, 2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset.
April 2018 Divestitures
In April 2018, the Company completed various sales of its interests in approximately 15,100 net acres of leasehold and primarily non-producing properties for aggregate sales proceeds of approximately $72.3 million and recognized a gain of $59.3 million for the year ended December 31, 2018.
April 2018 Acquisition
On November 15, 2017,In April 2018, the Company acquired an unaffiliated oil and gas company'scompany’s interest in approximately 36,6001,000 net acres of non-producing leasehold and primarily non-producing properties located in Arapahoe County, Colorado, (the "November 2017 Acquisition").Colorado. Upon closing the seller received $214.3approximately $9.4 million in cash, subject to customary purchase price adjustments. The Company also recorded a liability of $12.2 million for the final settlement payment due in April 2018 in conjunction with
November 2017 Acquisition, which has been reflected in the December 31, 2017 consolidated balance sheets within the accounts payable and accrued liabilities line item.cash. This transaction has been accounted for as an asset acquisition. The acquisition providesprovided new development opportunities in the Core DJ Basin.
July 2017January 2018 Acquisition
On July 7, 2017,January 8, 2018, the Company acquired an unaffiliated oil and gas company’s interestsinterest in approximately 12,5001,200 net acres of non-producing leasehold and primarily non-producing properties located primarily in AdamsArapahoe County, Colorado, (the "July 2017 Acquisition").Colorado. Upon closing the seller received total consideration of $84.0approximately $11.6 million in cash. The effective date for the July 2017 Acquisition is July 1, 2017. This transaction has been accounted for as an asset acquisition. The acquisition providesprovided new development opportunities in the Core DJ Basin.
On June 8, 2017,Note 5—Liabilities Subject to Compromise
The Company’s liabilities subject to compromise consisted of the following (in thousands):
| | | | | |
| December 31,
2020 |
| Accounts payable and accrued liabilities | $ | 54,647 | |
| Revenue payable | 59,848 | |
| Production taxes payable - current | 151,971 | |
| Production taxes payable - non-current | 22,405 | |
| Asset retirement obligations - current | 14,304 | |
| Asset retirement obligations - non-current | 80,465 | |
| Accrued interest on debt subject to compromise | 31,676 | |
| 2024 Senior Notes due May 15, 2024 | 400,000 | |
| 2026 Senior Notes due February 1, 2026 | 700,189 | |
| Deferred liability | 7,153 | |
| Damages for rejected and settled contracts | 582,439 | |
| Elevation cash settlement | 38,400 | |
| Total liabilities subject to compromise | $ | 2,143,497 | |
As discussed in Note 1 — Business and Organization — Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, since the Petition Date, the Company acquired an unaffiliated oilhas been operating as debtor-in-possession under the jurisdiction of the Bankruptcy Court and gas company’s interests in approximately 160 net acresaccordance with provisions of leaseholdthe Bankruptcy Code. On the accompanying consolidated balance sheets, the line item liabilities subject to compromise reflects the expected allowed amount of the prepetition claims that are not fully secured and that have at least a possibility of not being repaid at the full claim amount. Determination of the value at which liabilities will ultimately be settled was determined when the Bankruptcy Court approved the Plan on December 23, 2020. In addition, the manner by which those liabilities are settled was determined by the aforementioned Plan and will include settlement in cash, Successor Company New Common Stock or a combination. Liabilities subject to compromise includes amounts related producing properties located in Weld County, Colorado (the “June 2017 Acquisition”).to the rejection of various executory contracts and unexpired leases. The Company paid approximately $13.4 million in cash consideration in connectionwill continue to evaluate the amount and classification of its prepetition liabilities.
Note 6—Reorganization Items, Net
The Company’s reorganization items, net consisted of the following (in thousands):
| | | | | | | | | |
| | | For the Year Ending |
| | | December 31,
2020 |
| Professional fees | | | $ | 59,841 | |
| Professional services fees | | | 2,200 | |
| Trustee fees | | | 801 | |
| Damages for rejected and settled contracts | | | 572,126 | |
| DIP Credit Facility fees | | | 1,717 | |
| Write-off of debt issuance costs | | | 13,541 | |
| Court approved vendor settlements | | | (2,602) | |
| Backstop commitment premium | | | 29,231 | |
| Total reorganization items, net | | | $ | 676,855 | |
The Company has incurred and will continue to incur significant expenses, gains and losses associated with the closingreorganization, primarily adjustments for allowable claims related to executory contracts approved for rejection by the Bankruptcy Court, negotiated settlements on executory contracts, the write-off of unamortized debt issuance costs and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The amount of these items, which are being incurred in reorganization items, net within the Company’s accompanying consolidated statements of operations, are expected to significantly affect the Company’s results of operations.
As of December 31, 2020, $633.6 million of reorganization costs, net consisting of professional fees, trustee fees, damages for rejected or settled contracts and backstop party premiums are accrued and unpaid and are presented in either accounts payable and accrued liabilities or liabilities subject to compromise on the consolidated balance sheets. The write-off of the June 2017 Acquisition.Senior Notes debt issuance costs are included in reorganization items, net as the underlying debt instruments were impacted by the Chapter 11 Cases. The effective date for the acquisition was January 1, 2017, with purchase price adjustments calculated aswrite-off of the closing date of June 8, 2017. The acquisition increased the Company's interest in existing operated wells. The acquired producing properties contributed $3.7 million of revenue and $3.0 million of earnings, respectively, forSenior Notes debt issuance costs is a non-cash reorganization item. For the year ended December 31, 2017. 2020, the Company had cash charges related to reorganization items, net of $34.4 million.
Note 7—Leases
The acquired producing properties contributed no revenueCompany accounts for leases in accordance with ASC 842, Leases, which it adopted on January 1, 2019, applying the modified retrospective transition approach as of the effective date of adoption (see Note 2 — Basis of Presentation and earningsSignificant Accounting Policies — Recent Accounting Pronouncements for impacts of adoption).
The Company enters into operating leases for certain drilling equipment, completions equipment, equipment ancillary to drilling and completions, office facilities, compressors and office equipment. Under ASC 842, a contract is or contains a lease when (i) the contract contains an explicitly or implicitly identified asset and (ii) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. The Company assesses whether an arrangement is or contains a lease at inception of the contract. All leases (operating leases), other than those that qualify for the short-term recognition exemption, are recognized as of the lease commencement date on the balance sheet as a liability for its obligation related to the lease and a corresponding asset representing its right to use the underlying asset over the period of use.
The Company’s leases have remaining terms up to four years. Certain of our lease agreements contain options to extend or early terminate the agreement. The lease term used to calculate the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that the Company will exercise an option at commencement, it considers various economic factors, including capital expenditure strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, the Company generally determines that the exercise of renewal options would not be reasonably certain in determining the expected lease term for leases, other than certain operating compressor leases.
The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As the Company’s leases generally do not provide an implicit rate, the Company uses its incremental borrowing rate based on its Prior Credit Facility, which includes consideration of the nature, term, and geographic location of the leased asset.
Certain of the Company’s leases include variable lease payments, including payments that depend on an index or rate, as well as variable payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of the Company’s lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of the Company’s lease assets and liabilities and are recognized in the period in which the obligation for those payments is incurred. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants.
The Company has elected, for all classes of underlying assets, to not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and instead, recognize the lease payments in the consolidated statements of operations on a straight-line basis over the lease term. The Company has also made the election, for its certain drilling equipment, completions equipment, equipment ancillary to drilling and completions, compressors and office equipment classes of underlying assets, to account for lease and non-lease components in a contract as a single lease component.
For the year ended December 31, 2020, lease costs, which represent the straight-line lease expense of right-of-use (“ROU”) assets and short-term leases, were as follows (in thousands):
| | | | | | | | | | | | | | |
| | For the Year Ended December 31, | | For the Year Ended December 31, |
| | 2020 | | 2019 |
| Lease Costs included in the Consolidated Balance Sheets | | | |
| Proved oil and gas properties, including drilling, completions and ancillary equipment, and gathering systems and facilities (1) | $ | 69,104 | | | $ | 259,737 | |
| | | | |
| Lease Costs included in the Consolidated Statements of Operations | | | |
| Operating lease costs (2) | $ | 23,060 | | | $ | 33,025 | |
| General and administrative expenses (3) | $ | 3,074 | | | $ | 3,821 | |
| Total operating lease costs | $ | 26,134 | | | $ | 36,846 | |
| | | | |
| Total lease costs | $ | 95,238 | | | $ | 296,583 | |
| | | | |
(1) Represents short-term lease capital expenditures related to drilling rigs, completions equipment and other equipment ancillary to the drilling and completion of wells.
(2) Includes $6.0 million and $8.8 million of lease costs accounted for under ASC 842 for the years ended December 31, 20162020 and 2015. No significant transaction2019, respectively.
(3) Includes $1.0 million and $1.4 million of lease costs related to the acquisition were incurredaccounted for under ASC 842 for the years ended December 31, 2017, 20162020 and 2015.2019, respectively.
The June 2017 Acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of June 8, 2017. In August 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
|
| | | | |
| Purchase Price | | June 8, 2017 |
| Consideration given | | |
| Cash | | $ | 13,395 |
|
| Total consideration given | | $ | 13,395 |
|
| Allocation of Purchase Price | | |
| Proved oil and gas properties | | $ | 13,495 |
|
| Total fair value of oil and gas properties acquired | | $ | 13,495 |
|
| Asset retirement obligations | | $ | (100 | ) |
| Fair value of net assets acquired | | $ | 13,395 |
|
November 2016 Acquisition
On November 22, 2016, the Company acquired an unaffiliated oil and gas company’s interest in approximately 9,200 net acres of leaseholds located in the Core DJ Basin for approximately $120.0 million, including customary closing adjustments. The Company also made a $41.1 million deposit in November 2016 in conjunction with the November 2016 Acquisition, which has been reflected in the December 31, 2016 consolidated balance sheets within theSupplemental cash held in escrow line item. The deposit was made for two additional closings of leaseholds located in the Core DJ Basin. The first closing occurred in January 2017 and added approximately 5,300 net acres for approximately $26.8 million. The second closing occurred in July 2017 and added approximately 640 net acres for approximately $10.9 million. This transaction has been accounted for as an asset acquisition.
October 2016 Acquisition
On October 3, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 6,400 net acres of leasehold, and related producing and non‑producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “Bayswater Assets” and the acquisition, the “October 2016 Acquisition”). The seller received aggregate consideration of approximately $405.3 million in cash. The effective date for the acquisition was July 1, 2016, with purchase price adjustments calculated as of
the closing date on October 3, 2016. The acquisition provides new development opportunities in the DJ Basin as well as increases the Company’s existing working interest, as the majority of the locations are located on acreage in which the Company already owns a majority working interest and operates. The acquired producing properties contributed revenue of $17.2 million for the year ended December 31, 2016. The Company determined that it is not practical to calculate net income associated with October 2016 Acquisition. The Company incurred $2.6 million of transaction costsflow information related to the acquisition for year ended December 31, 2016. These transaction costs are recorded in the consolidated statements of operations within the acquisition transaction expenses line item. No transaction costs related to the acquisition were incurredoperating leases for the years ended December 31, 20172020 and 2015.
The acquisition is accounted for using the acquisition method under ASC 805,Business Combinations, which requires the acquired assets and liabilities to be recorded at fair value2019, was as of the acquisition date of October 3, 2016. In February 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumedfollows (in thousands):
| | | | | | | | | | | |
| For the Year Ended December 31, | | For the Year Ended December 31, |
| 2020 | | 2019 |
| Cash paid for amounts included in the measurements of lease liabilities | | | |
| Operating cash flows from operating leases | $ | 14,146 | | | $ | 12,923 | |
| Right-of-use assets obtained in exchange for lease obligations | | | |
| Operating leases | $ | 5,057 | | | $ | 12,805 | |
|
| | | | |
| Purchase Price | | October 3, 2016 |
| Consideration given | | |
| Cash | | $ | 405,335 |
|
| Total consideration given | | $ | 405,335 |
|
| Allocation of Purchase Price | | |
| Proved oil and gas properties | | $ | 252,522 |
|
| Unproved oil and gas properties | | 109,800 |
|
| Total fair value of oil and gas properties acquired | | $ | 362,322 |
|
Goodwill (1) | | $ | 54,220 |
|
| Working capital | | (7,185 | ) |
| Asset retirement obligations | | (4,022 | ) |
| Fair value of net assets acquired | | $ | 405,335 |
|
| Working capital acquired was estimated as follows: | | |
| Accounts receivable | | $ | 955 |
|
| Revenue payable | | (3,012 | ) |
| Production taxes payable | | (4,244 | ) |
| Accrued liabilities | | (884 | ) |
| Total working capital | | $ | (7,185 | ) |
| |
(1) | Goodwill is primarily attributable to a decrease in commodity prices from the time the acquisition was negotiated and commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the acquisition. Goodwill recognized as a result of the Bayswater Acquisition is not deductible for income tax purposes. |
Option to Acquire Additional Assets from October 2016 Acquisition
Upon the closing of the October 2016 Acquisition, the Company made a $10.0 million non‑refundable payment for an option to purchase additional assets from the seller of the October 2016 Acquisition (the “Additional Assets”) for an additional $190.0 million, for a total purchase price for the Additional Assets of $200.0 million. The option may be exercised at any time until March 31, 2017. If the Company does not exercise the option to acquire the Additional Assets, the seller will have the right until April 30, 2017 to elect to sell those assets to the Company for an additional $120.0 million, for a total purchase price for the Additional Assets of $130.0 million. In March 2017, the Company entered into an amendment to this agreement with Bayswater to terminate both the Company's and Bayswater’s options for no further consideration. The $10.0 million was expensed in the fourth quarter of 2016 to other operating expenses within the consolidated statements of operations.
August 2016 Acquisition
On August 23, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 1,400 net acres of leasehold located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way and other assets (the “August 2016 Acquisition”). The seller received aggregate consideration of
approximately $17.5 million in cash. The effective date for the acquisition was August 31, 2016, with purchase price adjustments calculated as of the closing date of August 23, 2016. The acquisition provided new development opportunities in the DJ Basin as well as additions adjacent to the Company’s core project area. The Company incurred $0.1 million of transaction costsSupplemental balance sheet information related to the acquisition. These transaction costsoperating leases were recorded in the condensed consolidated statements of operations within the acquisition transaction expenses line item in the third quarter of 2016.
The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of August 23, 2016. In March 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
|
| | | | |
| Purchase Price | | August 23, 2016 |
| Consideration given | | |
| Cash | | $ | 17,504 |
|
| Total consideration given | | $ | 17,504 |
|
| Allocation of Purchase Price | | |
| Proved oil and gas properties | | $ | 12,362 |
|
| Unproved oil and gas properties | | 8,566 |
|
| Total fair value of oil and gas properties acquired | | $ | 20,928 |
|
| Working capital | | $ | (9 | ) |
| Asset retirement obligations | | (3,415 | ) |
| Fair value of net assets acquired | | $ | 17,504 |
|
| Working capital acquired was estimated as follows: | | |
| Production taxes payable | | (9 | ) |
| Total working capital | | $ | (9 | ) |
March 2015 Acquisition
On March 10, 2015, the Company acquired an unaffiliated oil and gas company’s interests in approximately 39,000 net acres of leasehold, and related producing properties located primarily in Adams, Broomfield, Boulder and Weld Counties, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “March 2015 Acquisition”). The seller received aggregate consideration of approximately $120.5 million in cash. The effective date for the acquisition was January 1, 2014, with purchase price adjustments calculated as of the closing date on March 10, 2015. The acquisition provided new development opportunities in the DJ Basin as well as additions adjacent to the Company’s core project area and the acquired producing properties contributed revenue of $8.0 million to the Company for the year ended December 31, 2015. The Company determined that it is not practical to calculate net income associated with March 2015 Acquisition. The Company incurred $0.5 million of transaction costs related to the acquisition for the year ended December 31, 2015. These transaction costs are recorded in the consolidated statements of operations within the general and administrative expenses line item. No transaction costs related to the acquisition were incurred for the years ended December 31, 2017 and 2016. Additionally, the Company incurred $6.0 million of non‑cash transaction costs associated with a finder’s fee to an unaffiliated third‑party. The Company assigned an over‑riding royalty interest in the proved and unproved oil and gas properties acquired in the March 2015 Acquisition, which had a fair value of $6.0 million on the measurement date. These transaction costs are recorded in the consolidated statements of operations within the acquisition transaction expense line item.
The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of March 10, 2015. In November 2015, the Company completed the transaction’s post‑closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
|
| | | | |
| Purchase Price | | March 10, 2015 |
| Consideration given | | |
| Cash | | $ | 120,524 |
|
| Total consideration given | | $ | 120,524 |
|
| Allocation of Purchase Price | | |
| Proved oil and gas properties | | $ | 80,952 |
|
| Unproved oil and gas properties | | 69,450 |
|
| Total fair value of oil and gas properties acquired | | $ | 150,402 |
|
| Working capital | | $ | (1,996 | ) |
| Asset retirement obligations | | (27,882 | ) |
| Fair value of net assets acquired | | $ | 120,524 |
|
| Working capital acquired was estimated as follows: | | |
| Accounts receivable | | $ | 462 |
|
| Revenue payable | | (718 | ) |
| Production taxes payable | | (1,740 | ) |
| Total working capital | | $ | (1,996 | ) |
Pro Forma Financial Information (Unaudited)
For the years ended December 31, 2017 and 2016, the following pro forma financial information represents the combined results for the Company and the properties acquired in June 2017 as if the acquisition and related financing had occurred on January 1, 2016 and for the properties acquired in October 2016 as if the acquisition and related financing had occurred on January 1, 2015. For the year ended December 31, 2015, the following pro forma financial information represents the combined results for the Company and the properties acquired in March 2015 as if the acquisition and related financing had occurred on January 1, 2015 (all in thousands, except per share data). For purposes of the pro forma financial information, it was assumed that the June 2017 Acquisition was funded through cash. For purposes of the pro forma financial information, it was assumed that the October 2016 Acquisition was funded through the issuance of $260.3 million in convertible preferred securities and borrowings under the revolving credit facility. For purposes of the pro forma financial information, it was assumed that the Company issued equity to finance the March 2015 Acquisition. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $1.6 million, $23.1 million and $1.5 million for the years ended December 31, 2017, 2016 and 2015, respectively. No pro forma adjustments were made for non-recurring transaction costs for the year ended December 31, 2017. The pro forma information includes the effects of a decrease in non-recurring transaction costs that are included in general and administrative expenses and acquisition transaction expenses of $2.6 million and $6.4 million for the years ended December 31, 2016 and 2015, respectively. No pro forma adjustments were made for incremental interest expense on acquisition financing for the year ended December 31, 2017. The pro forma information includes the effects of adjustments for the incremental interest expense on acquisition financing of $4.0 million and $4.0 million for the years endedDecember 31, 2016 and 2015, respectively. The pro forma information includes the effects of adjustments for income taxes of $0.6 million for the year ended December 31, 2017. No pro forma adjustments were made for the effect of income taxes for the years ended December 31, 2016 and 2015 as the acquisitions occurred before the Corporate Reorganization. Additionally, the pro forma financial information excludes the effects the August 2016 Acquisition as these pro forma adjustments were de minimis.
The following pro forma resultsfollows (in thousands, except per share data) do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicativelease term and discount rate):
| | | | | | | | | | | | | | | | | |
| 2020 Classification | | As of December 31, 2020 | | As of December 31, 2019 |
| Operating Leases | | | | | |
| Operating lease right-of-use assets | Other non-current assets | | $ | 8,199 | | | $ | 29,186 | |
| | | | | |
| Operating lease obligation - short-term | Liabilities subject to compromise | | 4,279 | | | 17,388 | |
| Operating lease obligation - long-term | Liabilities subject to compromise | | 4,357 | | | 17,166 | |
| Total operating lease liabilities | | | $ | 8,636 | | | $ | 34,554 | |
| | | | | |
| Weighted Average Remaining Lease Term in Years | | | | |
| Operating leases | | | 2.3 | | 4.4 |
| Weighted Average Discount Rate | | | | | |
| Operating leases | | | 4.5 | % | | 4.2 | % |
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Revenues | $ | 606,460 |
| | $ | 325,355 |
| | $ | 214,259 |
|
| Net loss | $ | (44,231 | ) | | $ | (441,571 | ) | | $ | (33,524 | ) |
| Loss per share | | | | | |
| Basic and diluted | $ | (0.35 | ) | | $ | (1.54 | ) | | |
|
Note 5—Long‑Term8—Long-Term Debt
As of the dates indicated theThe Company’s long‑termlong-term debt consisted of the following (in thousands):
| | | | | | | | | | | | | | |
| | | As of December 31, |
| | | 2020 | | 2019 |
| DIP Credit Facility | $ | 106,727 | | | $ | — | |
| Prior Credit Facility due August 16, 2022 (or an earlier time as set forth in the credit facility) | 453,747 | | | 470,000 | |
| 2024 Senior Notes due May 15, 2024 | 400,000 | | | 400,000 | |
| 2026 Senior Notes due February 1, 2026 | 700,189 | | | 700,189 | |
| Total principal | 1,660,663 | | | 1,570,189 | |
| Unamortized debt issuance costs on Senior Notes (1) | 0 | | | (14,412) | |
| Total debt, prior to reclassification to liabilities subject to compromise | 1,660,663 | | | 1,555,777 | |
| Less amounts reclassified to liabilities subject to compromise (2) | (1,100,189) | | | 0 | |
| Total debt not subject to compromise (3) | 560,474 | | | 1,555,777 | |
| Less: current portion of long-term debt (4) | (560,474) | | | 0 | |
| Total long-term debt, net of current portion | $ | 0 | | | $ | 1,555,777 | |
| | | | |
(1) As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company wrote off all unamortized debt issuance cost balances to reorganization items, net in the consolidated statements of operations during the year ended December 31, 2020. |
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| Credit facility due November 29, 2018 | $ | 90,000 |
| | $ | — |
|
| 2021 Senior Notes due July 15, 2021 | 550,000 |
| | 550,000 |
|
| 2024 Senior Notes due May 15, 2024 | 400,000 |
| | — |
|
| Unamortized debt issuance costs on Senior Notes | (16,639 | ) | | (11,859 | ) |
| Total long-term debt | $ | 1,023,361 |
| | $ | 538,141 |
|
(3) Debt not subject to compromise includes all borrowings outstanding under the Prior Credit Facility and DIP Credit Facility which are fully secured claims in the Chapter 11 Cases and are expected to be unimpaired.
(4) Due to uncertainties regarding the outcome of the Chapter 11 Cases, the Company has classified the borrowings outstanding under the Prior Credit Facility and DIP Credit Facility as current liabilities on the consolidated balance sheets as of December 31, 2020.
RBL Credit Facility
On September 4, 2014, Holdingsthe Emergence Date at emergence, pursuant to the terms of the Plan, the Successor Company entered into a $1.0 billion reserve-based credit facilityagreement (“RBL Credit Agreement”) with Wells Fargo Bank, National Association (“RBL Credit Facility”) with an initial borrowing base of $500.0 million. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year, with one interim “wildcard” redetermination available to each of the Company and the bank between scheduled redeterminations during any 12-month period. The next scheduled redetermination will be on or around May 1, 2021. The initial elected amount under the RBL Credit Facility is $500.0 million before giving effect to any outstanding letters of credit.
As of the date of this filing, the Company has drawn $253.7 million on the RBL Credit Facility. Total funds available for borrowing under the Company’s RBL Credit Facility, after giving effect to an aggregate of $0.5 million of undrawn letters of credit, were $245.8 million as of the date of this filing.
The RBL Credit Facility provides for a syndicate$50.0 million sublimit of banks, whichthe aggregate commitments that is available for the issuance of letters of credit. The RBL Credit Facility bears interest either at a rate equal to (a) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum or (b) a base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. The RBL Credit Facility matures on July 20, 2024. The grid below shows the base rate margin and eurodollar margin depending on the applicable borrowing base utilization percentage as of the date of this filing:
RBL Credit Facility Borrowing Base Utilization Grid
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Base Rate | | Eurodollar | | Commitment |
| Borrowing Base Utilization Percentage | | Utilization | | Margin | | Margin | | Fee Rate |
| Level 1 | | <25% | | 2.00 | % | | 3.00 | % | | 0.50 | % |
| Level 2 | | ≥ | 25% | < | 50% | | 2.25 | % | | 3.25 | % | | 0.50 | % |
| Level 3 | | ≥ | 50% | < | 75% | | 2.50 | % | | 3.50 | % | | 0.50 | % |
| Level 4 | | ≥ | 75% | < | 90% | | 2.75 | % | | 3.75 | % | | 0.50 | % |
| Level 5 | | ≥90% | | 3.00 | % | | 4.00 | % | | 0.50 | % |
The RBL Credit Facility requires the Company to maintain (i) a consolidated net leverage ratio of less than or equal to 3.00 to 1.00 and (ii) a consolidated current ratio of greater than or equal to 1.00 to 1.00.
The Company is required to pay a commitment fee of 0.50% per annum on the actual daily unused portion of the current aggregate commitments under the RBL Credit Facility. The Company is also required to pay customary letter of credit and fronting fees.
The RBL Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants.
Additionally, the RBL Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If the Company does not comply with the financial and other covenants in the RBL Credit Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Credit Agreement and any outstanding unfunded commitments may be terminated.
Chapter 11 Cases and Effect of Automatic Stay
On June 14, 2020, the Company filed for relief under Chapter 11 of the Bankruptcy Code. The commencement of a borrowing base. In connection withvoluntary proceeding in bankruptcy constituted an immediate event of default under the IPOPredecessor Credit Agreement and the mergerindentures governing the Company’s Senior Notes, resulting in the automatic and immediate acceleration of Holdings into the Company, the Company assumed all of the obligations of HoldingsCompany’s outstanding debt under the credit facilityPredecessor Credit Agreement and becameSenior Notes. In conjunction with the borrower thereunder.
In August 2017,filing of the Chapter 11 Cases, the Company entered into an amendment and restatement of its existing credit facility (prior to amendment and restatement,did not make the "Prior Credit Facility"), to provide aggregate commitments of $1.5 billion with a syndicate of banks, which is subject to a borrowing base. The credit facility matures$14.8 million interest payment on the earlier of (a) August 16, 2022, (b) January 15, 2021 if (and only if) the Company's 2021Company’s 2024 Senior Notes (as defined below) have not been refinanced or repaiddue on May 15, 2020.
Debtor-in-Possession Financing
On June 16, 2020, in full on or prior to January 15, 2021, (c) April 15, 2021, if (and only if) (i)connection with the Series A Preferred Stockfiling of the Chapter 11 Cases, the Debtors entered into a debtor-in-possession credit agreement on the terms set forth in a Superpriority Senior Secured Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”), by and among the Company, as borrower, the Company’s subsidiaries party thereto, as guarantors, the lenders party thereto (the "Series A Preferred Stock"“DIP Lenders”) have not, and Wells Fargo Bank, National Association, as DIP agent and issuing lender, pursuant to which, having been converted into common equity or redeemed prior to April 15, 2021, and (ii) prior to April 15, 2021,granted the maturity dateapproval of the Series A Preferred Stock hasBankruptcy Court, the DIP Lenders agreed to provide the Company with a superpriority senior secured debtor-in-possession credit facility (as amended, the “DIP Credit Facility”) with loans in an aggregate principal amount not been extended to a dateexceed $50.0 million that, is no earlier than six months after August 16, 2022 or (d)among other things, will be used to finance the earlier termination in wholeongoing general corporate needs of the commitments. No principal payments are generally required untilDebtors during the credit agreement matures orcourse of the Chapter 11 Cases. In addition to the $50.0 million of incremental loans, the DIP Credit Facility included $75.0 million in Prior Credit Facility loans rolled over into the event thatDIP Credit Facility during July 2020, for a total facility size of $125.0 million.
As is described above, $22.5 million rolled from the borrowing base falls belowPrior Credit Facility to the outstanding balance. Subsequent toDIP Credit Facility on June 16, 2020 and an additional $52.5 million rolled on July 20, 2020 upon the Bankruptcy Court’s authorization order (the “Final DIP Order”). On July 27, 2020, the Company drew an additional $20.0 million on the DIP Credit Facility leaving $15.0 million of availability on the facility. The DIP Credit Facility is classified as a current liability on the consolidated balance sheets as of December 31, 2017, the Company repaid in full its 2021 Senior Notes.
2020 as it is fully secured and expected to be unimpaired. As of December 31, 2017,2020, the credit facility was subject to a borrowing base of $525.0 million.Company’s DIP Credit Facility borrowings were $35.0 million and $75.0 million had been rolled over from the Prior Credit Facility. As of December 31, 2017,2020, the Company had $90.0a undrawn standby letters of credit of $3.5 million under the DIP Credit Facility, which reduced the availability of borrowings outstanding.the undrawn borrowing base. As of December 31, 2016, with respect2020, the total outstanding balance under the DIP Credit Facility was $106.7 million due to land sale proceeds during the fourth quarter that were required to reduce the DIP Credit Facility per the DIP Credit Agreement.
The annualized, weighted average interest rate for the DIP Credit Facility for the year ending December 31, 2020 was approximately 6.75%.
Upon emergence from bankruptcy on the Emergence Date, the DIP Credit Agreement was terminated and the holders of claims under the DIP Credit Agreement received payment in full, in cash, for allowed claims. Also on this date all liens and security interests granted to secure such obligations were automatically terminated and are of no further force and effect.
Predecessor Credit Agreement
As described in Note 1 — Business and Organization — Plan, Disclosure Statement, and Backstop Commitment Agreement, the Company entered into the Predecessor Credit Agreement and subsequent amendments thereto (“Prior Credit Facility”). The acceleration of the obligations under the Predecessor Credit Agreement as of June 14, 2020 resulted in a cross-default and acceleration of the maturity of the Company’s other outstanding long-term debt. As of December 31, 2020, the Prior Credit Facility had a drawn balance of $453.7 million classified as a current liability on the Company had no outstanding borrowings. consolidated balance sheet as it was fully secured and unimpaired. Because this debt was fully secured, adequate protection payments paid throughout 2020 were classified as interest expense and not a reduction of principal. As is described in the Debtor-in-Possession Financing section above, $22.5 million rolled from the Prior Credit Facility to the DIP Credit Facility on June 16, 2020 and an additional $52.5 million rolled on July 20, 2020 upon court approval of the Final DIP Order. During the third quarter, due to the cancellation of a certain revenue contract discussed in Note 2 — Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements — Contract Balances, $24.3 million was drawn on a $40.0 million letter of credit secured by the Company’s Prior Credit Facility.As of December 31, 20172020 and with respect to the Prior Credit Facility, December 31, 2016,2019, the Company had standby letters of credit of $25.7$9.4 million and $0.6$49.5 million, respectively. At December 31, 2017,respectively, which reduced the availability of the undrawn balanceborrowing base. As of the date of this filing, and excluding any undrawn amounts under letters of credit, the available amount to be borrowed under the credit facilityPrior Credit Facility was $435.0 million.0. As of the date of this filing, the Company had $50.0 million0 borrowings outstanding under the credit facility.Prior Credit Facility due to the Company’s emergence from bankruptcy described below.
The amount available to be borrowed under the Company's revolving credit facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will dependInterest was paid on the volumesPrior Credit Facility throughout 2020 because adequate protection was granted by the Bankruptcy Court to holders of the Company's proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Company's revolving credit facility. In January 2018, the Company completed the November 1, 2017 borrowing base redetermination. As a result of the redetermination, the borrowing base increased to $750.0 million, subject to the current maximum lending commitments of $650.0 million.
Interest on the credit facility is payable at one of the following two variable rates as selected by the Company: a base rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlinedPrior Credit Facility in the Pricing Grid. Additionally,form of interest payments. The adequate protection payments were classified as interest expense and not reduction of principal given that the credit facility provides for a commitment fee of 0.375%debt was considered fully secured, and the Bankruptcy Court did not take any action to 0.50%, depending on borrowing base usage.recharacterize the adequate protection payments as principal reduction. The grid below shows the Base Rate Margin and
Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility) as of the date of this filing:
Borrowing Base Utilization Grid
|
| | | | | | | | | | | |
| | | | | LIBOR | | Base Rate | | Commitment |
| Borrowing Base Utilization Percentage | | Utilization | | Margin | | Margin | | Fee |
| Level 1 | | < 25 | | 2.00 | % | | 1.00 | % | | 0.375 | % |
| Level 2 | | ≥ 25% < 50 | | 2.25 | % | | 1.25 | % | | 0.375 | % |
| Level 3 | | ≥ 50% < 75 | | 2.50 | % | | 1.50 | % | | 0.500 | % |
| Level 4 | | ≥ 75% < 90 | | 2.75 | % | | 1.75 | % | | 0.500 | % |
| Level 5 | | ≥ 90 | | 3.00 | % | | 2.00 | % | | 0.500 | % |
The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the credit facility limits the Company from hedging in excess of 85% of its anticipated production volumes.
The credit facility also contains financial covenants requiring the Company to comply with a current ratio of the Company's consolidated current assets (includes unused commitments under the Company's revolving credit facility and unrestricted cash and excludes derivative assets) to the Company's consolidated current liabilities (excludes obligations under the Company's revolving credit facility, the second lien notes and certain derivative assets), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a net leverage ratio, which is the ratio of (i) consolidated debt less cash balances to (ii) the Company's consolidated EBITDAXweighted average interest rate for the four fiscal quarter period most recently ended, not to exceed 4.0 to 1.0 as of the last day of such fiscal quarter; provided that (a)Prior Credit Facility for the quarteryears ending December 31, 2017, consolidated EBITDAX will be based2020 and 2019 was 5.0% and 4.8%, respectively.
Upon emergence from bankruptcy on the last nine months' consolidated EBITDAX multiplied by 4/3Emergence Date, the Predecessor Credit Agreement was terminated and (b) for the quarters ending on or after March 31, 2018, consolidated EBITDAX will be based on the last twelve months’ consolidated EBITDAX. The Company was in compliance with all financial covenantsholders of claims under the credit facility as of December 31, 2017.
Any borrowings under the credit facility are collateralized by substantially allPredecessor Credit Agreement each received its ratable portion of the assetsPredecessor Credit Agreement for its allowed claims. Also on this date all liens and security interests granted to secure such obligations were automatically terminated and are of the Companyno further force and its subsidiaries, including oil and gas properties, personal property and the equity interests of the subsidiaries of the Company. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the credit facility. The Company’s obligations under these hedging contracts are secured by the collateral securing the credit facility.effect.
2021 Senior Notes
In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the “2021 Senior Notes” and the offering, the "2021“2021 Senior Notes Offering"Offering”). The 2021 Senior Notes bearbore an annual interest rate of 7.875%. The interest on the 2021 Senior Notes iswas payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees.
TheConcurrent with the 2026 Senior Notes Offering (as defined below), the Company commenced a cash tender offer to purchase any and all of its 2021 Senior Notes (the “Tender Offer”). On January 24, 2018, the Company received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 the Company made a cash payment of approximately $534.2 million, which includes principal of approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, the Company redeemed approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which included a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.
2024 Senior Notes
In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the “2024 Senior Notes” and the offering, the “2024 Senior Notes Offering”). The 2024 Senior Notes bore an annual interest rate of 7.375%. The interest on the 2024 Senior Notes was payable on May 15 and November 15 of each year which commenced on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting fees.
The Company’s 2024 Senior Notes were its senior unsecured obligations and ranked equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company’s 2024 Senior Notes were fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company’s current subsidiaries and by
certain future restricted subsidiaries that guarantees its indebtedness under a Prior Credit Facility (the “2024 Senior Notes Guarantors”). The 2024 Senior Notes were effectively subordinated to all of the Company’s secured indebtedness (including all borrowings and other obligations under its Prior Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future subsidiaries that did not guarantee the 2024 Senior Notes.
The 2024 Senior Notes also containcontained affirmative and negative covenants that, among other things, limitlimited the Company'sCompany’s and the Guarantors'2024 Senior Notes Guarantors’ ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its 2024 Senior Notes Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2021 Senior Notes (the “2021 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2021 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2021 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2021 Senior Notes may declare all outstanding 2021 Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the 2021 Senior Notes Indenture as of December 31, 2017.
Concurrent with the 2026 Notes Offering, the Company commenced a cash tender offer to purchase any and all of its 2021 Senior Notes. On January 24, 2018 the Company received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 the Company made a cash payment of approximately $534.2 million, which included principal of approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, the Company redeemed approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which includes a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.
2024 Senior Notes
In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the “2024 Senior Notes” and the offering, the “2024 Senior Notes Offering”). The 2024 Senior Notes bear an annual interest rate of 7.375%. The interest on the 2024 Senior Notes is payable on May 15 and November 15 of each year commencing on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting discounts and fees.
The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of its current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facility (the “2024 Senior Note Guarantors”). The 2024 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future subsidiaries that do not guarantee the 2024 Senior Notes.
The 2024 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2024 Senior Notes (the “2024 Senior Notes Indenture”) also containscontained customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2024 Senior Notes shallwould have become due and payable immediately without any declaration or other act of the trustee or the holders of the 2024 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes maycould declare all outstanding 2024 Senior Notes to be due and payable immediately.
The Company wasfiling of the Chapter 11 Cases resulted in compliance with all financial covenantsan event of default under and acceleration of the maturity of the Company’s 2024 Senior Notes.
On January 20, 2021, upon emergence from bankruptcy, the 2024 Senior Notes Indenture aswere cancelled. The holders of December 31, 2017.the 2024 Senior Notes received (i) their proportionate distribution of the New Common Stock and (ii) the right to participate in the Equity Rights Offering.
2026 Senior Notes
In January 2018, the Company closed a private offeringissued at par $750.0 million principal amount of its 20265.625% Senior Notes due February 1, 2026 (the “2026 Senior Notes” and together with the 2024 Senior Notes, the “Senior Notes” and the offering, the "2026offering of the 2026 Senior Notes, Offering"“2026 Senior Notes Offering”) that resulted in. The 2026 Senior Notes bore an annual interest rate of 5.625%. The interest on the 2026 Senior Notes was payable on February 1 and August 1 of each year commencing on August 1, 2018. The Company received net proceeds of approximately $737.9 million after deducting discounts and fees. The Company used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to fund the tender offer for its 2021 Senior Notes, $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder for general corporate purposes.
The Company'sCompany’s 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest onwere the Company's 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment will be made on August 1, 2018. The Company's 2026 Senior Notes will mature on February 1, 2026.
The Company's 2026 Senior Notes are the Company'sCompany’s senior unsecured obligations and rankranked equally in right of payment with all of the Company'sCompany’s other senior indebtedness and senior to any of the Company'sCompany’s subordinated indebtedness. The Company'sCompany’s 2026 Senior Notes arewere fully and unconditionally guaranteed on a senior unsecured basis by eachcertain of the Company'sCompany’s current subsidiaries and by certain future restricted subsidiaries that guarantee the Company'sCompany’s indebtedness under a credit facility.Prior Credit Facility (the “2026 Senior Notes Guarantors”). The 2026 Senior Notes arewere effectively subordinated to all of the Company'sCompany’s secured indebtedness (including all borrowings and other obligations under the Company's revolving credit facility)its Prior Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of anycertain of the Company'sCompany’s future restricted subsidiaries that do not guarantee the 2026 Senior Notes.
The 2026 Senior Notes also containcontained affirmative and negative covenants that, among other things, limitlimited the Company’s and the 2026 Senior Notes Guarantors’ ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its 2026 Senior Notes Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2026 Senior Notes (the “2026 Senior Notes Indenture”) also containscontained customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2026 Senior Notes shallwould have become due and payable immediately without any declaration or other act of the trustee or the holders of the 2026 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 20242026 Senior Notes maycould declare all outstanding 2026 Senior Notes to be due and payable immediately.
The filing of the Chapter 11 Cases resulted in an event of default under and acceleration of the maturity of the Company’s 2026 Senior Notes.
On May 29, 2014, Holdings entered into a five year, $430.0 million term loan facility with a syndicate of lenders (the “Second Lien Notes”). The Second Lien Notes would have matured on May 29, 2019. Holdings had drawnJanuary 20, 2021, upon emergence from bankruptcy, the full $430.0 million under the Second Lien Notes that bore an average interest rate of approximately 10.7%. The interest rates were fixed and interest was payable semi‑annually.
In July 2016, the Second Lien2026 Senior Notes were repaid and terminated in conjunction withcancelled. The holders of the 20212026 Senior Notes Offering. The Company usedreceived (i) their proportionate distribution of the proceeds fromNew Common Stock and (ii) the 2021 Senior Notes (as discussed below)right to repay the outstanding $430.0 million of principal and a $4.3 million prepayment penalty. The prepayment penalty was expensed during the year ended December 31, 2016participate in the consolidated statements of operations within the interest expense line item. Additionally, during the year ended December 31, 2016, the Company wrote off approximately $15.1 million of unamortized debt discount and debt issuance costs that were related to the Second Lien Notes. The write off of the unamortized debt discount and debt issuance costs were recorded in the consolidated statements of operations within the interest expense line item.
Debt Discount Costs on Second Lien Notes
The Company’s Second Lien Notes were issued with an original issue discount (OID) of $6.5 million. In July 2016, the Company repaid the Second Lien Notes in full and accelerated the remaining unamortized balance of $4.3 million. This expense was recorded in the consolidated statements of operations within the interest expense line item. As of December 31, 2017, there was no remaining balance on the OID.Equity Rights Offering.
Debt Issuance Costs
Debt issuance costs include origination, legal and other fees incurred in connection with the Company’s Prior Credit Facility and Senior Notes. As of December 31, 20172020 and 2016,2019, the Company had debt issuance costs, net of accumulated amortization, of $3.8$0.1 million and $2.2$2.9 million, respectively, related to its credit facilityPrior Credit Facility which has been reflected on the Company’s consolidated balance sheet within the line item other non‑currentnon-current assets. As a result of bankruptcy, the Company wrote-off $13.5 million in unamortized debt issuance costs on the Senior Notes to reorganization items, net in the consolidated statements of operations. As of December 31, 2017,2019, the Company had debt issuance costs net of accumulated amortization of $16.6$14.4 million related to its 2021 and 2024 Senior Notes (collectively, the "Senior Notes"), and as of December 31, 2016, the Company had debt issuance costs net of accumulated amortization of $11.9 million related to its 2021 Senior Notes, which hashave been reflected on the Company'sCompany’s consolidated balance sheetsheets within the line item Senior Notes, net of unamortized debt issuance costs. Upon the repayment of the Company’s Second Lien Notes, the Company accelerated the amortization of the remaining $10.8 million of unamortized debt issuance costs. This expense was recorded in the consolidated statements of operations within the interest expense line item. As of December 31, 2017 and 2016, there was no remaining balance on debt issuance costs associated with the Second Lien Notes. Debt issuance costs include origination, legal, engineering, and other fees incurred in connection with the Company’s credit facility and Senior Notes. For the yearsyear ended December 31, 2017, 2016,2020, 2019 and 2015,2018, the Company recorded amortization expense related to the debt issuance costs of $4.3$3.7 million, $14.4$5.5 million and $3.1$13.2 million, respectively.
Debt issuance costs of $1.7 million pertaining to the DIP Credit Facility were expensed to reorganization items, net during the year ended December 31, 2020.
Interest Incurred On Long‑Termon Long-Term Debt
As discussed in Note 2 — Basis of Presentation — Automatic Stay, during the proceedings of the Chapter 11 Cases, interest on the Senior Notes ceased being accrued and paid during 2020. However, interest was incurred, accrued and paid on the Prior Credit Facility due to the adequate protections obtained for this facility. Interest was incurred, accrued and paid on the DIP Credit Facility as it was obtained post-petition and approved by the Bankruptcy Court. For the years ended December 31, 2017, 20162020, 2019 and 2015,2018, the Company incurred interest expense on long‑term debt of $58.7$58.8 million, $50.5$91.5 million and $50.5$82.7 million, respectively, and the Company capitalized interest expense on debt of $11.1$5.3 million, $5.2$7.2 million and $5.3$8.2 million, respectively, for the years ended December 31, 2017, 20162020, 2019 and 2015, respectively,2018, which has been reflected in the Company’s consolidated financial statements. Also included in interest expense for the year ended December 31, 2016 is2018 was a prepayment penaltymake-whole premium of $4.3$35.6 million related to the Company’s repayment of its Second Lien2021 Senior Notes in July 2016. January and February 2018.
Senior Note Repurchase Program
In January 2019, the Company’s board of directors (the “Board”) authorized a program to repurchase up to $100.0 million of the Company’s Senior Notes (the “Senior Notes Repurchase Program”). The Company’s Senior Notes Repurchase Program was subject to restrictions under the Prior Credit Facility and did not obligate it to acquire any specific nominal amount of Senior Notes. During 2020, the Company did not repurchase any Senior Notes. As a result of the Chapter 11 Cases, the authorization to repurchase Senior Notes is no longer applicable. During 2019, the Company repurchased 2026 Senior Notes with a nominal value of $49.8 million for $39.3 million in connection with the Senior Notes Repurchase Program. Interest expense for the year ended December 31, 2019 contained a $10.5 million gain on debt repurchase related to the Company’s Senior Notes Repurchase Program. The Senior Note Repurchase Program had no impact to interest expense for the years ended December 31, 2020 and 2018.
Note 6—9—Commodity Derivative Instruments
The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production.
A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap. The Company has historically relied on commodity derivative contracts to mitigate its exposure to lower commodity prices.
The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.
To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, the Company has periodically entered into commodity derivative contracts with respect to certain of its oil and natural gas production through various transactions that limit the downside of future prices received. Future transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage the Company’s exposure to oil and natural gas price fluctuations.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with seven2 counterparties, allboth of whomwhich are lenders under our credit agreement.the Predecessor Credit Agreement and the DIP Credit Facility. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. The derivative contracts may be terminated by a non‑defaultingnon-defaulting party in the event of default by one1 of the parties to the agreement. There are no credit‑risk‑0 credit risk related contingent features or circumstances in which the features could be triggered in derivative instruments that are in a net liability position at the end of the reporting period.
Effect of Chapter 11 Cases
The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permitted the counterparties to such derivative instruments to terminate their outstanding hedges. Such termination events were not stayed under the Bankruptcy Code. During June 2020, certain of the lenders under the Predecessor Credit Agreement elected to terminate their International Swaps and Derivatives Association master agreements and outstanding hedges with the Company for aggregate settlement proceeds of $96.1 million. The proceeds from these terminations were applied to the outstanding borrowings under the Prior Credit Facility.
The Company’s open commodity derivative contracts as of December 31, 20172020 are summarized below:
| | | | | |
| 2021 |
NYMEX WTICrude Swaps: | |
| Notional volume (Bbl) | 2,629,700 | |
| Weighted average fixed price ($/Bbl) | $ | 50.40 | |
|
| | | | | | | |
| | 2018 | | 2019 |
NYMEX WTI Crude Swaps: | | | |
| Notional volume (Bbl) | 5,100,000 |
| | — |
|
| Weighted average fixed price ($/Bbl) | $ | 51.61 |
| | $ | — |
|
NYMEX WTI Crude Sold Calls: | |
| | |
| Notional volume (Bbl) | 8,290,000 |
| | 5,100,000 |
|
| Weighted average sold call price ($/Bbl) | $ | 56.18 |
| | $ | 55.93 |
|
NYMEX WTI Crude Sold Puts: | |
| | |
| Notional volume (Bbl) | 13,438,800 |
| | 5,100,000 |
|
| Weighted average sold put price ($/Bbl) | $ | 39.10 |
| | $ | 39.82 |
|
NYMEX WTI Crude Purchased Puts: | |
| | |
| Notional volume (Bbl) | 12,327,600 |
| | 5,100,000 |
|
| Weighted average purchased put price ($/Bbl) | $ | 44.81 |
| | $ | 49.69 |
|
NYMEX HH Natural Gas Swaps: | |
| | |
| Notional volume (MMBtu) | 40,800,000 |
| | — |
|
| Weighted average fixed price ($/MMBtu) | $ | 3.10 |
| | $ | — |
|
NYMEX HH Natural Gas Purchased Puts: | |
| | |
| Notional volume (MMBtu) | 2,400,000 |
| | — |
|
| Weighted average purchased put price ($/MMBtu) | $ | 3.00 |
| | $ | — |
|
NYMEX HH Natural Gas Sold Calls: | |
| | |
| Notional volume (MMBtu) | 2,400,000 |
| | — |
|
| Weighted average sold call price ($/MMBtu) | $ | 3.15 |
| | $ | — |
|
CIG Basis Gas Swaps: | |
| | |
| Notional volume (MMBtu) | 6,300,000 |
| | — |
|
| Weighted average fixed basis price ($/MMBtu) | $ | (0.31 | ) | | $ | — |
|
The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the consolidated balance sheets (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | As of December 31, 2020 |
| Location on Balance Sheet | | Gross Amounts of Recognized Assets and Liabilities | | Gross Amounts Offset in the Balance Sheet (1) | | Net Amounts of Assets and Liabilities Presented in the Balance Sheet | | Gross Amounts not Offset in the Balance Sheet (2) | | Net Amounts (3) |
| Current assets | | $ | 8,372 | | | $ | (1,401) | | | $ | 6,971 | | | $ | 0 | | | $ | 6,971 | |
| Non-current assets | | 0 | | | 0 | | | 0 | | | — | | | — | |
| Current liabilities | | (3,548) | | | 1,401 | | | (2,147) | | | 0 | | | (2,147) | |
| Non-current liabilities | | 0 | | | 0 | | | 0 | | | — | | | — | |
| | | | | | | | | | |
| | | As of December 31, 2019 |
| Location on Balance Sheet | | Gross Amounts of Recognized Assets and Liabilities | | Gross Amounts Offset in the Balance Sheet (1) | | Net Amounts of Assets and Liabilities Presented in the Balance Sheet | | Gross Amounts not Offset in the Balance Sheet (2) | | Net Amounts (3) |
| Current assets | | $ | 48,605 | | | $ | (31,051) | | | $ | 17,554 | | | $ | 0 | | | $ | 30,783 | |
| Non-current assets | | 38,034 | | | (24,805) | | | 13,229 | | | — | | | — | |
| Current liabilities | | (33,049) | | | 31,051 | | | (1,998) | | | 0 | | | (2,106) | |
| Non-current liabilities | | (24,913) | | | 24,805 | | | (108) | | | — | | | — | |
| | | | | | | | | | |
| (1) Agreements are in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. |
| (2) Netting for balance sheet presentation is performed by current and non-current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the consolidated balance sheets. There are no amounts of related financial collateral received or pledged. |
| (3) Net amounts are not split by current and non-current. All counterparties in a net asset position are shown in the current asset line item, and all counterparties in a net liability position are shown in the current liability line item. |
|
| | | | | | | | | | | | | | | | | | | | |
| | | As of December 31, 2017 |
| | | | | | | Net Amounts of | | | | |
| | | Gross Amounts | | | | Assets and | | | | |
| | | of Recognized | | Gross Amounts | | Liabilities | | Gross Amounts | | |
| | | Assets and | | Offset in the | | Presented in the | | not Offset in the | | Net |
| Location on Balance Sheet | | Liabilities | | Balance Sheet(1) | | Balance Sheet | | Balance Sheet(2) | | Amounts(3) |
| Current assets | | $ | 22,118 |
| | $ | (17,986 | ) | | $ | 4,132 |
| | $ | — |
| | $ | 4,132 |
|
| Non-current assets | | $ | 13,686 |
| | $ | (13,686 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
| Current liabilities | | $ | (85,414 | ) | | $ | 17,986 |
| | $ | (67,428 | ) | | $ | — |
| | $ | (84,702 | ) |
| Non-current liabilities | | $ | (30,960 | ) | | $ | 13,686 |
| | $ | (17,274 | ) | | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | As of December 31, 2016 |
| | | | | | | Net Amounts of | | | | |
| | | Gross Amounts | | | | Assets and | | | | |
| | | of Recognized | | Gross Amounts | | Liabilities | | Gross Amounts | | |
| | | Assets and | | Offset in the | | Presented in the | | not Offset in the | | Net |
| Location on Balance Sheet | | Liabilities | | Balance Sheet(1) | | Balance Sheet | | Balance Sheet(2) | | Amounts(3) |
| Current assets | | $ | 12,620 |
| | $ | (12,620 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
| Non-current assets | | $ | 14,993 |
| | $ | (14,993 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
| Current liabilities | | $ | (68,623 | ) | | $ | 12,620 |
| | $ | (56,003 | ) | | $ | — |
| | $ | (62,741 | ) |
| Non-current liabilities | | $ | (21,731 | ) | | $ | 14,993 |
| | $ | (6,738 | ) | | $ | — |
| | $ | — |
|
| |
(1) | Agreements are in place with all of the Company’s financial trading counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. |
| |
(2) | Netting for balance sheet presentation is performed by current and non‑current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the balance sheet. There are no amounts of related financial collateral received or pledged. |
| |
(3) | Net amounts are not split by current and non‑current. All counterparties in a net asset position are shown in the current asset line item and all counterparties in a net liability position are shown in the current liability line item. |
The table below sets forth the commodity derivatives gain (loss) for the years ended December 31, 2017, 20162020, 2019 and 20152018 (in thousands). Commodity derivatives gain (loss) are included underin the other income (expense). section of the consolidated statements of operations.
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Commodity derivatives gain (loss) | $ | 164,968 | | | $ | (37,107) | | | $ | (8,554) | |
|
| | | | | | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Commodity derivatives gain (loss) | $ | (36,332 | ) | | $ | (100,947 | ) | | $ | 79,932 |
|
Note 7—10—Asset Retirement Obligations
The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut‑inshut-in wells at the end of their productive lives in accordance with applicable local, state and federal laws, and applicable lease terms. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method. Asset retirement obligations are currently presented in the line item liabilities subject to compromise on the consolidated balance sheets.
The following table summarizes the activities of the Company’s asset retirement obligations for the periods indicated (in thousands):
| | | | | | | | | | | | | | |
| | | For the Year Ended |
| | December 31, |
| | | 2020 | | 2019 |
| Balance beginning of period | | $ | 95,908 | | | $ | 69,791 | |
| Liabilities incurred or acquired | | $ | 333 | | | $ | 978 | |
| Liabilities settled | | $ | (21,533) | | | $ | (29,305) | |
| Revisions in estimated cash flows (1) | | $ | 13,617 | | | $ | 49,050 | |
| Accretion expense | | $ | 6,444 | | | $ | 5,394 | |
| Balance end of period | | $ | 94,769 | | | $ | 95,908 | |
| | | | |
| (1) Revisions in estimated cash flows during the year ended December 31, 2020 and 2019 were primarily due to changes in estimates of costs to be incurred to plug and abandon wells and changes in estimated dates of abandonment. |
|
| | | | | | | |
| | For the Year Ended |
| | December 31, |
| | 2017 | | 2016 |
| Balance beginning of period | $ | 56,108 |
| | $ | 44,367 |
|
| Liabilities incurred or acquired | 9,802 |
| | 8,945 |
|
| Liabilities settled | (4,169 | ) | | (1,155 | ) |
| Revisions in estimated cash flows | 2,630 |
| | (1,695 | ) |
| Accretion expense | 5,169 |
| | 5,646 |
|
| Balance end of period | $ | 69,540 |
| | $ | 56,108 |
|
Note 8—11—Fair Value Measurements
ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
•Level 1: Quoted prices are available in active markets for identical assets or liabilities;
•Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;
•Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between levels during any periods presented below.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 20172020 and December 31, 20162019 by level within the fair value hierarchy (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurement at |
| | December 31, 2020 |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| Financial Assets: | | | | | | | |
| Commodity derivative assets | $ | 0 | | | $ | 6,971 | | | $ | 0 | | | $ | 6,971 | |
| Financial Liabilities: | | | | | | | |
| Commodity derivative liabilities | $ | 0 | | | $ | 2,147 | | | $ | 0 | | | $ | 2,147 | |
| | | | Fair Value Measurements at | | Fair Value Measurement at |
| | December 31, 2017 Using | | December 31, 2019 |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Financial Assets: | | | | | | | | Financial Assets: | | | | | | | |
| Commodity derivative assets | $ | — |
| | $ | 4,132 |
| | $ | — |
| | $ | 4,132 |
| Commodity derivative assets | $ | 0 | | | $ | 30,783 | | | $ | 0 | | | $ | 30,783 | |
| Financial Liabilities: | | | | | | | | Financial Liabilities: | | | | | | | |
| Commodity derivative liabilities | $ | — |
| | $ | 84,702 |
| | $ | — |
| | $ | 84,702 |
| Commodity derivative liabilities | $ | 0 | | | $ | 2,106 | | | $ | 0 | | | $ | 2,106 | |
|
| | | | | | | | | | | | | | | |
| | Fair Value Measurements at |
| | December 31, 2016 Using |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| Financial Assets: | | | | | | | |
| Commodity derivative assets | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Financial Liabilities: | | | | | | | |
| Commodity derivative liabilities | $ | — |
| | $ | 62,741 |
| | $ | — |
| | $ | 62,741 |
|
The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the tabletables above:
Commodity Derivative Instruments
The Company determines its estimate of the fair value of derivative instruments using a market based approach that takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. Derivative instruments utilized by the Company consist of swaps, put options, and call options. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the
instruments themselves are traded with third‑partythird-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long‑termlong-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short‑termshort-term maturities. The carrying amount of the Company’s credit facilityPrior Credit Facility and DIP Credit Facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair valuevalues of the 20212024 Senior Notes and 20242026 Senior Notes waswere derived from available market data. As such, the Company has classified the 20212024 Senior Notes and 20242026 Senior Notes as Level 2. Please refer to Note 58 — Long‑TermLong-Term Debt for further information. The Company’s policy is to recognize transfers between levels at the end of the period. This disclosureThe table below (in thousands) does not impact the Company’s financial position, results of operations or cash flows.
|
| | | | | | | | | | | | | | | |
| | At December 31, 2017 | | At December 31, 2016 |
| | Carrying | | | | Carrying | | |
| | Amount | | Fair Value | | Amount | | Fair Value |
| Credit facility | $ | 90,000 |
| | $ | 90,000 |
| | $ | — |
| | $ | — |
|
2021 Senior Notes(1) | $ | 540,382 |
| | $ | 583,000 |
| | $ | 538,141 |
| | $ | 588,500 |
|
2024 Senior Notes(2) | $ | 392,979 |
| | $ | 427,000 |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | At December 31, 2020 | | At December 31, 2019 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Prior Credit Facility | $ | 453,747 | | | $ | 453,747 | | | $ | 470,000 | | | $ | 470,000 | |
| DIP Credit Facility | 106,727 | | | 106,727 | | | — | | | — | |
| 2024 Senior Notes (1) | 400,000 | | | 70,732 | | | 394,824 | | | 250,000 | |
| 2026 Senior Notes (2) | 700,189 | | | 123,408 | | | 690,953 | | | 420,113 | |
| |
(1) | The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $9.6 million and $11.9 million as of December 31, 2017 and 2016, respectively. |
| |
(2) | The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $7.0 million as of December 31, 2017. |
(1)The carrying amount of the 2024 Senior Notes includes 0 unamortized debt issuance costs as of December 31, 2020 and $5.2 million as of December 31, 2019.
(2)The carrying amount of the 2026 Senior Notes includes 0 unamortized debt issuance costs as of December 31, 2020 and $9.2 million as of December 31, 2019.
Non‑RecurringNon-Recurring Fair Value Measurements
The Company applies the provisions of the fair value measurement standard on a non‑recurringnon-recurring basis to its non‑financialnon-financial assets and liabilities, including proved property and goodwill.property. These assets and liabilities are not measured at fair value on a recurring basis but are subject to fair value adjustments when facts areand circumstances arise that indicate a need for measurement.remeasurement.
The Company utilizes fair value on a non‑recurringnon-recurring basis to reviewvalue its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverabilityresults of the Company’s impairment evaluations indicate that the undiscounted future cash flows of an asset group do not exceed its carrying value of such property.value. The Company uses an income approach analysis based on the net discounted future cash‑cash flows of producingproved property. The future cash‑flows are based on Management’s estimates forCompany calculates the future. Unobservable inputs included future estimatesestimated fair values of its proved property oil and gas production, asassets using a discounted future cash flow model. Significant inputs associated with the case may be, from the Company’s reserve reports, commodity prices based on the sales contract terms or forward price curves,calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) future operating and development costs, (iii) future commodity prices, and a discount rate based on(iv) a market-based weighted average cost of capital (all of whichcapital. The Company utilized the NYMEX strip pricing, adjusted for differentials, to value the reserves. These are classified as Level 3 inputs withinfair value assumptions. At December 31, 2020, the Company’s estimate of commodity prices for purposes of determining discounted future cash flows ranged from a 2021 price of $48.29 per barrel of oil decreasing to a 2022 price of $46.76 per barrel of oil and decreasing further to a 2025 price of $44.84 per barrel of oil. Natural gas prices ranged from a 2021 price of $2.65 per Mcf decreasing to a 2025 price of $2.52 per Mcf. NGL prices ranged from a 2021 price
of $13.45 per barrel decreasing to a 2025 price of $12.49 per barrel. These prices were then adjusted for location and quality differentials. The expected future net cash flows were discounted using a rate of 13.5 percent.
For the year ended December 31, 2020, the Company recognized $194.3 million in impairment expense on its oil and gas properties related to assets in its Core DJ Basin field as the fair value hierarchy). Nodid not exceed the Company’s carrying amount attributable primarily to certain downward adjustments to the Company’s reserves due to expirations due to the SEC five year drilling rule caused by the change in business strategy to focus on cash flow rather than maximizing production and reserves growth. Additionally, downward revisions were due to altering the development plan to increase the spacing between wellbores, thus drilling fewer wells, as well as negative performance revisions. For the year ended December 31, 2019, the Company recognized $1.3 billion in impairment expense on its proved oil and gas properties related to assets in its Core DJ Basin field as the fair value did not exceed the Company’s carrying amount attributable primarily to certain downward adjustments to the Company’s reserves due to expirations due to the SEC five year drilling rule caused by the change in business strategy to focus on cash flow rather than maximizing production and reserves growth. NaN impairment expense was recognized for the year ended December 31, 20172018 on proved oil and gas properties. For the years ended December 31, 2016 and 2015, the Company recognized $22.5 million and $9.5 million in impairment expense on proved oil and gas properties. The impairment expense for the years ended December 31, 2016 and 2015 is related to impairment of the assets in the Company’s northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in the Company’s northern fieldCore DJ Basin field. For the years ended December 31, 2020, 2019 and it was determined that2018, the Company recognized $3.6 million, $14.5 million and $16.2 million, respectively in impairment expense on its proved oil and gas properties had no remainingrelated to assets in its northern field as the fair value. Therefore,value did not exceed the full net book value of theseCompany’s carrying amount attributable primarily to certain downward adjustments to the Company’s economically recoverable proved oil and natural gas properties were impaired at June 30, 2016 and 2015, respectively. Additionally, during 2015, the Company sold proved oil and gas properties for proceeds of $4.7 million. In connection with the sale, the Company determined that assets’ net book value exceeded the fair value of such properties by $2.7 million. The Company recognized that amount as an impairment expense for the year ended December 31, 2015.reserves.
The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test iswas performed at the reporting unit level, which representsrepresented the Company’s oil and gas operations in its coreCore DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the
estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed ana quantitative assessment as of September 30, 2017,2018, which concluded the fair value of the reporting unit was greater than its carrying amount.
The Company identified triggering events as of December 31, 2018, due to the decrease in commodity pricing and the quoted market price of the Company’s common shares compared to September 30, 2018. As such, the Company performed a qualitativequantitative assessment as of December 31, 20172018, utilizing an income approach based on estimates of the expected discounted future cash flows of the reporting unit’s oil and 2016,gas properties, which concluded the fair value of the reporting unit was more-likely-than-notnot greater than its carrying amount. As a result, the Company recorded goodwill impairment of $54.2 million, the entirety of the balance, for the year ended December 31, 2018. As such, no test for goodwill impairment was necessary for the years ended December 31, 2020 and 2019.
The Company’s other non‑recurringnon-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 4 — Acquisitions.combinations. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted‑discounted cash flow approach using levelLevel 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk‑adjustedrisk-adjusted oil and gas reserves, commodity prices, development costs and operating costs, based on market participant assumptions. The fair value of assets or liabilities associated with purchase price allocations is on a non‑recurringnon-recurring basis and is not measured in periods after initial recognition.
Note 9—12—Equity
Private Placement of Common StockEmergence from Chapter 11 Bankruptcy
On December 15, 2016,Emergence Date, the Company, completedpursuant to the issuance of 25.0 million shares of common stock, at a price of $18.25 per share, in connection with the Private Placement (the “Private Placement”). The Private Placement resulted in approximately $457.0 million of gross proceeds and approximately $441.9 million of net proceeds, after deducting placement agent commissions and offering expenses. Proceeds from the Private Placement were to be used for general corporate purposes, including to fund the Company’s 2017 capital expenditures.
Initial Public Offering
On October 17, 2016, the Company completed its initial public offering, issuing 38.3 million shares of common stock, par value $0.01 per share (“common stock”), which include the full exercise of the underwriters’ over-allotment option of 5.0 million shares at a price of $19.00 per share. The net proceeds of the offering were $681.0 million, after deducting underwriting discounts and commissions and offering expenses, of approximately $47.3 million. The proceeds from the Offering were used to (i) redeem in full the Series A Preferred Units for $90.0 million and (ii) to repay borrowings under the Company’s revolving credit facility for $291.6 million. The remaining net proceeds were to be used for general corporate purposes, including to fund 2017 capital expenditures. The material terms of the Equity Rights Offering, are describedissued New Common Stock in the Successor Company to various stakeholders as discussed in Note 1 — Business and Organization—Emergence from Chapter 11 Bankruptcy.
Warrant Agreements
On the Emergence Date, pursuant to the Plan, the Company entered into a warrant agreement with American Stock Transfer & Trust Company, LLC (“AST”) which provides for the Company’s final prospectus, dated October 11, 2016issuance of up to an aggregate of 2,909,686 Tranche A Warrants (the “Tranche A Warrants”) to purchase New Common Stock to former holders of the Predecessor Common Stock and filedPredecessor Preferred Stock. The Company also entered into a warrant agreement with AST which provides for the Company’s issuance of up to an aggregate of 1,454,863 Tranche B Warrants (the “Tranche B Warrants” and,
together with the SEC pursuantTranche A Warrants, the “New Warrants”) to Rule 424(b)(4)purchase New Common Stock to former holders of the Securities ActPredecessor Common Stock and Predecessor Preferred Stock. As of 1933, as amended, on October 13, 2016.
Series A Preferred Units
On October 3, 2016,January 31, 2021, the Company issued $75.0had approximately 2.9 million in Series A Preferred Units (the “Series A Preferred Units”) to fund a portion of the purchase price for the October 2016 Acquisition. The Series A Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears. All holders of Series A Preferred Units were also members of Holdings. The Company used $90.0and 1.5 million of the net proceeds from its IPO to redeem the SeriesTranche A Preferred Units in full on October 17, 2016, including a premium of $15.0 million which is recorded within additional paid in capital in the consolidated statement of changes in members’Warrants and stockholders’ equity. For further discussion on the October 2016 Acquisition, please refer to Note 4 — Acquisitions.Tranche B Warrants issued and outstanding, respectively.
Series A Preferred Stock and
The holders of our Series B Preferred Units
On October 3, 2016, the Company issued $185.3 million in convertible preferred securities ("Series B Preferred Units") to fund a portion of the purchase price for the October 2016 Acquisition. The Series B Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears, and the Company had the ability to pay up to 50% of the quarterly dividend in kind. For the year ended December 31, 2016, the Company paid $0.7 million of dividends associated with the Series B Preferred Units. The Company did not make any payments in kind on the Series B Preferred Units from the date of issuance of the Series B Preferred Units through the Offering. The Series B Preferred Units converted in connection with the closing of the IPO into 185,280 shares of Series A Convertible Preferred Stock (the "Series“Series A Preferred Stock"Holders”) that arewere entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and the Company hashad the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends arewere partially paid in cash). ForThe Company had paid the year ended December 31, 2017,quarterly dividends in kind from the fourth quarter of 2019 until the filing of the Chapter 11 Cases. Because certain provisions within the RSA and the DIP Credit Agreement restricted the Company’s ability to declare a dividend, the Company accrued $2.7 million of dividends associated with the Series A Preferred Stock, or $14.69 per share, which were paid in January 2018. The Company didhas not makemade any dividend payments in kind on the Series A Preferred Stock fromsince the datecommencement of the Offering through December 31, 2017. Beginning on or after the later of (a) 90 days after the closing of the Offering and (b) the earlier of 120 days after the closing of the Offering and the expiration
of the lock-up period contained in the underwriting agreement entered into in connection with the Offering ("Lock-Up Period End Date"), theChapter 11 Cases. The Series A Preferred Stock will bewas convertible into shares of the Company'sour common stock at the election of the holders of the Series A Preferred Stock ("Series A Preferred Holders")Holders at a conversion ratio per share of Series A Preferred Stock of 61.9195. Beginning on or afterUntil the Lock-Up Period End Date until the three yearthree-year anniversary of the closing of the Offering,Company’s initial public offering (the “IPO,”), the Company maycould elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of the Company’sour common stock tradeshad traded at or above a certain premium to the Company’sour initial offering price, such premium to decrease with time. On October 15, 2019, the three year anniversary had passed for the Series A Preferred Stock to convert into our common stock. Prior to the commencement of the Chapter 11 Cases, the Company could have redeemed the Series A Preferred Stock for the liquidation preference, which was $198.7 million on June 14, 2020. In certain situations, including a change of control, the Series A Preferred Stock may becould have been redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock maturewould have matured on October 15, 2021, at which time they areit would have been mandatorily redeemable for cash at the liquidation preference.preference to the extent there were legally available funds to do so.
Note 10—Income Taxes
On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted making significant changesEmergence Date, pursuant to the Internal Revenue Code. The Company has calculatedPlan, each share of Series A Preferred Stock was canceled, released, and extinguished, and is of no further force or effect, and each holder of Series A Preferred Stock received, in full and final satisfaction, compromise, settlement, release, and discharge of, and in exchange for such Series A Preferred Stock, its best estimatepro rata share of (a) 1.5% of the impactNew Common Stock, subject to certain dilution; (b) the right to purchase 1.5% of the TCJANew Common Stock in its year end income tax provision in accordance with its understandingthe backstopped equity offering to be issued pursuant to the terms of the TCJA and guidance available asEquity Rights Offering; (c) 50.0% of the date of this filing. ManyTranche A Warrants, and (d) 50.0% of the provisionsTranche B Warrants to acquire an aggregate of 15.0% of the New Common Stock.
Elevation Preferred Units
In July 2018 and July 2019, respectively, Elevation sold 150,000 and 100,000 of Elevation Preferred Units at a price of $990 per unit to a third party (the “Purchaser”). The aggregate liquidation preference when the units were sold was $150.0 million and $100.0 million, respectively. These Preferred Units represent the noncontrolling interest presented on the consolidated balance sheets, consolidated statements of operations and consolidated statements of changes in the TCJA have an effective datestockholders’ equity (deficit) and noncontrolling interest for years beginning afterperiods ended on or prior to December 31, 2017, including the lowering of the U.S. corporate rate from 35 percent to 21 percent. However, as a result of the enactment date of December 22, 2017, the Company is required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. The Company provisionally recorded an income tax benefit in the amount of $23.4 million related to the remeasurement of the net deferred tax liability. The Company is currently evaluating other potential impacts of the TCJA.
The SEC staff has issued Staff Accounting Bulletin No. 118, which allows registrants to record provisional amounts during a one year "measurement period" similar to that used when accounting for business combinations. Impacts of this TCJA are expected to be recorded at the time a reasonable estimate for all or a portion of the effects can be made, and provisional amounts can be recognized and adjusted as information becomes available, prepared or analyzed. The Company has made a reasonable estimate and recorded the provisional deferred tax liability regarding the 100% cost recovery of qualified property acquired and placed in service after September 27, 2017 in the amount of $13.0 million. Also, the Company has made a reasonable estimate and recorded a portion of the deferred tax asset of $13.9 million related to stock-based compensation as provisional associated with covered employees. We believe these compensation plans for covered employees continue to qualify as deductible and would be grandfathered under the IRC Sec. 162(m) as of December 31, 2017.
The tax consequences of items taking effect after December 31, 2017 will be analyzed by the Company during 2018, some of the items the Company has identified that will have an impact on the Company are; i) deductibility of future compensation and awards for covered employees, ii) deductibility of meals and entertainment, iii) interest expense deductions, iv) the repeal of like-kind exchanges for non-real property, v) the repeal of the corporate alternative minimum tax and vi) the limitation of the use of NOLs to 80 percent of taxable income. The Company will make a good faith effort to analyze and complete the accounting under ASC Topic 740 of these items prior to the end of the measurement period
Holdings, the Company’s accounting predecessor, was a limited liability company that was not subject to U.S. federal income tax.2019. As part of the Corporate Reorganization,July 2018 transaction, the membersCompany committed to Elevation that it would drill at least 297 qualifying wells in the acreage dedicated to Elevation by December 31, 2023, subject to reductions if Elevation does not invest the full amount of Holdings exchangedcapital as initially anticipated. Pursuant to the Fourth Amendment to the Elevation Gathering Agreements between Elevation and Extraction, this drilling commitment would be eliminated, if and only if all of their member unitsElevation Preferred Units have been redeemed in full or are otherwise no longer outstanding. Please see Note 16 — Commitments and Contingencies — Elevation Gathering Agreements for shares of the Company’s common stock. For additional discussionfurther details on the Corporate Reorganization, see settlement to reduce this drilling commitment.
Upon deconsolidation of Elevation Midstream, LLC as discussed in Note 1 — Business and Organization.Organization — Deconsolidation of Elevation Midstream, LLC, the $270.5 million Elevation preferred unit balance in the noncontrolling interest line item of the consolidated balance sheets as of March 31, 2020 was removed. The amount comprises the line item effects of deconsolidation of Elevation Midstream, LLC on the consolidated statements of changes in stockholders’ equity (deficit) and noncontrolling interest as of March 31, 2020.
During the twenty-eight months following the July 3, 2018 Preferred Unit closing date, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $250.0 million commitment. For the year ended December 31, 2020, due to the deconsolidation of Elevation during the first quarter of 2020, the Company’s consolidated statements excluded all commitment fees paid-in-kind from the Preferred Unit commitment fees and dividends paid-in-kind line item in the consolidated statements of changes in stockholders’ equity (deficit) and noncontrolling interest. For the years ended December 31, 2020 and 2019, respectively, Elevation recognized $0.6 million and $3.1 million of commitment fees paid-in-kind.
The Elevation Preferred Units entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. The Dividend is currently payable solely in cash. For the year ended December 31, 2020, due to the deconsolidation of Elevation during the first quarter of 2020, the Company’s consolidated statements excluded all dividends paid-in-kind from the Preferred Unit commitment fees and dividends paid-in-kind line item in the consolidated statements of changes in stockholders’ equity (deficit) and noncontrolling interest. For the years ended December 31, 2020 and 2019, respectively, Elevation recognized $5.5 million and $16.9 million of dividends paid-in-kind.
Elevation Common Units
In May 2020, Elevation’s board of managers issued 1,530,000,000 common units at a price of $0.01 per unit to certain of Elevation’s members other than Extraction through the Capital Raise. The Capital Raise caused Extraction’s ownership of Elevation to be diluted to less than 0.01%. As a result of the Corporate Reorganization,Capital Raise, beginning in May 2020 Extraction began accounting for Elevation under the cost method of accounting. In December 2020, the Company identifiedreached a settlement with Elevation, which was approved by the Bankruptcy Court and established the deferred tax assets and liabilities for differences between the book and tax basis of Holdings. The Company recorded a net deferred tax liability of approximately $135.3 million. As this Corporate Reorganization is being accounted for as a transaction under common control the offsetpart of the net deferred tax liabilitysettlement the Company relinquished all of its remaining ownership in Elevation.
Stock Repurchase Program
In November 2018, the Company announced that the Board had authorized a program to repurchase up to $100.0 million of the Company’s common stock (“Stock Repurchase Program”). On April 1, 2019, the Company announced the Board had authorized an extension and increase to the ongoing Stock Repurchase Program bringing the total amount authorized to $163.2 million (“Extended Stock Repurchase Program”). The Stock Repurchase Program and the Extended Stock Repurchase Program were both completed during 2019, bringing the total amount of common stock repurchased to 38.2 million shares for $163.2 million and a weighted average share price of $4.27. For the years ended December 31, 2019 and 2018, the Company repurchased approximately 34.1 million and 4.1 million shares of its common stock for $137.0 million and $26.2 million, respectively. No common stock was recorded to additional paid-in capital within the consolidated balance sheet.repurchased during 2020.
Note 13—Income Taxes
The components of the income tax expense (benefit) were as follows (in thousands):
| | | | For the Year Ended | | For the Year Ended |
| | December 31, | | December 31, |
| | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| Current: | |
| | | Current: | | | | | |
| Federal | $ | — |
| | $ | — |
| Federal | $ | 0 | | | $ | 0 | | | $ | 0 | |
| State, net of federal benefit | — |
| | — |
| State, net of federal benefit | 0 | | | 0 | | | 0 | |
| Total current income tax benefit | $ | — |
| | $ | — |
| |
| Total current income tax expense (benefit) | | Total current income tax expense (benefit) | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | |
| Deferred: | | | | Deferred: | | | |
| Federal | $ | (61,719 | ) | | $ | (26,962 | ) | Federal | $ | 0 | | | $ | (93,245) | | | $ | 56,943 | |
| State, net of federal benefit | (1,981 | ) | | (2,318 | ) | |
| Total deferred income tax benefit | $ | (63,700 | ) | | $ | (29,280 | ) | |
| State, net of federal expense (benefit) | | State, net of federal expense (benefit) | 0 | | | (15,931) | | | 9,907 | |
| Total deferred income tax expense (benefit) | | Total deferred income tax expense (benefit) | $ | 0 | | | $ | (109,176) | | | $ | 66,850 | |
| | | | |
| | | | |
| Income tax benefit | $ | (63,700 | ) | | $ | (29,280 | ) | |
| Income tax expense (benefit) | | Income tax expense (benefit) | $ | 0 | | | $ | (109,176) | | | $ | 66,850 | |
The following table reconciles the
Total income tax expense (benefit) withdiffered from the amounts computed by applying the U.S. federal income tax expense atrate to earnings (loss) before income taxes as a result of the federal statutory ratefollowing (in thousands):
| | | | | | | | For the Year Ended |
| | For the Year Ended | | December 31, |
| | December 31, | | 2020 | | 2019 | | 2018 |
| | 2017 | | 2016 | |
| Loss before income taxes | (108,108 | ) | | (485,281 | ) | |
| Net income (loss) before income taxes | | Net income (loss) before income taxes | $ | (1,267,534) | | | $ | (1,476,596) | | | $ | 188,705 | |
| Federal income taxes at statutory rate | (37,838 | ) | | (169,849 | ) | Federal income taxes at statutory rate | (266,182) | | | (310,085) | | | 39,628 | |
| Net loss prior to Corporate Reorganization | — |
| | 80,463 |
| |
| State income taxes, net of federal benefit | (3,118 | ) | | (2,318 | ) | State income taxes, net of federal benefit | (41,582) | | | (52,723) | | | 9,907 | |
| Impact of goodwill impairment | | Impact of goodwill impairment | 0 | | | 0 | | | 11,386 | |
| Bankruptcy costs | | Bankruptcy costs | 18,717 | | | 0 | | | 0 | |
| Deconsolidation of Elevation Midstream LLC | | Deconsolidation of Elevation Midstream LLC | 2,448 | | | 0 | | | 0 | |
| Partnership income excluded | | Partnership income excluded | 0 | | | (3,558) | | | 0 | |
| Nondeductible stock-based compensation | 2,264 |
| | 62,284 |
| Nondeductible stock-based compensation | 3,216 | | | 9,436 | | | 5,088 | |
| Enactment of the Tax Cuts and Jobs Act | (23,412 | ) | | — |
| |
| Other | (1,596 | ) | | 140 |
| Other | 2,568 | | | 1,626 | | | 841 | |
| Valuation allowance | | Valuation allowance | 280,815 | | | 246,128 | | | 0 | |
| Income tax expense (benefit) | (63,700 | ) | | (29,280 | ) | Income tax expense (benefit) | 0 | | | (109,176) | | | 66,850 | |
| Net loss | $ | (44,408 | ) | | $ | (456,001 | ) | |
| Net income (loss) | | Net income (loss) | $ | (1,267,534) | | | $ | (1,367,420) | | | $ | 121,855 | |
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows (in thousands):
| | | | | | | | | | | |
| As of December 31, |
| 2020 | | 2019 |
| Deferred Tax Assets: | | | |
| Net operating loss carryforward | $ | 328,654 | | | $ | 266,446 | |
| Stock-based compensation | 14,217 | | | 17,138 | |
| Intangible drilling costs - Section 59(e) | 79,755 | | | 98,631 | |
| Property taxes | 7,142 | | | 16,812 | |
| Reorganization items | 144,450 | | | 0 | |
| Other | 20,123 | | | 0 | |
| Total deferred tax assets | $ | 594,341 | | | $ | 399,027 | |
| Deferred Tax Liabilities: | | | |
| Excess basis of oil and gas properties | (52,199) | | | (134,484) | |
| Commodity derivatives | (15,199) | | | (7,071) | |
| Other | 0 | | | (11,344) | |
| Total deferred tax liabilities | (67,398) | | | (152,899) | |
| Less: Valuation allowance | (526,943) | | | (246,128) | |
| Deferred Taxes, net | $ | 0 | | | $ | 0 | |
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| Deferred Tax Assets: | |
| | |
| Net operating loss carryforward | $ | 205,806 |
| | $ | 35,719 |
|
| Commodity derivatives | 19,984 |
| | 24,068 |
|
| Stock-based compensation | 13,853 |
| | 2,824 |
|
| Other | 17,053 |
| | 14,309 |
|
| Total deferred tax assets | 256,696 |
| | 76,920 |
|
| Deferred Tax Liabilities: | |
| | |
|
| Excess basis of oil and gas properties | (299,022 | ) | | (182,946 | ) |
| Total deferred tax liabilities | (299,022 | ) | | (182,946 | ) |
| Deferred Tax Liability, net | $ | (42,326 | ) | | $ | (106,026 | ) |
Management considers whether some portion or all of the deferred tax assets will be realized based on a more likely than not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable
income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. The Company has net operating lossNOL carryforwards (NOLs) for U.S. income tax purposes that have been generated from the Company'sCompany’s operations through December 31, 2020 of approximately $834.7 million. Due to the Act, these NOLs will not expire$1.3 billion, of which $833.6 million was generated before January 1, 2018 and are not subject to the 80 percent limitation of taxable income arisingincome. Such NOLs will expire beginning in future2036. As of December 31, 2020, the Company had $324.3 million of intangible drilling costs that were capitalized under Code Section 59(e). We believe it is more likely than not that the benefit from NOL carryforwards and other tax years.attributes will not be fully realized. In recognition of this risk, we have provided a valuation allowance on the deferred tax assets.
The utilization of such NOL carryforwards may be limited upon the occurrence of certain ownership changes as stipulated in Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"“Code”). As of December 31, 2017,2020, the Company determined that the statutory provision of Section 382 will not limit the Company’s ability to realize future tax benefits. As of December 31, 2017, the Company believes it will be able to generate sufficient future taxable income within the carryforward period and accordingly, believes that it is more likely than not that its deferred income tax assets will be fully realized. The Company files income tax returns in the U.S. federal jurisdiction and in Colorado. The statute of limitations related to the 20162017, 2018 and 20172019 tax returns areis open through 20202021, 2022 and 2021 respectively,2023, respectively; however, the ability for the tax authority to adjust the NOL will continue until three years after the NOL is utilized.
As of December 31, 2017,2020, the Company believes that it has no0 liability for uncertain tax positions. If the Company were to determine there wereare any uncertain tax positions, the Company would recognize the liability and related interest and
penalties within income tax expense. As of December 31, 2017,2020, the Company had no0 provision for interest or penalties related to uncertain tax positions.
Effect of Chapter 11 Cases and Emergence from Chapter 11 Cases
On July 13, 2020 the Bankruptcy Court entered a final order approving certain procedures (including notice requirements) that certain shareholders and potential shareholders were required to comply with during the pendency of the Chapter 11 Cases regarding transfers of, or declarations of worthlessness with respect to, the Company’s Predecessor Common Stock and Predecessor Preferred Stock, as well as certain obligations with respect to notifying the Company with respect to current share ownership, each of which were intended to preserve the Company’s ability to use its NOLs to offset possible future U.S. taxable income by reducing the likelihood of an ownership change under Section 382 of the Code during the pendency of the Chapter 11 Cases.
The consummation of the Plan on the Emergence Date resulted in an “ownership change” of the Company under Section 382 of the Code. Absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its pre-ownership change net operating losses that may be utilized to offset future taxable income generally will be subject to an annual limitation equal to the value of its stock immediately prior to the ownership change multiplied by the long-term tax exempt rate, plus an additional amount calculated based on certain “built in gains” in its assets that may be deemed to be realized within a 5-year period following any ownership change. This limitation, in the case of the ownership change that occurred as a result of the consummation of the Plan, will be subject to additional rules under Sections 382(l)(5) or (l)(6) of the Code, depending upon whether we are eligible for the application of Section 382(l)(5) of the Code and, if so eligible, whether we affirmatively elect not to apply Section 382(l)(5) of the Code. As a result of such limitation, the Company’s ability to utilize any NOLs or other tax attributes that are not eliminated as a result of cancellation of indebtedness income arising from the consummation of the Plan may be materially limited in the future.
The CARES Act provides relief to corporate taxpayers by permitting a five year carryback of 2018-2020 NOLs, removing the 80% limitation on the carryback of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020 as well as allowing 2019 adjusted taxable income to be utilized for 2020 limitation purposes, and accelerating refunds for minimum tax credit carryforwards, along with a few other provisions.
Note 11—Unit and 14—Stock-Based Compensation
Extraction2021 Long Term Incentive Plan
On January 20, 2021, as part of the emergence from bankruptcy, the Board adopted the 2021 Long Term Incentive Plan (the “2021 LTIP”) with a share reserve equal to 3,038,657 shares of New Common Stock. The 2021 LTIP provides for the grant of restricted stock units, restricted stock awards, stock options, stock appreciation rights, performance awards and cash awards to the Company’s employees and non-employee board directors. At emergence the Company granted awards under the 2021 LTIP to its directors, officers and employees, including restricted stock units and performance stock units.
2016 Long Term Incentive Plan
In October 2016, the Company’s Board of Directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (the “2016 Plan” or “LTIP”(“2016 LTIP”), pursuant to which employees, consultants, and directors of the Company and its affiliates performing services for the Company arewere eligible to receive awards. The 2016 Plan providesLTIP provided for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards, substitute awards, annual incentive awards, and performance awards intended to align the interests of participants with those of stockholders. In accordance withMay 2019, the termsCompany’s stockholders approved the amendment and restatement of the LTIP, 20.22016 LTIP. The amended and restated 2016 Long Term Incentive Plan provided a total reserve of 32.2 million shares of common stock have been reservedPredecessor Common Stock for issuance pursuant to awards under the 2016 LTIP. Extraction has granted awards under the 2016 LTIP to certain directors, officers and employees, including stock options, restricted stock units, and performance stock awards, performance stock units, performance cash awards and cash awards. Effective January 20, 2021, as part of the emergence from bankruptcy, the 2016 LTIP was terminated and no longer in effect and all outstanding awards were cancelled.
Restricted Stock Units (“RSUs”)
Restricted stock units granted under the 2016 LTIP (“RSUs”) vestgenerally vested over either (i) a one-yearone or three-year service period, with 100% of the units vesting at the end of the service period,in year one or (ii) a three-year service period with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of Extraction’s common stock onpursuant to the dateterms of issuance.the 2016 LTIP. The Company assumed a forfeiture rate of zero0 as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09.
The Company recorded $31.8$4.7 million, $23.8 million and $5.5$27.9 million of stock-based compensation costs related to RSUs for the years ended December 31, 20172020, 2019 and 2016,2018, respectively. No stock-based compensationThese costs related to RSUs were recorded forincluded in the year ended December 31, 2015.consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2017,2020, there was $45.7$2.9 million of total unrecognized compensation cost related to the unvested RSUs granted to certain directors, officers and employees that is expected to be recognized over a weighted average period of 2.0 years.1.0 year.
The following table summarizes the RSU activity from January 1, 20162018 through December 31, 20172020 and provides information for RSUs outstanding at the dates indicated.
| | | | | | | | | | | |
| | | | Weighted Average |
| | Number of | | Grant Date |
| | Shares | | Fair Value |
| Non-vested RSUs at January 1, 2018 | 2,906,473 | | | $ | 19.51 | |
| Granted | 1,226,768 | | | $ | 12.53 | |
| Forfeited | (95,725) | | | $ | 14.94 | |
| Vested | (935,181) | | | $ | 19.44 | |
| Non-vested RSUs at December 31, 2018 | 3,102,335 | | | $ | 16.91 | |
| Granted | 1,905,918 | | | $ | 4.75 | |
| Forfeited | (469,035) | | | $ | 10.54 | |
| Vested | (1,903,453) | | | $ | 18.20 | |
| Non-vested RSUs at December 31, 2019 | 2,635,765 | | | $ | 8.32 | |
| Granted | 1,409,765 | | | $ | 0.75 | |
| Forfeited | (1,852,249) | | | $ | 3.00 | |
| Vested | (1,007,930) | | | $ | 9.09 | |
| Non-vested RSUs at December 31, 2020 | 1,185,351 | | | $ | 6.99 | |
Performance Stock Awards
The Company granted performance stock awards (“PSAs”) to certain executives under the 2016 LTIP in October 2017, March 2018, April 2019 and March 2020. The number of shares of the Company’s common stock that may be issued to settle these various PSAs ranges from zero to two times the number of PSAs awarded. PSA’s that settle in cash are presented as liability awards. Generally, the shares issued for PSAs are determined based on the satisfaction of a time-based vesting schedule and a weighting of one or more of the following: (i) absolute total stockholder return (“ATSR”), (ii) relative total stockholder return (“RTSR”), as compared to the Company’s peer group and (iii) cash return on capital invested (“CROCI”) or return on invested capital (“ROIC”) measured over a three-year period and vest in their entirety at the end of the three-year measurement period. Any PSAs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion that is associated with the RTSR is based on a comparison of the Company’s total shareholder return for the measurement period compared to that of a group of peer companies for the same measurement period. As the ATSR and RTSR vesting criteria are linked to the Company’s share price, they each are considered a market condition for purposes of calculating the grant-date fair value of the awards. The vesting criterion that is associated with the CROCI and ROIC are considered a performance condition for purposes of calculating the grant-date fair value of the awards.
The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company’s peers.
|
| | | | | | |
| | | | Weighted |
| | | | Average |
| | Number of | | Grant Date |
| | Shares | | Fair Value |
| Non-vested RSUs at January 1, 2016 | — |
| | $ | — |
|
| Granted | 3,237,500 |
| | $ | 21.41 |
|
| Forfeited | — |
| | $ | — |
|
| Vested | — |
| | $ | — |
|
| Non-vested RSUs at December 31, 2016 | 3,237,500 |
| | $ | 21.41 |
|
| Granted | 1,369,083 |
| | $ | 16.37 |
|
| Forfeited | (445,366 | ) | | $ | 19.85 |
|
| Vested | (1,254,744 | ) | | $ | 20.85 |
|
| Non-vested RSUs at December 31, 2017 | 2,906,473 |
| | $ | 19.51 |
|
| | | | | | | | | | | | | | | | | |
| | For the Years Ended |
| | December 31, 2020 | | December 31, 2019 | | December 31, 2018 |
| Risk free rates | 0.6 | % | | 2.3 | % | | 2.3 | % |
| Dividend yield | 0 | | | 0 | | | 0 | |
| Expected volatility | 83.7 | % | | 58.5 | % | | 59.9 | % |
The Company recorded $1.7 million, $7.3 million and $5.7 million of stock-based compensation costs related to PSAs for the years ended December 31, 2020, 2019 and 2018, respectively. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2020, there was $0.9 million of total unrecognized compensation cost related to the unvested PSAs granted to certain executives that is expected to be recognized over a weighted-average period of 1.1 years.
The following table summarizes the PSA activity from January 1, 2018 through December 31, 2020 and provides information for PSAs outstanding at the dates indicated.
| | | | | | | | | | | |
| | | | Weighted Average |
| | Number of | | Grant Date |
| | Shares(1) | | Fair Value |
| Non-vested PSAs at January 1, 2018 | 832,163 | | | $ | 8.85 | |
| Granted | 1,961,920 | | | $ | 9.06 | |
| Forfeited | 0 | | | $ | 0 | |
| Vested | 0 | | | $ | 0 | |
| Non-vested PSAs at December 31, 2018 | 2,794,083 | | | $ | 9.00 | |
| Granted | 1,224,696 | | | $ | 5.63 | |
| Forfeited | (418,229) | | | $ | 8.17 | |
| Cancelled | (737,360) | | | $ | 8.85 | |
| Vested | 0 | | | $ | 0 | |
| Non-vested PSAs at December 31, 2019 | 2,863,190 | | | $ | 7.72 | |
| Granted | 5,952,700 | | | $ | 0.29 | |
| Forfeited (2) | (5,881,200) | | | $ | 0.29 | |
| Cancelled | (1,738,411) | | | $ | 9.06 | |
| Vested | 0 | | | $ | 0 | |
| Non-vested PSAs at December 31, 2020 | 1,196,279 | | | $ | 5.32 | |
(1)The number of awards assumes that the associated maximum vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to one for the 2017 and 2018 grants and ranges from zero to two for the 2019 and 2020 grants, depending on the level of satisfaction of the vesting condition.
(2)The Company approved retention agreements on June 12, 2020 with certain executives and senior managers. These retention agreements, are subject to repayment upon a resignation without “good reason” or termination of employment for “cause” before specified dates and events. As a condition to participating in the revised compensation program, the equity compensation awards granted in 2020 were forfeited.
Stock Options
Expense on the stock options areis recognized on a straight-line basis over the service period of the award less awards forfeited. The fair value of the stock options werewas measured at the grant date using the Black ScholesBlack-Scholes valuation model. The Company utilizesutilized the "simplified"“simplified” method to estimate the expected term of the stock options granted as at the time there iswas limited historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury instruments with comparable terms. A dividend yield and forfeiture rate of zero0 were assumed. Stock options granted under the 2016 LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date. To fulfill options exercised, the Company issueswill issue new shares.
The Company recorded $15.70 stock-based compensation costs related to stock options for the year ended December 31, 2020. The Company recorded $12.1 million and $2.9$15.1 million of stock-based compensation costs related to the stock options for the years ended December 31, 20172019 and 2016,2018, respectively. The Company did not record any stock-based compensation expense related to stock options forThese costs were included in the year ended December 31, 2015.consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2017,2020, there was $27.2 million ofare no remaining unrecognized compensation costcosts related to the stock options that is expectedgranted to be recognized over a weighted-average period of 1.8 years.certain executives.
The following table summarizes the assumptions used for the Black-Scholes valuation model to calculate the stock-based compensation expense for the year ended December 31, 2018. NaN stock options were granted for the years presented.ended December 31, 2020, 2019, and 2018.
|
| | | | | | | |
| | For the Year Ended |
| | December 31, 2017 | | December 31, 2016 |
| | |
| | |
| Risk free rates | 2.0 | % | | 1.4 | % |
| Dividend yield | — |
| | — |
|
| Expected volatility | 58.9 | % | | 47.2 | % |
| Expected term (in years) | 6.0 |
| | 6.0 |
|
| | |
| | |
| The weighted average fair value at the date of grant for stock options granted is as follows: | |
| | |
| | |
| | |
| Weighted average per share | $ | 8.66 |
| | $ | 8.75 |
|
| Total options granted | 744,428 |
| | 4,500,000 |
|
| Total weighted average fair value of shares granted (in thousands) | $ | 6,445 |
| | $ | 39,375 |
|
| | | | | |
| For the Year Ended |
| December 31, 2018 |
| Risk free rates | 2.0 | % |
| Dividend yield | 0 | |
| Expected volatility | 58.9 | % |
| Expected term (in years) | 6.0 |
| |
| The weighted average fair value at the date of grant for stock options granted is as follows: | |
| Weighted average per share | $ | 8.66 | |
| Total options granted | 744,428 | |
| Total weighted average fair value of options granted (in thousands) | $ | 6,445 | |
The following table summarizes the stock option activity from January 1, 20162018 through December 31, 20172020 and provides information for stock options outstanding at the dates indicated.
| | | | | | | Number of Shares | | Weighted Average Exercise Price | | Aggregate Intrinsic Value
(in thousands) |
| | | | Weighted | |
| | | | Average | |
| | Number of | | Exercise | |
| | Shares | | Price | |
| Non-vested Stock Options at January 1, 2016 | — |
| | $ | — |
| |
| Non-vested Stock Options at January 1, 2018 | | Non-vested Stock Options at January 1, 2018 | 3,496,290 | | | $ | 18.50 | | | $ | 0 | |
| Granted | 4,500,000 |
| | $ | 19.00 |
| Granted | 0 | | | $ | 0 | | | $ | — | |
| Forfeited | — |
| | $ | — |
| Forfeited | 0 | | | $ | 0 | | | $ | — | |
| Vested | — |
| | $ | — |
| Vested | (1,748,142) | | | $ | 18.49 | | | $ | — | |
| Non-vested Stock Options at December 31, 2016 | 4,500,000 |
| | $ | 19.00 |
| |
| Non-vested Stock Options at December 31, 2018 | | Non-vested Stock Options at December 31, 2018 | 1,748,148 | | | $ | 18.50 | | | $ | — | |
| Granted | 744,428 |
| | $ | 15.53 |
| Granted | 0 | | | $ | 0 | | | $ | — | |
| Forfeited | — |
| | $ | — |
| Forfeited | 0 | | | $ | 0 | | | $ | — | |
| Vested | (1,748,138 | ) | | $ | 18.52 |
| Vested | (1,748,148) | | | $ | 18.50 | | | $ | — | |
| Non-vested Stock Options at December 31, 2017 | 3,496,290 |
| | $ | 18.50 |
| |
| Non-vested Stock Options at December 31, 2019 | | Non-vested Stock Options at December 31, 2019 | 0 | | | $ | 0 | | | $ | — | |
| Granted | | Granted | 0 | | | $ | 0 | | | $ | — | |
| Forfeited | | Forfeited | 0 | | | $ | 0 | | | $ | — | |
| Vested | | Vested | 0 | | | $ | 0 | | | $ | — | |
| Non-vested Stock Options at December 31, 2020 | | Non-vested Stock Options at December 31, 2020 | 0 | | | $ | 0 | | | $ | — | |
The following table summarizes information about outstanding and exercisable stock options as of December 31, 2017.2020.
| | | | | | | | | | | | | | | | | | | | |
| Outstanding and Exercisable Options |
| | Weighted-Average | | Weighted-Average | | |
| Options | | Remaining Contractual Life | | Exercise Price | | Aggregate Intrinsic Value (thousands) |
| 4,500,000 | | | 5.9 years | | $ | 19.00 | | | $ | — | |
| 744,428 | | | 6.8 years | | $ | 15.53 | | | $ | — | |
| 5,244,428 | | | 6.0 years | | $ | 18.50 | | | $ | — | |
|
| | | | | | | | | | | | | | |
| | | | | | | | | |
| Outstanding Options | | Exercisable Options |
| | | Weighted-Average | | Weighted-Average | | | | Weighted-Average Exercise |
| Options | | Remaining Contractual Life | | Exercise Price | | Options | | Price per Share |
| 4,500,000 |
| | 8.9 years | | $ | 19.00 |
| | 1,500,000 |
| | $ | 19.00 |
|
| 744,428 |
| | 9.8 years | | $ | 15.53 |
| | 248,138 |
| | $ | 15.53 |
|
| 5,244,428 |
| | 9.0 years | | $ | 18.50 |
| | 1,748,138 |
| | $ | 18.52 |
|
Performance Stock Awards
The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Those outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results with be obtained for those iterations. In the case of the Company's PSAs, the Company cannot predict with certainty the path its stock price or the stock prices of its peer will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSAs. Significant assumptions used in this simulation include the Company's expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company's peers.
The assumptions used in valuing the PSAs granted were as follows:
|
| | |
| For the Year Ended |
| December 31, 2017 |
| |
|
Risk free rates | 1.5 | % |
Dividend yield | — |
|
Expected volatility | 45.0 | % |
The Company recorded $0.8 million of stock-based compensation costs related to PSAs for the year ended December 31, 2017. The Company did not record any stock-based compensation expense related to PSAs for the years ended December 31, 2016 and 2015. As of December 31, 2017, there was $6.6 million of unrecognized compensation cost related to the PSAs that is expected to be recognized over a weighted-average period of 2.0 years.
The following table summarizes the PSA activity from January 1, 2017 through December 31, 2017 and provides information for PSAs outstanding at the dates indicated.
|
| | | | | | |
| | | | Weighted |
| | | | Average |
| | Number of | | Grant Date |
| | Shares (1) | | Fair Value |
| Non-Vested PSAs as of January 1, 2017 | — |
| | $ | — |
|
| Granted | 832,163 |
| | $ | 8.85 |
|
| Forfeited | — |
| | $ | — |
|
| Vested | — |
| | $ | — |
|
| Non-Vested PSAs as of December 31, 2017 | 832,163 |
| | $ | 8.85 |
|
| |
(1) | The number of awards assumes that the associated maximum vesting condition is met at the target amount. The final number of shares of the Company's common stock issued may vary depending on the performance multiplier, which ranges from zero to one, depending on the level of satisfaction of the vesting condition. |
Incentive Restricted Stock Units (“Incentive RSUs”)
In November 2016, after the Holdings’ Incentive Units were converted to the 9.1 million shares of common stock, holdersOfficers of the Holding’s Incentive UnitsCompany contributed 2.7 million shares of common stock to Extraction Employee Incentive, LLC (“Employee Incentive”), which is owned solely by certain officers of the Company. Employee Incentive issued restricted stock units (“Incentive RSUs”) to certain employees. Incentive RSUs vestvested over a three year-year service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. On July 17, 2017, the partners of Employee Incentive amended the vesting schedule in which 25% vested immediately and the remaining Incentive RSUs vest 25%, 25% and 25% each six months thereafter, over the remaining 18 month service period. Grant date fair value was determined based on the value of Extraction’sthe Company’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero0 as part of the grant date estimate of compensation cost. On July 10, 2017, the partners of Employee Incentive amended the vesting schedule in which 25% vested on July 17, 2017 and the remaining Incentive RSUs will vest 25%, 25% and 25% each six months thereafter, over the remaining 18 months service period. Grant date fair value was determined based on the value of Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09. The Company withholds shares as Incentive RSUs vest to satisfy tax withholding obligations of employees and as these shares are issued and outstanding, the withheld shares are included in treasury stock on the consolidated balance sheets.
The Company recorded $17.30 stock-based compensation costs related to Incentive RSUs for the year ended December 31, 2020. The Company recorded $0.8 million and $2.4$19.6 million of stock-based compensation costs related to Incentive RSUs for the years ended December 31, 20172019 and 2016,2018, respectively. No stock-based compensation costs related to Incentive RSUs were recorded for the year ended December 31, 2015. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2017,2020, there was $21.3 million of totalare no remaining unrecognized compensation costcosts related to the unvested Incentive RSUs granted to certain employees that is expected to be recognized over a weighted average period of 1.0 year.employees.
The following table summarizes the Incentive RSU activity from January 1, 20162018 through December 31, 20172020 and provides information for Incentive RSUs outstanding at the dates indicated.
| | | | | | | | | | | |
| | | | Weighted Average |
| | Number of | | Grant Date |
| | Shares | | Fair Value |
| Non-vested Incentive RSUs at January 1, 2018 | 1,496,175 | | | $ | 20.45 | |
| Granted | 0 | | | $ | 0 | |
| Forfeited | (41,400) | | | $ | 20.45 | |
| Vested | (978,775) | | | $ | 20.45 | |
| Non-vested Incentive RSUs at December 31, 2018 | 476,000 | | | $ | 20.45 | |
| Granted | 0 | | | $ | 0 | |
| Forfeited | 0 | | | $ | 0 | |
| Vested | (476,000) | | | $ | 20.45 | |
| Non-vested Incentive RSUs at December 31, 2019 | 0 | | | $ | 0 | |
| Granted | 0 | | | $ | 0 | |
| Forfeited | 0 | | | $ | 0 | |
| Vested | 0 | | | $ | 0 | |
| Non-vested Incentive RSUs at December 31, 2020 | 0 | | | $ | 0 | |
|
| | | | | | |
| | | | Weighted |
| | | | Average |
| | Number of | | Grant Date |
| | Shares | | Fair Value |
| Non-vested Incentive RSUs at January 1, 2016 | — |
| | $ | — |
|
| Granted | 2,717,968 |
| | $ | 20.45 |
|
| Forfeited | (3,600 | ) | | $ | 20.45 |
|
| Vested | — |
| | $ | — |
|
| Non-vested Incentive RSUs at December 31, 2016 | 2,714,368 |
| | $ | 20.45 |
|
| Granted | — |
| | $ | — |
|
| Forfeited | (710,993 | ) | | $ | 20.45 |
|
| Vested | (507,200 | ) | | $ | 20.45 |
|
| Non-vested Incentive RSUs at December 31, 2017 | 1,496,175 |
| | $ | 20.45 |
|
Holdings’ Membership Unit Incentive Plan
On May 29, 2014, Holdings adopted the 2014 Membership Unit Incentive Plan (“2014 Plan”). The 2014 Plan provided for the compensation of employees, non‑employee managers and consultants of the Company and its affiliates through grants of restricted unit awards (“Holdings’ RUAs”) and incentive units (“Holdings’ Incentive Units”). The 2014 Plan was terminated as a result of the Corporate Reorganization in October 2016.
Holdings’ RUAs
Holdings’ RUAs vested over a three‑year service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. The Company estimated fair value of the RUAs on their grant date based upon estimated volatility, market comparable risk free rate, estimated forfeiture rate and a discount for lack of marketability. Grant date fair value was determined based on the value of Holdings’ Equity Units on the date of the grant. Due to a lack of historical data, the Company used the experience of other entities in the same industry to estimate a forfeiture rate. Expected forfeitures are then included as part of the grant date estimate of compensation cost.
No unit-based compensation costs related to Holdings' RUA grants were recorded for December 31, 2017. The Company recorded $16.8 million and $5.3 million of unit-based compensation costs related to Holdings’ RUA grants for the years ended December 31, 2016 and 2015, respectively. These costs are included in the consolidated statements of operations within the general and administrative expenses line item. In connection with the Corporate Reorganization in 2016, the Holdings Membership Unit Incentive Plan ("2014 Plan") was terminated. As of December 31, 2017, there is no unrecognized compensation cost related to unvested RUAs granted to employees.
The following table summarizes the Holdings’ RUA activity from January 1, 2015 through December 31, 2016 and provides information for Holdings’ RUAs outstanding at the dates indicated.
|
| | | | | | |
| | | | Weighted |
| | | | Average |
| | Number of | | Grant Date |
| | Shares | | Fair Value |
| Non-vested RUAs at January 1, 2015 | 9,365,896 |
| | $ | 2.22 |
|
| Granted | 196,047 |
| | $ | 2.68 |
|
| Forfeited | (53,063 | ) | | $ | 2.21 |
|
| Vested | (3,197,638 | ) | | $ | 2.22 |
|
| Non-vested RUAs at December 31, 2015 | 6,311,242 |
| | $ | 2.23 |
|
| Granted | 1,531,542 |
| | $ | 5.84 |
|
| Forfeited | (181,817 | ) | | $ | 2.68 |
|
| Vested | (7,660,967 | ) | | $ | 2.94 |
|
| Non-vested RUAs at December 31, 2016 | — |
| | $ | — |
|
PRL RUAs
PRL granted RUAs to certain employees, including Extraction employees (“PRL RUAs”). PRL RUAs vested over a three years service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of PRL’s Equity Units on the date of the grant. PRL uses its past experience to estimate a forfeiture rate and expected forfeitures are included as part of the grant date estimate of compensation cost.
No unit-based compensation costs related to PRL RUA grants were recorded for the year ended December 31, 2017. The Company recorded $0.5 million and $0.8 million of unit-based compensation costs related to PRL RUA grants for the years ended December 31, 2016 and 2015, respectively. These costs are included in the consolidated statements of operations within the general and administrative expenses line item. In connection with the Corporate Reorganization in 2016, the Holdings Membership Unit Incentive Plan ("2014 Plan") was terminated. As of December 31, 2017, there was no unrecognized compensation cost related to the PRL RUAs as all awards were fully vested.
Holdings’ Incentive Units
In accordance with the 2014 Plan and the Holdings LLC Agreement, Holdings issued 3.0 million Holdings’ incentive units to certain members of management in the fourth quarter of 2015. All of Holdings’ Incentive Units were non‑voting and subject to certain vesting and performance conditions. The Holdings’ Incentive Units vested over a three year service period, with 25%, 25% and 50% of the units vesting in year 1, year 2 and year 3, respectively (with vesting between the first and third anniversaries occurring pro-rata based on the number of full months elapsed since the last vesting date), and in full upon a change of control, as defined in the Holdings LLC Agreement. The Holdings’ Incentive Units were accounted for as liability awards under ASC 718, Compensation-Stock Compensation, with compensation expense based on period‑end fair value.
In connection with the IPO, the Board of Managers of Holdings accelerated the vesting of the Holdings’ Incentive Units. The Company’s IPO and change of control triggered the conversion of these units into approximately 9.1 million common shares of the Company based on the 10-day volume weighted average price of the Company’s common stock following its IPO as set forth in the Holdings Third Amended and Restated LLC Agreement. For the year ended December 31, 2016, the Company recognized approximately $172.1 million in non-cash, share-based compensation expense in connection with the conversion of the Holdings’ Incentive Units into the Company’s common stock. No incentive compensation expense was recorded for the year ended December 31, 2015 because it was not probable that the performance criterion would be met.
Note 12—15—Earnings (Loss) Per Share
Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings available to common shareholders of the Company. The Company uses the “if-converted” method to determine potential dilutive effects of Series A Preferred Stock and the treasury method to determine the potential dilutive effects of outstanding restricted stock awards and stock options and PSAs.options.
EPS for the year ended December 31, 2016 is calculated for the period from October 12, 2016, the effective date
The components of basic and diluted EPS were as follows:follows (in thousands, except per share data):
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Basic and Diluted Income (Loss) per Share | | | | | |
| Net income (loss) | $ | (1,267,534) | | | $ | (1,367,420) | | | $ | 121,855 | |
| Less: Noncontrolling interest | (6,160) | | | (19,992) | | | (7,287) | |
| Less: Adjustment to reflect Series A Preferred Stock dividend | (8,749) | | | (12,796) | | | (10,885) | |
| Less: Adjustment to reflect accretion of Series A Preferred Stock discount | (7,366) | | | (6,640) | | | (5,984) | |
| Net income (loss) available to common shareholders, basic and diluted | $ | (1,289,809) | | | $ | (1,406,848) | | | $ | 97,699 | |
Weighted Average Common Shares Outstanding (1) (2) (3) | | | | | |
| Basic and diluted | 138,149 | | | 151,481 | | | 174,748 | |
| Net Income (Loss) Allocated to Common Shareholders per Common Share | | | | | |
| Basic and diluted | $ | (9.34) | | | $ | (9.29) | | | $ | 0.56 | |
|
| | | | | | | |
| | | | From October 12, 2016 |
| | Year Ended December 31, 2017 | | to December 31, 2016 |
| Basic and Diluted EPS (in thousands, except per share data) | | | |
|
| Net Loss | $ | (44,408 | ) | | $ | (226,107 | ) |
| Less: Adjustment to reflect Series A Preferred Stock dividend | (10,885 | ) | | (2,958 | ) |
| Less: Adjustment to reflect accretion of Series A Preferred Stock discount | (5,394 | ) | | (1,041 | ) |
| Net loss attributable to common shareholders | $ | (60,687 | ) | | $ | (230,106 | ) |
Weighted Average Common Shares Outstanding (1) (2) | |
| | |
| Basic and diluted | 171,910 |
| | 149,029 |
|
| Net Loss Allocated to Common Shareholders per Common Share | |
| | |
| Basic and diluted | $ | (0.35 | ) | | $ | (1.54 | ) |
| |
(1) | For the year ended December 31, 2017, 8,566,983 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards, stock options outstanding and performance stock awards contingently issuable, if December 31, 2017 was the end of the measurement period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded. |
| |
(2) | For the period of October 12 through December 31, 2016, 7,737,500 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards and stock options outstanding for the period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded. |
(1)For the year ended December 31, 2020, 1,185,351 potentially dilutive shares associated with restricted stock awards outstanding were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out of the money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.
(2)For the year ended December 31, 2019, 2,635,765 potentially dilutive shares associated with restricted stock awards outstanding were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out of the money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.
(3)For the year ended December 31, 2018, 3,102,335 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards, stock options outstanding and performance stock awards contingently issuable, if December 31, 2018 was the end of the measurement period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.
Note 13—16—Commitments and Contingencies
Chapter 11 Cases
On June 14, 2020, the Company filed the Chapter 11 Cases seeking relief under the Bankruptcy Code. The Company continues to operate its business and manage its properties in the ordinary course of business pursuant to the applicable provisions of the Bankruptcy Code. In addition, commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against the Company (other than regulatory enforcement matters), including those noted below. Please refer to Note 1 — Business and Organization for more information on the Chapter 11 Cases.
General
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost, or the Company may be required to pay damages if certain performance conditions are not met.
Leases
The Company has entered into operating leases twofor certain office spaces in Denver, Colorado, twofacilities, compressors and office spaces in Greeley, Colorado and oneequipment. As of December 31, 2020, the Company leased 1 office space in Houston, Texas under separatean operating lease agreements. The Denver, Colorado leases expireagreement that expires on February 29, 2020 and May 31, 2026, respectively. The Greeley and Houston leases expire on August 19, 2019, JuneNovember 30, 2019 and October 31, 2017, respectively. Total rental commitments under non-cancelable leases for office space were $35.7 million at December 31, 2017. The future minimum lease payments under these non-cancelable leases are as follows: $3.0 million in 2018, $3.5 million in 2019, $3.4 million in 2020, $3.4 million in 2021, $3.3 million in 2022 and $19.1 million thereafter.2021. Rent expense was $2.3$3.1 million, $1.9$3.5 million and $1.1$3.4 million for the years ended December 31, 2017, 2016,2020, 2019, and 2015,2018, respectively.
On June 4, 2015,January 1, 2019, the Company subleasedadopted ASC Topic 842, Leases, using the remaining termmodified retrospective approach. Refer to Note 7 — Leases for additional information.
In connection with the Chapter 11 Cases, the Company filed a motion to reject its drilling rig contracts effective June 14, 2020. For one of the contracts, the rejection resulted in the removal of the lease liability and net right-of-use asset in the amount of $6.7 million from the consolidated balance sheets. The Company amended its Denver office leases that expires February 29,lease contract effective December 7, 2020. The sublease will decreaseamendment resulted in the Company’s futureremoval of the lease payments by $0.5 million.liability and the net right-of-use asset in the amount of $13.2 million and $9.4 million, respectively.
Maturities of operating lease liabilities associated with right-of-use assets including imputed interest but excluding rejected contracts were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| | As of December 31,
2020 | | | | As of December 31,
2019 |
| | | | 2020 | | 19,040 | |
| 2021 | | 4,549 | | | 2021 | | 5,247 | |
| 2022 | | 3,176 | | | 2022 | | 2,211 | |
| 2023 | | 1,139 | | | 2023 | | 2,246 | |
| 2024 | | 199 | | | 2024 | | 2,301 | |
| Thereafter | | 0 | | | Thereafter | | 8,273 | |
| Total lease payments (1) | | 9,063 | | | Total lease payments (1) | | 39,318 | |
| Less imputed interest | | (427) | | | Less imputed interest | | (4,735) | |
| Present value of lease liabilities (2) | | $ | 8,636 | | | Present value of lease liabilities (3) | | $ | 34,583 | |
| | | | | | |
(1) Calculated using the estimated interest rate for each lease.
(2) The total present value of lease liabilities was recorded in liabilities subject to compromise on the consolidated balance sheets as of December 31, 2020.
(3) Of the total present value of lease liabilities, $17.4 million was recorded in accounts payable and accrued liabilities and $17.2 million was recorded in other non-current liabilities on the consolidated balance sheets as of December 31, 2019.
Drilling Rigs
As of December 31, 2017,2020, the Company was not subject to commitments on three dillingany drilling rigs. In the eventAs part of early termination of these contracts,its case in chapter 11, the Company would be obligatedfiled a motion to pay an aggregate amount of approximately $8.9reject its drilling rig contracts. As such, the Company recorded $6.7 million in liabilities subject to compromise on the consolidated balance sheets as of December 31, 2017, as required under2020, and in reorganization items, net on the termsconsolidated statements of operations. During the first quarter of 2021, the Company agreed to have a drilling rig on a 30-day rolling term drill various pads during 2021.
Delivery Commitments
During the third and fourth quarters of 2020, the majority of the contracts. In March 2015,Company’s material midstream contracts were renegotiated and/or rejected by the Bankruptcy Court as part of the Chapter 11 Cases. As a result of these rejections or renegotiated contracts, the Company early terminated oneeliminated the majority of its drilling rig contracts for approximately $1.7minimum volume commitments as described below and accrued $550.5 million which was recordedwithin liabilities subject to compromise on the consolidated balance sheets as of December 31, 2020 and in reorganization items, net on the consolidated statements of operations withinfor the other operating expenses line item. In February 2016, the Company provided notice to terminate one of its drilling rigs that was subject to commitment atyear ended December 31, 2015. As part of this termination, the2020.
The Company was obligated to pay $1.0 million in the second quarter of 2016. In January 2017, the Company provided notice for termination on one drilling rig and paid no termination fees.
Delivery Commitments
As of December 31, 2017, the Company’s oil marketer is subject to a firm transportation agreement that commenced in November 2016 and hashad a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017,Until July 2020, these commitments were obligations of the Company’s third-party oil marketer, which reverted back to the Company amended its agreementwhen the associated oil marketing contract terminated in June 2020. After termination of the aforementioned contract with its third-party oil marketer, that requires it to sell all of itsthe Company had a long-term crude oil from an areadelivery commitment agreement that commenced on July 1, 2020. Before the Bankruptcy Court rejected this contract, the Company’s long-term crude oil delivery commitment had a monthly minimum delivery commitment of mutual interest61,800 Bbl/d through October 2023 and then would have reduced to 58,000 Bbl/d through October 2026. The Company was required to pay a shortfall fee for any volume deficiencies under these commitments. On November 2, 2020, the Bankruptcy Court ruled in exchange for a make-whole provision that allowsfavor of the Company to satisfy anyrejecting this contract with an effective date as of June 14, 2020, and, therefore, the Company has no remaining minimum volume commitment deficiencies incurred by its oil marketer with future barrels of crude oil in excess of theircommitments under this transportation contract. On December 19, 2020, the Company and the counterparty entered into a settlement agreement and also entered into a new supply agreement that has no minimum volume commitment through October 31, 2018. In December 2017, the Company extended the termcommitments.
The Company evaluates its contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable. The Company also has onehad 2 long-term crude oil gathering commitmentcommitments with antwo former unconsolidated subsidiary,subsidiaries in which we havethe Company had a de minimis minority ownership interest. It hasPlease see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC for further information. The first agreement commenced in November 2016 and had a term of ten years with a minimum volume commitment of an average of 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The remaining aggregate amountsecond agreement commenced in October 2019 and had a term of estimated paymentsten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. The Company would have been required to pay a shortfall fee for any volume deficiencies under these commitments. On November 2, 2020, the Bankruptcy Court ruled in favor of the Company rejecting both of these crude oil gathering contracts with an effective date of June 14, 2020, and, therefore, the Company has no remaining minimum volume commitments under these contracts. On January 4, 2021, the Company and the counterparty entered into a settlement agreement and subsequently entered into two new transportation service agreements is approximately $927.3 million.that have no minimum volume commitments.
In February 2019, the Company entered into a long-term gas gathering and processing agreement with a third-party midstream providers. The agreement commenced in November 2019 and had a term of twenty years with a minimum volume commitment of 251 Bcf to be delivered within the first seven years. The annual commitments over seven years were to be delivered on an average 85,000 Mcf/d in year one, 125,000 Mcf/d in year two, 140,000 Mcf/d in year three, 118,000 Mcf/d in year four, 98,000 Mcf/d in year five, 70,000 Mcf/d in year six and 52,000 Mcf/d in year seven. On January 20, 2021, the Company and the counterparty entered into a settlement agreement and amended its three long-term gas gathering and processing agreements and one oil gathering agreement with the same party. As part of the settlement and amended agreements, all prior minimum volume commitments were relieved. There are no minimum volume commitments in the amended agreements.
The Company entered into another long-term gas gathering and processing agreement with a different third party midstream provider in February 2019. This agreement commenced in January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf. This agreement also includes a commitment to sell take-in-kind NGLs from other processing agreements of 4,000 Bbl/d in year one and 7,500 Bbl/d in years two through seven with the ability to roll up to a 10% shortfall in a given month to the subsequent month. On December 23, 2020, the Company and the counterparty entered into a settlement and amended the agreement. As part of the settlement and amended agreement, there were no changes made to the minimum volume commitments.
In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, the Company agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes twoincluded 2 new processing plants as well as the expansion of related gathering systems, which are currently expected to be completed by mid-2018systems. The first plant commenced operations in August 2018 and mid-2019, respectively, although the exact start-up dates are undetermined at this time.second plant commenced operations in July 2019. The Company’s share of these commitments will require an incremental 51.5 MMcf and 20.6 MMcf per day, respectively, over a baseline volume of 65 MMcf per day to be delivered after the plants'plants’ in-service dates for a period of seven years thereafter. The Company may be required to pay a shortfall fee for any volumesincremental volume deficiencies under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other third partythird-party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. The Company is also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold. Under its current drilling plans,
In July 2019, the Company expectsentered into 3 long-term contracts to meet thesesupply 125,000 dekatherms of residue gas per day for five years to a transportation company. On November 24, 2020, the Bankruptcy Court ruled in favor of the Company rejecting this contract with an effective date as of December 10, 2020, and, therefore, the Company has no remaining minimum volume commitments.
Acquisition of Undeveloped Leasehold Acreage
commitments under this transportation contract. The Company had previously posted a letter of credit for this agreement in the amount of $8.7 million. On February 8, 2021, the transportation company drew the full amount of the letter of credit on the Company’s RBL Credit Facility, and this drawing was partyconverted into a borrowing under the RBL Credit Facility.
Elevation Gathering Agreements
In July 2018, the Company entered into three long-term gathering agreements (the “Elevation Gathering Agreements”) for gas, crude oil and produced water with Elevation. Under the agreements, the Company agreed to drill 100 wells in Broomfield and 325 wells in Hawkeye by December 31, 2023 if both facilities are to be built, subject to adjustments if less capital is spent. If the Company wer to fail to complete the wells by the applicable deadline, then it would be in breach of the agreement and Elevation could attempt to assert damages against Extraction and its affiliates. During the first quarter of 2020, Elevation postponed indefinitely further development of gathering systems and facilities that were to be constructed to service the Company’s acreage in Hawkeye and another project in the Southwest Wattenberg area. Due to the decision to not complete the Hawkeye facilities and based on the amount of capital invested, Elevation had asserted that the drilling commitment now consists of 297 wells in the Broomfield area of operations with a deadline of December 31, 2022. As discussed below, in December 2020 this drilling commitment was further reduced to 106 wells.
In April 2019, the Elevation Gathering Agreements were amended to provide for, among other amendments, the inclusion of additional gathering facilities that would produce into Elevation’s Badger facility.
In December 2019, the Elevation Gathering Agreements were further amended to provide Elevation additional connection fees that are consistent with market terms (the “Connect Fees”). In the fourth quarter of 2019, the Company incurred and paid $19.5 million for Connect Fees pursuant to the Elevation Gathering Agreements, and in the first quarter of 2020 the Company incurred and paid $23.5 million. The Company did not incur additional Connect Fees for the year ended December 31, 2020.
In April 2020, pursuant to the amendment to the Elevation Gathering Agreements made in April 2019 discussed above, Elevation asserted that the additional gathering facilities that were required to be completed by April 1, 2020 were not built thus Extraction must make a payment to Elevation in the amount of 135% of all costs incurred by Elevation as of such date for the development and construction of such additional gathering facilities. On April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. The Company recorded the amount in liabilities subject to compromise on the condensed consolidated balance sheet as of December 31, 2020 and in other operating expenses on the condensed consolidated statements of operations for the year ended December 31, 2020.
On December 15, 2020, the Company and Elevation reached an agreement through November 15, 2017regarding amendments to the gathering agreements and the settlement of all outstanding claims. As part of the settlement, the Company will pay Elevation $38.4 million in cash over 24 months, and Elevation submitted an unsecured claim of $80.0 million with the Bankruptcy Court. The agreement released certain areas from future dedication, provided a reduction in certain gathering fees, a reduction in the number of wells subject to the drilling commitment, and an unrelated third party for whichextended term in order to satisfy the remaining drilling commitment. The Company also relinquished the nominal common interest ownership it has paid $214.3had in Elevation. The Company previously accrued $46.8 million and is required$4.2 million of accrued interest related to paythe aforementioned alleged breach in contract. During the third quarter of 2020, the Company accrued an additional $12.2$68.7 million in April 2018,within liabilities subject to certain customary closing conditions, to lease a totalcompromise on the consolidated balance sheets and in reorganization items, net on the consolidated statements of approximately 36,600 net acres of undeveloped leasehold. Additionally, in January 2018, theoperations.
Company acquired approximately 1,200 net acres of undeveloped leasehold from an unrelated third party for $11.6 million, subject to certain customary closing conditions.
General
The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating, and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s financial position, results of operations, or cash flows.
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost or the Company may be required to pay damages if certain performance conditions are not met.
Litigation and Legal MattersItems
InThe Company is involved in various legal proceedings and reviews the ordinary coursestatus of business,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 the Company’s best interests. The Company has provided the necessary estimated accruals in the consolidated balance 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, the Company may at times be subject to claims and legal actions. Managementcurrently believes it is remote that the impactultimate results of such mattersproceedings will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Management is unaware of any material pending litigation brought against the Company requiring the reserve of a contingent liability as of the date of this filing.
We were issued a Compliance Advisory in July 2015 from the Colorado Department of Public Health and Environment (“CDPHE”), which alleged air quality violations at certain of our facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. On January 31, 2018, we entered into a Compliance Order on Consent with the CDPHE that provides for a field-wide administrative settlement of these issues.
The Compliance Order provides that we will implement changes to our design, operation, maintenance and recordkeeping of many of our field-wide storage tank systems to enhance our emissions management. Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation and operation of certain emission mitigation projects at certain facilities constructed in 2018 and 2019. The two primary elements of the Compliance Order are: (i) a monetary penalty of $138,600; and (ii) injunctive relief with an estimated cost of approximately $500,000, primarily representing capital enhancements to our operations. Certain expenditures for the injunctive relief have already been incurred prior to entry of the Compliance Order, with the remainder expected to be incurred over the next few years. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidatedbusiness, financial statements.position, results of operations or liquidity.
Environmental. Due to the nature of the oil and natural gas industry, the Company is exposed to environmental risks. The Company has various policies and procedures to minimize and mitigate the risks from environmental contamination or with respect to environmental compliance issues. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, the Company is not aware of any material environmental claims existing as of December 31, 2020 which have not been provided for or would otherwise have a material impact on the Company’s 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, compliance matters or other environmental liabilities will not be discovered on our properties. The liability ultimately incurred with respect to a matter may exceed the related accrual.
COGCC Notices of Alleged Violations (“NOAVs”). The Company has received NOAVs from the Colorado Oil and Gas Conservation Commission (the “COGCC”) for alleged compliance violations that the Company has responded to. The Company does not believe penalties that could result from these NOAVs will have a material effect on its business, financial condition, results of operations or liquidity, but Extraction is in negotiations to settle all of its outstanding NOAVs with the COGCC, and the ultimate settlement amount is expected to exceed $600,000.
Note 14—17—Related Party Transactions
Office Lease with Related AffiliateElevation Midstream, LLC
As discussed in Note 16 — Commitments and Contingencies — Elevation Gathering Agreements, on April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. In April 2016,December 2020, the Company subleased office spaceand Elevation reached an agreement regarding amendments to Star Peak Capital, LLC,the gathering agreements and the settlement of which a memberoutstanding claims. As part of the Board of Directors is an owner, for $1,400 per month. The sublease commenced on May 1, 2016 and expires on February 28, 2020.
Units Repurchased from Officer
In May 2016,settlement, the Company repurchased 60,605 Tranche A Unitswill pay Elevation $38.4 million in cash over 24 months, and 82,578 Tranche C UnitsElevation submitted an unsecured claim of $80.0 million with the Bankruptcy Court. The agreement released certain areas from its former Chief Accounting Officer, for $3.25 per unit forfuture dedication, provided a reduction in certain gathering fees, a reduction in the number of wells subject to the drilling commitment, and an aggregate purchase priceextended term in order to satisfy the drilling commitment. The Company also relinquished the nominal common interest ownership it had in Elevation. The Company previously accrued $46.8 million and $4.2 million of approximately $0.5 million.
Promissory Notes
In May 2014,accrued interest related to the aforementioned alleged breach in contract. During the third quarter of 2020, the Company received full recourse promissory notes from two officers under which the Company advanced $5.4accrued an additional $68.7 million within liabilities subject to the employees to meet their capital contributions. The promissory notes were due on May 29, 2021, or earlier in the event of termination or certain change in control events as stipulated in the individual promissory notes and any distributions of capital contributions were considered mandatory prepayments. The promissory notes had a stated interest rate of LIBOR plus 1% per annum. The promissory notes were recorded as a reduction of members’ equity.
In September 2016, the Company redeemed 1.2 million units from two of its executive officers, for an aggregate purchase price of $7.8 million. On the same date, the executive officers used $5.6 million of the redemption value to settle in full and terminate their obligations under the promissory notes, including accrued interest thereon.
Second Lien Notes
Several lenders of Second Lien Notes were also members of Holdings. Of the $430.0 million outstandingcompromise on the Second Lien Notes asconsolidated balance sheets and in reorganization items, net on the consolidated statements of December 31, 2015, members held approximately $311.7 million. These members were paid $314.8 million upon repayment and termination of the Second Lien Notes in July 2016, including the prepayment penalty.operations.
20212024 Senior Notes
Several lenders of 2021 Senior Notes are also 5% stockholders of the Company. As of the initial issuance of the $550.0 million principal amount on the 2021 Senior Notes, members held $63.5 million.
2024 Senior Notes
Several lendersCompany were also holders of the 2024 Senior Notes are also 5% stockholders of the Company.Notes. As of the initial issuance in August 2017 of the $400.0 million principal amount on the 2024 Senior Notes, such stockholders held $54.9 million.
2026 Senior Notes
Several lenders5% stockholders of the Company were also holders of the 2026 Senior Notes are also 5% stockholders of the Company.Notes. As of the initial issuance in January 2018 of the $750.0 million principal amount on the 2026 Senior Notes, such stockholders held $56.2 million.
All holdersNote 18—Segment Information
Beginning in the fourth quarter of 2018, the Company had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the “exploration and production segment”) and (ii) the construction of and support of midstream assets to gather and process crude oil and gas production (the “gathering and facilities segment”). Elevation Midstream, LLC comprised the gathering and facilities segment. Through March 16, 2020, the results of Elevation were included in the consolidated financial statements of Extraction. Effective March 17, 2020, the results of Elevation Midstream, LLC are no longer consolidated in Extraction’s results; however, the Company’s prior quarter segment disclosures included the gathering and facilities segment because it was consolidated through March 16, 2020. Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC for further information. After March 31, 2020, the Company had a single reportable segment.
Financial information of the $75.0 million of Series A Preferred Units were also members of Holdings. The Company used $90.0 million ofCompany’s reportable segments was as follows for the net proceeds from its IPO to redeem the Series A Preferred Units in full on October 17, 2016, which included a premium of $15.0 million.
Series A Preferred Stock and Series B Preferred Units
As of the initial issuance of the $185.3 million of Series B Preferred Units, members of Holdings held approximately $135.3 million. Upon closing of the IPO, members of Holdings held $185.3 million of the Series A Preferred Stock.
Private Placement of Common Stock
Several participants in the Private Placement are also 5% stockholders of the Company. As of the initial issuance of $457.0 million of common stock in December 2016, such stockholders purchased 2,503,370 shares for $45.7 million.
Related Party—Employees
Mr. Troy Owens, brother of Mr. Matthew R. Owens, the Company's President and a member of the Company's Board of Directors, is employed by the Company as an engineer. Consistent with market compensation for his services, Mr. Troy Owens received approximately $0.3 million and $0.2 million in aggregate cash compensation relating to the fiscal years ended December 31, 20172020. 2019 and 2016, respectively. In addition, Mr. Troy Owens received certain long-term incentives during2018 (in thousands).
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020 |
| Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| Revenues: | | | | | | | |
| Revenues from third parties | 556,431 | | 1,473 | | — | | $ | 557,904 | |
| Revenues from Extraction | 0 | | 4,513 | | (4,513) | | 0 | |
| Total Revenues | $ | 556,431 | | | $ | 5,986 | | | $ | (4,513) | | | $ | 557,904 | |
| | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | |
| Direct operating expenses | $ | (249,720) | | | $ | (3,935) | | | $ | 4,294 | | | $ | (249,361) | |
| Depletion, depreciation, amortization and accretion | (331,220) | | | (1,099) | | | — | | | (332,319) | |
| Interest income | 88 | | | 29 | | | — | | | 117 | |
| Interest expense | (57,143) | | | 0 | | | — | | | (57,143) | |
| Earnings in unconsolidated subsidiaries | 0 | | | 480 | | | — | | | 480 | |
| Subtotal Operating Expenses and Other Income (Expense): | $ | (637,995) | | | $ | (4,525) | | | $ | 4,294 | | | $ | (638,226) | |
| | | | | | | |
| Segment Assets | $ | 2,025,199 | | | $ | 0 | | | $ | — | | | $ | 2,025,199 | |
| Capital Expenditures | 176,505 | | | (6,311) | | | — | | | 170,194 | |
| Investment in Equity Method Investees | 0 | | | 0 | | | — | | | 0 | |
| Segment EBITDAX | 447,919 | | | 1,256 | | | — | | | 449,175 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2019 |
| Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| Revenues: | | | | | | | |
| Revenues from third parties | $ | 905,374 | | | $ | 1,261 | | | $ | — | | | $ | 906,635 | |
| Revenues from Extraction | 0 | | | 5,618 | | | (5,618) | | | 0 | |
| Total Revenues | $ | 905,374 | | | $ | 6,879 | | | $ | (5,618) | | | $ | 906,635 | |
| | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | |
| Direct operating expenses | $ | (223,707) | | | $ | (2,258) | | | $ | 5,131 | | | $ | (220,834) | |
| Depletion, depreciation, amortization and accretion | (523,122) | | | (1,415) | | | — | | | (524,537) | |
| Interest income | 449 | | | 1,379 | | | — | | | 1,828 | |
| Interest expense | (79,232) | | | 0 | | | — | | | (79,232) | |
| Earnings in unconsolidated subsidiaries | 0 | | | 2,285 | | | — | | | 2,285 | |
| Subtotal Operating Expenses and Other Income (Expense): | $ | (825,612) | | | $ | (9) | | | $ | 5,131 | | | $ | (820,490) | |
| | | | | | | |
| Segment Assets | $ | 2,554,893 | | | $ | 377,925 | | | $ | (5,861) | | | $ | 2,926,957 | |
| Capital Expenditures | 597,677 | | | 202,624 | | | — | | | 800,301 | |
| Investment in Equity Method Investees | 0 | | | 44,584 | | | — | | | 44,584 | |
| Segment EBITDAX | 607,560 | | | 3,653 | | | (487) | | | 610,726 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018 |
| Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| Revenues: | | | | | | | |
| Revenues from third parties | $ | 1,060,743 | | | $ | 0 | | | $ | — | | | $ | 1,060,743 | |
| Revenues from Extraction | 0 | | | 0 | | | — | | | 0 | |
| Total Revenues | $ | 1,060,743 | | | $ | 0 | | | $ | 0 | | | $ | 1,060,743 | |
| | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | |
| Direct operating expenses | (209,169) | | | 0 | | | — | | | (209,169) | |
| Depletion, depreciation, amortization and accretion | (435,736) | | | (39) | | | — | | | (435,775) | |
| Interest income | 461 | | | 1,467 | | | — | | | 1,928 | |
| Interest expense | (123,330) | | | 0 | | | — | | | (123,330) | |
| Earnings in unconsolidated subsidiaries | 319 | | | 2,544 | | | — | | | 2,863 | |
| Subtotal Operating Expenses and Other Income (Expense): | $ | (767,455) | | | $ | 3,972 | | | $ | 0 | | | $ | (763,483) | |
| | | | | | | |
| Segment Assets | $ | 3,896,966 | | | $ | 269,337 | | | $ | (276) | | | $ | 4,166,027 | |
| Capital Expenditures | 892,548 | | | 108,198 | | | — | | | 1,000,746 | |
| Investment in Equity Method Investees | 0 | | | 15,487 | | | — | | | 15,487 | |
| Segment EBITDAX | 658,565 | | | 1,187 | | | — | | | 659,752 | |
The following table presents a reconciliation of Adjusted EBITDAX by segment to the same periods inGAAP financial measure of income (loss) before income taxes for the formyears ended December 31, 2020, 2019 and 2018 (in thousands).
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020 | | For the Year Ended December 31, 2019 | | For the Year Ended December 31, 2018 |
| Reconciliation of Adjusted EBITDAX to Income (Loss) Before Income Taxes | | | | |
| Exploration and production segment EBITDAX | $ | 447,919 | | | $ | 607,560 | | | $ | 658,565 | |
| Gathering and facilities segment EBITDAX | 1,256 | | | 3,653 | | | 1,187 | |
| Elimination of intersegment transactions segment EBITDAX | 0 | | | (487) | | | 0 | |
| Subtotal of Reportable Segments | $ | 449,175 | | | $ | 610,726 | | | $ | 659,752 | |
| Less: | | | | | |
| Depletion, depreciation, amortization and accretion | (332,319) | | | (524,537) | | | (435,775) | |
| Impairment of long lived assets | (208,463) | | | (1,337,996) | | | (70,928) | |
| Other operating expenses | (79,615) | | | 0 | | | 0 | |
| Exploration and abandonment expenses | (258,932) | | | (88,794) | | | (31,611) | |
| Gain on sale of property and equipment and assets of unconsolidated subsidiary | 122 | | | (421) | | | 136,834 | |
| Commodity derivative gain (loss) | 164,968 | | | (37,107) | | | (8,554) | |
| Settlements on commodity derivative instruments | (188,822) | | | 5,790 | | | 123,518 | |
| Premiums paid for derivatives that settled during the period | 0 | | | 18,929 | | | 7,148 | |
| Stock-based compensation expense | (6,511) | | | (43,954) | | | (68,349) | |
| Amortization of debt issuance costs | (3,685) | | | (5,482) | | | (13,250) | |
| Interest expense | (53,458) | | | (84,236) | | | (110,080) | |
| Gain on repurchase of 2026 Senior Notes | 0 | | | 10,486 | | | 0 | |
| Loss on deconsolidation of Elevation Midstream, LLC | (73,139) | | | 0 | | | 0 | |
| Reorganization items, net | (676,855) | | | 0 | | | 0 | |
| Income (Loss) Before Income Taxes | $ | (1,267,534) | | | $ | (1,476,596) | | | $ | 188,705 | |
Note 15—19—Supplemental Oil and Gas Reserve Information (Unaudited)
Results of Operations for Oil, Natural Gas and NGL Producing Properties
The following are the results of operations (in thousands) of the Company’s oil and gas producing activities, before corporate overhead and interest expenses. The Company assumed a statutory tax rate of 38%24.7% for allthe years presented, although the Company was not subject to federalended December 31, 2020, 2019 and state income taxes prior to the Corporate Reorganization.2018.
| | | | For the Year Ended | | For the Year Ended |
| | December 31, | | December 31, |
| | 2017 | | 2016 | | 2015 | | 2020 | | 2019 | | 2018 |
| Revenues | $ | 604,296 |
| | $ | 278,089 |
| | $ | 197,750 |
| Revenues | $ | 556,431 | | | $ | 905,374 | | | $ | 1,060,743 | |
| Operating Expenses: | |
| | |
| | |
| Operating Expenses: | | | | | |
| Production expenses | 162,673 |
| | 82,773 |
| | 47,663 |
| Production expenses | 245,426 | | | 218,576 | | | 209,169 | |
| Exploration expenses | 36,256 |
| | 36,422 |
| | 18,636 |
| |
| Depletion and accretion | 311,916 |
| | 203,073 |
| | 144,228 |
| |
| Exploration and abandonment expenses | | Exploration and abandonment expenses | 258,932 | | | 88,794 | | | 31,611 | |
| Depletion, depreciation, amortization and accretion | | Depletion, depreciation, amortization and accretion | 332,319 | | | 524,537 | | | 431,946 | |
| Impairment of proved properties | — |
| | 22,438 |
| | 12,207 |
| Impairment of proved properties | 208,463 | | | 1,337,996 | | | 16,166 | |
| Results of operations before income tax expense | 93,451 |
| | (66,617 | ) | | (24,984 | ) | |
| Income tax (expense) benefit | (35,511 | ) | | 25,314 |
| | 9,494 |
| |
| Results of operations before income tax benefit (expense) | | Results of operations before income tax benefit (expense) | (488,709) | | | (1,264,529) | | | 371,851 | |
| Income tax benefit (expense) | | Income tax benefit (expense) | 120,711 | | | 312,339 | | | (91,847) | |
| Results of Operations | $ | 57,940 |
| | $ | (41,303 | ) | | $ | (15,490 | ) | Results of Operations | $ | (367,998) | | | $ | (952,190) | | | $ | 280,004 | |
Oil, Natural Gas and NGL Reserve Quantities (Unaudited)
The reserves at December 31, 2017, 20162020, 2019 and 20152018 presented below were prepared by the independent engineering firm Ryder Scott Company, L.P. All reserves are located within the DJ Basin. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGL which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The principal methodologies employed are decline curve analysis and analogy. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
The following table sets forth information for the years ended December 31, 2017, 20162020, 2019 and 20152018 with respect to changes in the Company’s proved (i.e., proved developed and undeveloped) reserves:
| | | | | | | | | | | Crude Oil | | Natural Gas | | NGL | | MBoe |
| | Crude Oil | | Natural Gas | | NGL | | MBoe | | Mbbls | | MMcf | | Mbbls | | Total |
| | Mbbls | | MMcf | | Mbbls | | Total | |
| Balance as of December 31, 2014 | 45,164.9 |
| | 166,416.1 |
| | 19,451.0 |
| | 92,352.0 |
| |
| Balance as of December 31, 2017 | | Balance as of December 31, 2017 | 111,275 | | | 626,169 | | | 77,106 | | | 292,742 | |
| Revisions of previous estimates | (2,961.0 | ) | | (2,825.8 | ) | | 2,281.9 |
| | (1,150.1 | ) | Revisions of previous estimates | 6,264 | | | (49,239) | | | (1,383) | | | (3,325) | |
| Purchase of reserves | 11,831.7 |
| | 64,392.7 |
| | 7,533.3 |
| | 30,097.1 |
| Purchase of reserves | 6,296 | | | 24,668 | | | 3,264 | | | 13,672 | |
| Extensions, discoveries, and other additions | 23,098.7 |
| | 85,781.0 |
| | 11,663.4 |
| | 49,058.9 |
| Extensions, discoveries, and other additions | 32,475 | | | 164,424 | | | 22,853 | | | 82,733 | |
| Sale of reserves | (1,688.5 | ) | | (10,357.1 | ) | | (1,212.1 | ) | | (4,626.8 | ) | Sale of reserves | (5,786) | | | (15,907) | | | (1,730) | | | (10,167) | |
| Production | (3,945.6 | ) | | (10,823.0 | ) | | (1,334.6 | ) | | (7,084.0 | ) | Production | (14,679) | | | (46,847) | | | (5,260) | | | (27,747) | |
| Balance as of December 31, 2015 | 71,500.2 |
| | 292,583.9 |
| | 38,382.9 |
| | 158,647.1 |
| |
| Balance as of December 31, 2018 | | Balance as of December 31, 2018 | 135,845 | | | 703,268 | | | 94,850 | | | 347,908 | |
| Revisions of previous estimates | (15,576.8 | ) | | 35,803.1 |
| | 1,988.8 |
| | (7,620.8 | ) | Revisions of previous estimates | (41,255) | | | (118,365) | | | (29,554) | | | (90,537) | |
| Purchase of reserves | 18,473.6 |
| | 78,761.6 |
| | 9,680.7 |
| | 41,281.2 |
| Purchase of reserves | 275 | | | 1,526 | | | 217 | | | 746 | |
| Extensions, discoveries, and other additions | 21,885.4 |
| | 120,798.3 |
| | 14,679.9 |
| | 56,698.5 |
| Extensions, discoveries, and other additions | 14,620 | | | 72,880 | | | 8,425 | | | 35,191 | |
| Sale of reserves | — |
| | — |
| | — |
| | — |
| Sale of reserves | (2,590) | | | (14,510) | | | (1,765) | | | (6,773) | |
| Production | (5,287.4 | ) | | (20,211.5 | ) | | (2,284.0 | ) | | (10,940.0 | ) | Production | (15,436) | | | (64,710) | | | (6,164) | | | (32,386) | |
| Balance as of December 31, 2016 | 90,995.0 |
| | 507,735.4 |
| | 62,448.3 |
| | 238,066.0 |
| |
| Balance as of December 31, 2019 | | Balance as of December 31, 2019 | 91,459 | | | 580,089 | | | 66,009 | | | 254,149 | |
| Revisions of previous estimates | (625.9 | ) | | 9,349.8 |
| | 1,961.6 |
| | 2,894.0 |
| Revisions of previous estimates | (38,281) | | | (163,718) | | | (21,741) | | | (87,308) | |
| Purchase of reserves | 10,761.2 |
| | 11,183.6 |
| | 1,563.3 |
| | 14,188.3 |
| Purchase of reserves | 0 | | | 0 | | | 0 | | | 0 | |
| Extensions, discoveries, and other additions | 19,738.4 |
| | 130,295.4 |
| | 15,033.6 |
| | 56,487.9 |
| Extensions, discoveries, and other additions | 5,347 | | | 31,035 | | | 3,025 | | | 13,545 | |
| Sale of reserves | — |
| | — |
| | — |
| | — |
| Sale of reserves | (590) | | | (5,561) | | | (453) | | | (1,971) | |
| Production | (9,593.7 | ) | | (32,395.2 | ) | | (3,900.8 | ) | | (18,893.7 | ) | Production | (12,543) | | | (72,311) | | | (7,945) | | | (32,540) | |
| Balance as of December 31, 2017 | 111,275.0 |
| | 626,169.0 |
| | 77,106.0 |
| | 292,742.5 |
| |
| Balance as of December 31, 2020 | | Balance as of December 31, 2020 | 45,392 | | | 369,534 | | | 38,895 | | | 145,875 | |
| Proved Developed Reserves, included above | | | | | | | | Proved Developed Reserves, included above | | | | | | | |
| Balance as of December 31, 2015 | 14,248.6 |
| | 53,011.7 |
| | 7,058.3 |
| | 30,142.3 |
| |
| Balance as of December 31, 2016 | 17,158.0 |
| | 107,918.0 |
| | 13,354.0 |
| | 48,498.4 |
| |
| Balance as of December 31, 2017 | 37,078.0 |
| | 222,236.0 |
| | 27,932.0 |
| | 102,049.3 |
| |
| Balance as of December 31, 2018 | | Balance as of December 31, 2018 | 47,075 | | | 316,499 | | | 39,689 | | | 139,514 | |
| Balance as of December 31, 2019 | | Balance as of December 31, 2019 | 45,807 | | | 350,309 | | | 39,001 | | | 143,193 | |
| Balance as of December 31, 2020 | | Balance as of December 31, 2020 | 33,367 | | | 288,769 | | | 30,797 | | | 112,292 | |
| Proved Undeveloped Reserves, included above | | | | | | | | Proved Undeveloped Reserves, included above | | | | | | | |
| Balance as of December 31, 2015 | 57,251.5 |
| | 239,572.2 |
| | 31,324.6 |
| | 128,504.8 |
| |
| Balance as of December 31, 2016 | 73,837.0 |
| | 399,817.4 |
| | 49,094.3 |
| | 189,567.5 |
| |
| Balance as of December 31, 2017 | 74,197.0 |
| | 403,933.0 |
| | 49,174.0 |
| | 190,693.2 |
| |
| Balance as of December 31, 2018 | | Balance as of December 31, 2018 | 88,771 | | | 386,769 | | | 55,162 | | | 208,395 | |
| Balance as of December 31, 2019 | | Balance as of December 31, 2019 | 45,652 | | | 229,781 | | | 27,008 | | | 110,957 | |
| Balance as of December 31, 2020 | | Balance as of December 31, 2020 | 12,025 | | | 80,765 | | | 8,098 | | | 33,583 | |
•The values for the 20172020 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2017.2020. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $51.34$39.57 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.98$1.99 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 20172020 was $42.89$33.60 per barrel for oil, $1.73$0.35 per Mcf for natural gas and $20.28$10.45 per barrel for NGL.
•The values for the 20162019 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2016.2019. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $42.75 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.49 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2016 was $34.91 per barrel for oil, $1.39 per Mcf for natural gas and $11.63 per barrel for NGL.
The values for the 2015 oil, natural gas and NGL reserves are based on the 12 month arithmetic average of the first day of the month prices for the period from January through December 31, 2015. The unweighted arithmetic average first-day-of-month prices for the prior twelve months were $50.28$55.69 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.58 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2019 was $48.09 per barrel for oil, $1.04 per Mcf for natural gas and $13.87 per barrel for NGL.
•The values for the 2018 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2018. The unweighted arithmetic average first-day-of-month prices for the prior twelve months were $65.56 per barrel (West Texas Intermediate price) for crude oil and NGL and $3.10 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and
basis differentials. The average resulting price used as of December 31, 20152018 was $43.28$57.65 per barrel for oil, $2.11$1.47 per Mcf for natural gas and $10.65$20.45 per barrel for NGL.
For the year ended December 31, 2017,2020, the Company had upwarddownward revisions of previous estimates of 2,894.087,308 MBoe primarily due to revisions of PUD expirations due to the SEC’s five year drilling rule caused by the change in business strategy to focus on being cash flow positive rather than maximizing reserves growth. Additionally, downward revisions were due to altering the development plan to increase the spacing between wellbores, thus drilling fewer wells, as well as negative performance revisions. As a result of ongoing drilling and completion activities during 2020, the Company reported extensions, discoveries, and other additions of 13,545 MBoe. Additionally, during 2020 the Company sold reserves of 1,971 MBoe and purchased 0 reserves.
For the year ended December 31, 2019, the Company had downward revisions of previous estimates of 90,537 MBoe. As a result of ongoing drilling and completion activities during 2017,2019, the Company reported extensions, discoveries, and other additions of 56,487.935,191 MBoe. Additionally, during 20172019 the Company sold reserves of 6,773 MBoe and purchased reserves of 14,188.3746 MBoe.
For the year ended December 31, 2016,2018, the Company had downward revisions of previous estimates of 7,620.83,325 MBoe. As a result of ongoing drilling and completion activities during 2016,2018, the Company reported extensions, discoveries, and other additions of 56,698.582,733 MBoe. Additionally, during 20162018 the Company sold reserves of 10,167 MBoe and purchased reserves of 41,281.2 MBoe.
For the year ended December 31, 2015, the Company had upward revisions of previous estimates of 1,150.1 MBoe. These revisions are primarily the result of well performance exceeding previous estimates. As a result of ongoing drilling and completion activities during 2015, the Company reported extensions, discoveries, and other additions of 49,058.9 MBoe. Additionally, during 2015 the Company purchased reserves of 30,097.113,672 MBoe.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves
The Company follows the guidelines prescribed in ASC 932, Extractive Activities-Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.
The information is based on estimates of proved reserves attributable to the Company’s interest in oil and gas properties as of December 31 of the years presented. These estimates were prepared by Ryder Scott Company L.P., independent petroleum engineers.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions. (2) The estimated future cash flows are compiled by applying the trailing twelve monthtwelve-month average of the first of the month prices applied to the Company’s proved reserve year-end quantities. (3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred. (4) Future net cash flows are discounted to present value by applying a discount rate of 10%.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
The following are the principal sources
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Future crude oil, natural gas and NGL sales | $ | 7,422,335 |
| | $ | 4,610,848 |
| | $ | 4,119,888 |
|
| Future production costs | (2,227,370 | ) | | (1,429,202 | ) | | (1,193,560 | ) |
| Future development costs | (1,662,859 | ) | | (1,579,628 | ) | | (1,141,330 | ) |
| Future income tax expense | (212,923 | ) | | (42,859 | ) | | — |
|
| Future net cash flows | $ | 3,319,183 |
| | $ | 1,559,159 |
| | $ | 1,784,998 |
|
| 10% annual discount | (1,440,177 | ) | | (836,163 | ) | | (949,115 | ) |
Standardized measure of discounted future net cash flows(1) | $ | 1,879,006 |
| | $ | 722,996 |
| | $ | 835,883 |
|
| |
(1) | The Company’s calculations of the standardized measure of discounted future net cash flows does not include the effect of estimated future income tax expenses for the year ended December 31, 2015 as the Company was a limited liability company and not subject to income taxes. For the years ended December 31, 2017 and 2016, future income tax expenses in the Company’s calculation of the standardized measure of discounted future net cash flows are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credit and allowances relating to the Company’s proved reserves. For purposes of the standardized measure calculation, it was assumed that all of the Company’s operations are attributable to the Company’s oil and gas assets. If the Company had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2015 would have been $327.9 million and the unaudited standardized measure would have been $680.3 million. |
The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC 932, Extractive Activities-Oil and Gas (in thousands):
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Future crude oil, natural gas and NGL sales | $ | 2,062,787 | | | $ | 5,914,900 | | | $ | 10,805,063 | |
| Future production costs | (732,455) | | | (2,166,852) | | | (3,215,840) | |
| Future development costs | (209,074) | | | (798,225) | | | (1,912,641) | |
| Future income tax expense | 0 | | | (7,647) | | | (694,398) | |
| Future net cash flows | $ | 1,121,258 | | | $ | 2,942,176 | | | $ | 4,982,184 | |
| 10% annual discount | (326,825) | | | (1,038,303) | | | (2,082,201) | |
| Standardized measure of discounted future net cash flows (1) | $ | 794,433 | | | $ | 1,903,873 | | | $ | 2,899,983 | |
(1)For the years ended December 31, 2020, 2019 and 2018, future income tax expenses in the Company’s calculation of the standardized measure of discounted future net cash flows are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credit and allowances relating to the Company’s proved reserves. For purposes of the standardized measure calculation, it was assumed that all of the Company’s operations are attributable to the Company’s oil and gas assets.
The following are the principal sources of change in the standardized measure (in thousands): |
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Balance at beginning of period | $ | 722,996 |
| | $ | 835,883 |
| | $ | 1,387,472 |
|
| Sales of crude oil, natural gas and NGL, net | (441,623 | ) | | (195,316 | ) | | (150,087 | ) |
| Net change in prices and production costs | 586,271 |
| | (325,236 | ) | | (1,292,364 | ) |
| Net change in future development costs | 3,959 |
| | (49,213 | ) | | 175,944 |
|
| Extensions and discoveries | 330,160 |
| | 96,982 |
| | 284,216 |
|
| Acquisitions of reserves | 59,745 |
| | 156,675 |
| | 240,989 |
|
| Sale of reserves | — |
| | — |
| | (50,018 | ) |
| Revisions of previous quantity estimates | 188,421 |
| | 19,161 |
| | (28,391 | ) |
| Previously estimated development costs incurred | 331,550 |
| | 123,085 |
| | 102,060 |
|
| Net changes in income taxes | (79,181 | ) | | (17,611 | ) | | — |
|
| Accretion of discount | 74,061 |
| | 83,588 |
| | 156,723 |
|
| Other | 102,647 |
| | (5,002 | ) | | 9,339 |
|
| Balance at end of period | $ | 1,879,006 |
| | $ | 722,996 |
| | $ | 835,883 |
|
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Balance at beginning of period | $ | 1,903,873 | | | $ | 2,899,983 | | | $ | 1,879,006 | |
| Sales of crude oil, natural gas and NGL, net | (306,711) | | | (681,667) | | | (851,574) | |
| Net change in prices and production costs | (594,367) | | | (878,838) | | | 902,762 | |
| Net change in future development costs | 60,901 | | | 3,147 | | | (174,112) | |
| Extensions and discoveries | 62,858 | | | 256,147 | | | 629,304 | |
| Acquisitions of reserves | 0 | | | 9,623 | | | 88,124 | |
| Sale of reserves | (15,506) | | | (52,710) | | | (55,042) | |
| Revisions of previous quantity estimates | (559,839) | | | (560,397) | | | 132,373 | |
| Previously estimated development costs incurred | 115,095 | | | 348,137 | | | 306,546 | |
| Net changes in income taxes | 2,779 | | | 347,057 | | | (253,044) | |
| Accretion of discount | 172,408 | | | 324,981 | | | 197,580 | |
| Changes in production timing and other | (47,058) | | | (111,590) | | | 98,060 | |
| Balance at end of period | $ | 794,433 | | | $ | 1,903,873 | | | $ | 2,899,983 | |
Note 16—20—Unaudited Quarterly Financial Data
The following is a summary of the unaudited quarterly financial data for each of the quarters from first quarter 20162019 through fourth quarter 20172020 (in thousands, except per share data). Historical results are not necessarily indicative of the results to be expected in future periods. YouThis data should be read this data together with the Company'sCompany’s consolidated financial statements and the related notes included elsewhere in this Annual Report:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended |
| | March 31, | | June 30, | | September 30, | | December 31, |
| | 2017 | | 2017 | | 2017 | | 2017 |
| Oil, Natural gas and NGL sales | $ | 89,639 |
| | $ | 119,766 |
| | $ | 180,861 |
| | $ | 214,030 |
|
Operating Income (1) | $ | 10,210 |
| | $ | 16,480 |
| | $ | 41,084 |
| | $ | 58,850 |
|
| Net Income (Loss) | $ | 8,716 |
| | $ | 7,240 |
| | $ | (29,796 | ) | | $ | (30,568 | ) |
| Basic and Diluted Income (Loss) Per Common Share | $ | 0.03 |
| | $ | 0.02 |
| | $ | (0.20 | ) | | $ | (0.20 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For The Three Months Ended |
| | | March 31, | | June 30, | | September 30, | | December 31, |
| | | 2020 | | 2020 | | 2020 | | 2020 |
| Total Revenues | $ | 165,187 | | | $ | 63,129 | | | $ | 158,226 | | | $ | 171,362 | |
| Operating Income (Loss) (1) | 18,573 | | | (73,460) | | | 8,657 | | | 22,454 | |
| Net Income (Loss) (2) | 9,037 | | | (291,934) | | | (540,607) | | | (444,030) | |
| Basic and Diluted Loss Per Common Share | (0.03) | | | (2.16) | | | (3.92) | | | (3.22) | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended |
| | March 31, | | June 30, | | September 30, | | December 31, |
| | 2016 | | 2016 | | 2016 | | 2016 |
| Oil, Natural gas and NGL sales | $ | 45,133 |
| | $ | 65,364 |
| | $ | 72,902 |
| | $ | 94,690 |
|
Operating Income (Loss) (1) | $ | (16,635 | ) | | $ | (3,593 | ) | | $ | 4,556 |
| | $ | 5,640 |
|
| Net Loss | $ | (45,519 | ) | | $ | (127,614 | ) | | $ | (37,267 | ) | | $ | (245,601 | ) |
| Basic and Diluted Loss Per Common Share | |
| | |
| | |
| | $ | (1.54 | ) |
133
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For The Three Months Ended |
| | | March 31, | | June 30, | | September 30, | | December 31, |
| | | 2019 | | 2019 | | 2019 | | 2019 |
| Total Revenues | $ | 221,917 | | | $ | 222,057 | | | $ | 176,942 | | | $ | 285,720 | |
| Operating Income (1) | 52,796 | | | 49,647 | | | 22,334 | | | 36,488 | |
| Net Income (Loss) (3) | (94,032) | | | 43,444 | | | 33,924 | | | (1,350,758) | |
| Basic and Diluted Income (Loss) Per Common Share | (0.60) | | | 0.22 | | | 0.17 | | | (9.84) | |
| | | | | | | | |
(1) Total revenues less lease operating expenses, midstream operating expenses, transportation and gathering expenses, production taxes and depreciation, depletion, amortization and accretion expenses.
(2) The first quarter of 2020 contains a $73.1 million loss on the deconsolidation of Elevation Midstream, LLC. The third and fourth quarters of 2020 contain $528.0 million and $148.9 million, respectively, of reorganization items, net due to the Chapter 11 Cases.
(3) The fourth quarter of 2019 contains a $1.3 billion impairment of proved oil and gas properties in the Company’s Core DJ Basin field.
| |
(1) | Oil, Natural gas and NGL sales revenue less lease operating expenses, production taxes and depreciation, depletion, amortization and accretion. |
| |
(2) | EPS for the year ended December 31, 2016 is calculated for the period from October 12, 2016, the effective date of the Corporate Reorganization, to December 31, 2016. EPS information is not applicable for reporting periods prior to the Corporate Reorganization. |
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
In accordance with the Securities Exchange Act, of 1934, as amended (the "Exchange Act"), Rules 13a-15(b) and 15d-15(b), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2017.2020. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 20172020 at the reasonable assurance level.
Remediation of a Previously Reported Material Weakness
During 2019, management determined that the Company did not design and maintain effective controls to determine the appropriate contract termination date and evaluate the potential accounting implications of changes in termination dates of contracts with customers. This material weakness resulted in a restatement of the Company’s condensed consolidated financial statements as of and for the three and nine month periods ended September 30, 2019 and immaterial errors to the consolidated financial statements for the periods ended December 31, 2018, March 31, 2019 and June 30, 2019. The line items affected were oil revenue, accounts payable and accrued liabilities, other non-current liabilities, inventory, prepaid expenses and other, and other non-current assets.
The Company and its Board are committed to maintaining a strong internal control environment. During 2020, management undertook a remediation plan to redesign and enhance existing controls to determine the appropriate contract termination date of new and amended revenue contracts and to evaluate the potential accounting implications of changes in termination dates of contracts with customers pursuant to the accounting treatment under ASC 606 - Revenue from Contracts with Customers. The remediation plan was implemented during 2020, and management determined that the enhancements to the design of our control activities related to determining the appropriate contract termination for contracts with customers have been satisfactorily implemented and have operated effectively for a sufficient period of time. Therefore, management concluded the previously reported material weakness is remediated as of December 31, 2020.
Management’s Annual Report on Internal Control over Financial Reporting
Our management, including our principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated 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 the policies or procedures may deteriorate.
OurAs of December 31, 2020, management assessed the effectiveness of the Company'sour internal control over financial reporting as of December 31, 2017, usingreporting. In making this assessment, management, including our principal executive officer and principal financial officer, used the criteria established in set forth by the Internal Control-IntegratedControl - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"(“COSO”). Based on this assessment, management determinedour principal executive officer and principal financial officer have concluded that our internal control over financial reporting was effective as of December 31, 2017.2020.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this annual report on Form 10-K, has also audited the effectiveness
Changes in Internal Control over Financial Reporting
There were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 20172020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The information responsiverequired by this item will be provided in an amendment to Items 401, 405, 406 and 407 of Regulation S-K to be included in our definitive Proxy Statement for our 2018this Annual Meeting of Shareholders, to be filed within 120 days of December 31, 2017, pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the “2018 Proxy Statement”), is incorporated herein by reference.Report on Form 10-K/A.
ITEM 11.EXECUTIVE COMPENSATION
The information responsiverequired by this item will be provided in an amendment to Items 402 and 407 of Regulation S-K to be included in our 2018 Proxy Statement is incorporated herein by reference.this Annual Report on Form 10-K/A.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information responsiverequired by this item will be provided in an amendment to Items 201(d) and 403 of Regulation S-K to be included in our 2018 Proxy Statement is incorporated herein by reference.this Annual Report on Form 10-K/A.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information responsiverequired by this item will be provided in an amendment to Items 404 and 407 of Regulation S-K to be included in our 2018 Proxy Statement is incorporated herein by reference.this Annual Report on Form 10-K/A.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information responsiverequired by this item will be provided in an amendment to Item 9(e)this Annual Report on Form 10-K/A.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents Filed With This Report
1. FINANCIAL STATEMENTS
The following consolidated financial statements of the Company are filed as a part of this report:
2. FINANCIAL STATEMENT SCHEDULES
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements and related notes.
3. EXHIBITS
The exhibits to this report required to be filed pursuant to Item 15(b) are listed below in the “Index to Exhibits” attached hereto and are incorporated herein by reference.
INDEX TO EXHIBITS
|
| | | | | | | |
Exhibit
Number
| | Description |
| | |
| *2.2 | | |
| | |
| *3.2 | | |
| | |
| †*10.1 | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| |
|
| | |
| |
|
| *10.3 | | |
| | |
| *10.4 | | |
| | |
| | |
| | Amended and RestatedRBL Credit Agreement dated as of August 16, 2017, by and betweenJanuary 20, 2021, among Extraction Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and issuing lender, and the lenders and other parties party thereto (incorporated(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (file No. 001-37907) filed with the Commission on August 21, 2017). |
| | |
| | Increase Agreement, Joinder and Amendment No. 1 to Amended and Restated Credit Agreement, dated as of October 11, 2017, by and between Extraction Oil & Gas, Inc., as borrower, certain subsidiaries of the Company, as guarantors, Wells Fargo Bank, National Association, as administrative agent and issuing lender and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 13, 2017)January 20, 2021). |
| *10.5 | | |
| | |
| | | | | | | | |
| †*10.6 | | |
| †*10.7 | | |
| 10.8 | | |
| †*10.9 | | |
| †*10.10 | | |
| †*10.11 | | |
| †*10.12 | | |
| *10.13 | | |
| †*10.14 | | |
| †*10.15 | | |
| †*10.16 | | |
| **21.1 | | |
| **23.1 | | |
| | |
| **23.2 | | |
| | |
| **31.1 | | |
| |
|
|
| **31.2 | | |
| | |
| |
|
| **32.1 | | |
| | |
| **32.2 | | |
| | |
| **99.1 | | |
| | |
| **101 | | |
*101 | | Interactive Data Files |
| † | | Management contract or compensatory plan or agreement. |
| * | | Previously Filed. |
| ** | | Filed herewith. |
† Management contract or compensatory plan or agreement.
* Filed herewith.
** Previously filed.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements 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.
Date: February 27, 2018.March 18, 2021.
|
| | | | | | | |
| Extraction Oil & Gas, Inc. |
| | |
| By: | /s/ MARK A. ERICKSONThomas B. Tyree Jr. |
| | Mark A. EricksonThomas B. Tyree Jr. |
| | Chairman and Chief Executive Officer
(Principal Executive Officer)
and Director |
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.
| | | | | | | | | | | | | | |
| | | | |
/s/ RUSSELL T. KELLEY, JR.Thomas B. Tyree Jr. | | Chief Executive Officer and Director | | March 18, 2021 |
| Thomas B. Tyree Jr. | | (Principal Executive Officer) | | |
| | | | |
| /s/ Marianella Foschi | | Chief Financial Officer (Principal | | March 18, 2021 |
| Marianella Foschi | | (Principal Financial Officer) | | February 27, 2018 |
Russell T. Kelley, Jr. | | | | |
| | | | |
/s/ TOMTom L. BROCKBrock | | Vice President, Chief Accounting Officer (Principal Accounting Officer) | | February 27, 2018March 18, 2021 |
| Tom L. Brock | | (Principal Accounting Officer) | | |
| | | | |
/s/ MATTHEW R. OWENSBenjamin Dell | | President and Director | | February 27, 2018March 18, 2021 |
Matthew R. OwensBenjamin Dell | | | | |
| | | | |
/s/ JOHN S. GAENSBAUERCarney Hawks | | Director | | February 27, 2018March 18, 2021 |
John S. GaensbauerCarney Hawks | | | | |
| | | | |
/s/ PETER A. LEIDELCarrie M. Fox | | Director | | February 27, 2018March 18, 2021 |
Peter A. LeidelCarrie M. Fox | | | | |
| | | | |
/s/ MARVIN M. CHRONISTERHoward A. Willard, III | | Director | | February 27, 2018March 18, 2021 |
Marvin M. ChronisterHoward A. Willard, III | | | | |
| | | | |
/s/ PATRICK D. O’BRIENMichael Wichterich | | Director | | February 27, 2018March 18, 2021 |
Patrick D. O’BrienMichael Wichterich | | | | |
| | | | |
/s/ WAYNE W. MURDYMorris R. Clark | | Director | | February 27, 2018March 18, 2021 |
Wayne W. MurdyMorris R. Clark | | | | |
| | | | |
/s/ DONALD L. EVANS | | Director | | February 27, 2018 |
Donald L. Evans | | | | |
| | | | |
| | | | |
