Diamondback Energy, Inc.
ITEM 1A. RISK FACTORS
The nature of our business activities subjects us to certain hazards and risks. The following is a summary of some of the material risks relating to our business activities. Other risks are described in Item 1. “Business and Properties,” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” These risks are not the only risks we face. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline.
Risks Relating to the Pending Merger
The pending merger may not be completed and the merger agreement may be terminated in accordance with its terms. Failure to complete the pending merger could negatively impact the price of shares of our common stock and our future businesses and financial results.
The pending merger is subject to a number of conditions that must be satisfied, including the approval by QEP stockholders of the merger agreement proposal, or, to the extent permitted by applicable law, waived, in each case prior to the completion of the pending merger. The conditions to the completion of the pending merger, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all, and, accordingly, the pending merger may be delayed or may not be completed.
In addition, if the pending merger is not completed by June 30, 2021, or, in certain instances, on or before September 30, 2021, either we or QEP may choose not to proceed with the pending merger by terminating the merger agreement, and the parties can mutually decide to terminate the merger agreement at any time, before or after stockholder approval. Further, either we or QEP may elect to terminate the merger agreement in certain other circumstances specified in the merger agreement. If the transactions contemplated by the merger agreement are not completed for any reason, our ongoing business, financial condition and financial results may be adversely affected. Without realizing any of the benefits of having completed the transactions, we will be subject to a number of risks, including the following:
•we may be required to pay our costs relating to the transactions, which are substantial, such as legal, accounting, financial advisory and printing fees, whether or not the transactions are completed;
•time and resources committed by our management to matters relating to the transactions could otherwise have been devoted to pursuing other beneficial opportunities;
•we may experience negative reactions from financial markets, including negative impacts on the price of our common stock, including to the extent that the current market price reflects a market assumption that the transactions will be completed;
•we may experience negative reactions from employees, customers or vendors; and
•since the merger agreement restricts the conduct of our business prior to completion of the pending merger, we may not have been able to take certain actions during the pendency of the merger that would have benefitted us as an independent company and the opportunity to take such actions may no longer be available.
We will be subject to business uncertainties while the merger is pending, which could adversely affect our business.
Uncertainty about the effect of the pending merger on employees, industry contacts and business partners may have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate key personnel until the pending merger is completed and for a period of time thereafter and could cause industry contacts, business partners and others that deal with us to seek to change their existing business relationships with us. In addition, the merger agreement restricts the parties to the merger agreement from entering into certain corporate transactions and taking other specified actions without the consent of the other party. These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of the pending merger.
We will incur significant transaction and merger-related costs in connection with the pending merger, which may be in excess of those anticipated by us.
We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the pending merger, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the pending merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees.
We will also incur transaction fees and costs related to the integration of the companies, which may be substantial. Moreover, we may incur additional unanticipated expenses in connection with the pending merger and the integration, including costs associated with any stockholder litigation related to the pending merger. Although we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, should allow us to offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all. The costs described above, as well as other unanticipated costs and expenses, could have a material adverse effect on the financial condition and operating results of the combined company following the completion of the pending merger.
We and our subsidiaries will have substantial indebtedness after giving effect to the pending merger, which may limit our financial flexibility and adversely affect our financial results.
Under the merger agreement, QEP’s outstanding debt (other than its existing credit facility) will remain outstanding, which debt, as of December 31, 2020 was approximately $1.6 billion and consisted of amounts outstanding under QEP’s senior notes. As of December 31, 2020, we had total long-term debt of approximately $5.6 billion, consisting primarily of the amounts outstanding under our revolving credit facility, our senior unsecured notes, the notes issued by our subsidiary Energen Corporation, the senior notes issued by our publicly traded subsidiaries, Viper and Rattler, and the amounts outstanding under Viper’s and Rattler’s revolving credit facilities.
Our pro forma indebtedness as of December 31, 2020, assuming consummation of the pending merger had occurred on such date and QEP’s senior notes remain outstanding, would have been approximately $7.4 billion, representing an increase in comparison to our indebtedness on a recent historical basis. We believe that post-merger we will retain our investment grade credit ratings and retire the combined company’s pro forma debt at a faster rate than either company would have been able to do absent the pending merger. However, any increase in our indebtedness could have adverse effects on our financial condition and results of operations, including:
•increasing difficulty to satisfy our obligations with respect to our debt obligations, including any repurchase obligations that may arise thereunder;
•diverting a significant portion of our cash flows to service our indebtedness, which could reduce the funds available to us for operations and other purposes;
•increasing our vulnerability to general adverse economic and industry conditions;
•placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that we would be unable to pursue due to our indebtedness;
•limiting our ability to access the capital markets to raise capital on favorable terms;
•impairing our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and
•increasing our vulnerability to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.
We believe that the combined company will have flexibility to repay, refinance, repurchase, redeem, exchange or otherwise terminate large portions of our outstanding debt obligations. However, there can be no guarantee that we would be able to execute such refinancings on favorable terms or at all, and a high level of indebtedness increases the risk that we may default on our debt obligations, including from the debt obligations of QEP. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. Our future performance depends on many factors independent of the pending merger, some of which are beyond our control, such as general economic conditions and oil and natural gas prices. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.
Lawsuits have been filed against QEP, us, Merger Sub and the members of the QEP board in connection with the merger and additional lawsuits may be filed in the future. An adverse ruling in any such lawsuit could result in an injunction preventing the completion of the merger and/or substantial costs to us and QEP.
Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements like the merger agreement. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources.
As of February 22, 2021, nine individual lawsuits have been filed by purported QEP stockholders in United States District Courts in connection with the proposed merger. All nine lawsuits name QEP and the members of the QEP board as defendants, and two of the nine lawsuits name us and Merger Sub as defendants. The complaints allege, among other things, that the registration statements relating to the merger on Form S-4 filed by us on January 22, 2021, as amended on Form S-4/A filed on February 3, 2021, and the Schedule 14A Definitive Proxy Statement filed by QEP on February 10, 2021 fail to provide certain allegedly material information concerning the proposed merger in violation of Sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9 promulgated thereunder. In addition to these allegations, some of the complaints allege that the merger consideration to be received by the QEP stockholders in the merger is unfair because the value of the QEP common
stock is in excess of the value of the merger consideration, that the "no solicitation" clause in the merger agreement is improper and that the termination fee contemplated by the merger agreement is excessive. Some of the complaints also assert a breach of fiduciary duty claim under state law against individual QEP board members. Among other remedies, the plaintiffs seek to enjoin the completion of the proposed merger, a recission of the completed merger or rescissory damages, an accounting of damages suffered by the plaintiff, an award of plaintiff’s expenses and attorney’s fees, and other relief.
Each of us and QEP believes that the allegations in the complaints are without merit. Additional lawsuits arising out of the merger may also be filed in the future.
One of the conditions to the closing of the merger is that no injunction by any governmental entity having jurisdiction over us, QEP or Merger Sub has been entered and continues to be in effect and no law has been adopted, in either case that prohibits the closing of the merger. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the merger, that injunction may delay or prevent the merger from being completed within the expected timeframe or at all, which may adversely affect our business, financial position and results of operations.
Additionally, there can be no assurance that any of the defendants will be successful in the outcome of the lawsuits filed thus far or any potential future lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect our business, financial condition, results of operations and cash flows.
Risk Factors Relating to Diamondback Following the Completion of the Pending Merger
The integration of QEP into our business may not be as successful as anticipated, and we may not achieve the intended benefits or do so within the intended timeframe.
The pending merger involves numerous operational, strategic, financial, accounting, legal, tax and other risks, potential liabilities associated with the acquired businesses, and uncertainties related to design, operation and integration of QEP’s internal control over financial reporting. Difficulties in integrating QEP into our business may result in us performing differently than expected, operational challenges, or the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:
•the inability to successfully integrate QEP into our business in a manner that permits us to achieve the full revenue and cost savings anticipated from the pending merger;
•complexities associated with managing the larger, more complex, integrated business;
•not realizing anticipated operating synergies;
•integrating personnel from the two companies and the loss of key employees;
•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the pending merger;
•integrating relationships with industry contacts and business partners;
•performance shortfalls as a result of the diversion of management’s attention caused by completing the pending merger and integrating QEP’s operations into our operations; and
•the disruption of, or the loss of momentum in, ongoing business or inconsistencies in standards, controls, procedures and policies.
Additionally, the success of the pending merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and QEP’s businesses, including operational and other synergies that we believe the combined company will achieve. The anticipated benefits and cost savings of the pending merger may not be realized fully or at all, may take longer to realize than expected, or could have other adverse effects that we do not currently foresee.
Our results may suffer if we do not effectively manage our expanded operations following the pending merger.
The success of the pending merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and QEP’s businesses, including the need to integrate the operations and business of QEP into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors, industry contacts and business partners.
The anticipated benefits and cost savings of the pending merger may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of operating synergies, may not be realized. There could also be unknown liabilities and unforeseen expenses associated with the pending merger that were not discovered in the due diligence review conducted by each company prior to entering into the merger agreement.
The pending merger may not be accretive, and may be dilutive, to our earnings per share, which may negatively affect the market price of our common stock.
Because shares of our common stock will be issued in the pending merger, it is possible that, although we currently expect the merger to be accretive to earnings per share, the merger may be dilutive to our earnings per share, which could negatively affect the market price of our common stock.
In connection with the completion of the pending merger, based on the number of issued and outstanding shares of QEP common stock as of February 22, 2021 and the number of outstanding QEP equity awards currently estimated to be payable in our common stock following the merger, we will issue up to approximately 12.4 million shares of our common stock. The issuance of these new shares of our common stock could have the effect of depressing the market price of our common stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, our earnings per share could cause the price of shares of our common stock to decline or increase at a reduced rate.
Furthermore, our current stockholders may not wish to continue to invest in the additional operations of the combined company, or for other reasons may wish to dispose of some or all of their interests in the combined company, and as a result may seek to sell their shares of our common stock following, or in anticipation of, completion of the pending merger. The merger agreement does not restrict the ability of former QEP stockholders to sell such shares of our common stock following completion of the pending merger. Therefore, these sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of our common stock, may affect the market for, and the market price of, our common stock in an adverse manner.
If the pending merger is completed and our stockholders, including former QEP stockholders, sell substantial amounts of our common stock in the public market following the consummation of the pending merger, the market price of our common stock may decrease. These sales might also make it more difficult for us to raise capital by selling equity or equity-related securities at a time and price that it otherwise would deem appropriate.
The market price of our common stock will continue to fluctuate after the pending merger, and may decline if the benefits of the pending merger do not meet the expectations of financial analysts.
Upon completion of the pending merger, holders of QEP common stock who receive merger consideration will become holders of shares of our common stock. The market price of our common stock may fluctuate significantly following completion of the pending merger and holders of QEP common stock could lose some or all of the value of their investment in our common stock. In addition, the stock market has recently experienced significant price and volume fluctuations which could, if such fluctuations continue to occur, have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.
The market price of our common stock may be affected by factors different from those that historically have affected QEP common stock or our common stock.
Our business differs from that of QEP in certain respects, and, accordingly, our financial position or results of operations and/or cash flows after the pending merger is completed, as well as the market price of our common stock, may be affected by factors different from those currently affecting our financial position or results of operations and/or cash flows as an independent standalone company.
Following the completion of the pending merger, we may incorporate QEP’s hedging activities into our business and, as a result, may be exposed to additional commodity price risks arising from such hedges.
To mitigate its exposure to changes in commodity prices, QEP hedges oil and natural gas prices from time to time, primarily through the use of certain derivative instruments. If we assume QEP’s existing derivative instruments or if QEP enters into additional derivative instruments prior to the completion of the pending merger, we will bear the economic impact of the contracts following the completion of the pending merger. Actual crude oil and natural gas prices may differ from the combined company’s expectations and, as a result, such derivative instruments may have a negative impact on our business.
The combined company may record goodwill and other intangible assets that could become impaired and result in material non-cash charges to the results of operations of the combined company in the future.
The pending merger will be accounted for as an acquisition by us in accordance with GAAP. Under the acquisition method of accounting, the assets and liabilities of QEP and its subsidiaries will be recorded, as of completion of the pending merger, at their respective fair values and added to those of us. Our reported financial condition and results of operations for the periods after completion of the pending merger will reflect QEP balances and results after completion of the pending
merger but will not be restated retroactively to reflect the historical financial position or results of operations of QEP and its subsidiaries for periods prior to the completion of the pending merger.
Under the acquisition method of accounting, the total purchase price will be allocated to QEP’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of the date of completion of the pending merger. The excess of the purchase price over those fair values will be recorded as goodwill. We expect that the pending merger may result in the creation of goodwill based upon the application of the acquisition method of accounting. To the extent goodwill or intangibles are recorded and the values become impaired, the combined company may be required to recognize material non-cash charges relating to such impairment. The combined company’s operating results may be significantly impacted from both the impairment and underlying trends in the business that triggered the impairment.
The combined company may not be able to retain customers or suppliers, and customers or suppliers may seek to modify contractual obligations with the combined company, either of which could have an adverse effect on the combined company’s business and operations. Third parties may terminate or alter existing contracts or relationships with us as a result of the pending merger.
As a result of the pending merger, the combined company may experience impacts on relationships with customers and suppliers that may harm the combined company’s business and results of operations. Certain customers or suppliers may seek to terminate or modify contractual obligations following the completion of the pending merger whether or not contractual rights are triggered as a result of the pending merger. There can be no guarantee that customers and suppliers will remain with or continue to have a relationship with the combined company or do so on the same or similar contractual terms following the closing of the pending merger. If any customers or suppliers seek to terminate or modify contractual obligations or discontinue their relationships with the combined company, then the combined company’s business and results of operations may be harmed. If the combined company’s suppliers were to seek to terminate or modify an arrangement with the combined company, then the combined company may be unable to procure necessary supplies or services from other suppliers in a timely and efficient manner and on acceptable terms, or at all.
QEP also has contracts with vendors, landlords, licensors and other business partners which may require QEP to obtain consent from these other parties in connection with the pending merger. If these consents cannot be obtained, the combined company may suffer a loss of potential future revenue, incur costs and/or lose rights that may be material to the business of the combined company. In addition, third parties with whom Diamondback or QEP currently have relationships may terminate or otherwise reduce the scope of their relationship with either party in anticipation of the closing of the pending merger. Any such disruptions could limit the combined company’s ability to achieve the anticipated benefits of the pending merger. The adverse effect of any such disruptions could also be exacerbated by a delay in the completion of the pending merger or by a termination of the merger agreement.
Declaration, payment and amounts of dividends, if any, distributed to our stockholders will be uncertain.
Although we have paid cash dividends on our common stock in the past, our board of directors may determine not to declare dividends in the future or may reduce the amount of dividends paid in the future. Any payment of future dividends will be at the discretion of our board of directors and will depend on our results of operations, financial condition, cash requirements, future prospects and other considerations that our board of directors deems relevant.
Risks Related to the Oil and Natural Gas Industry and Our Business
Our business and operations have been and will likely continue to be adversely affected by the ongoing COVID-19 pandemic.
The spread of COVID-19 caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economies, including contributing to the reduced global and domestic demand for oil and natural gas, which has had and will likely continue to have an adverse effect on our business, financial condition and results of operations. Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 could also negatively impact the availability of key personnel necessary to conduct our business. If COVID-19 continues to spread or the response to contain or mitigate the COVID-19 pandemic through the development and availability of effective treatments and vaccines, including the vaccines recently approved by the FDA for emergency use in the U.S., is unsuccessful, we could continue to experience material adverse effects on our business, financial condition and results of operations. Due to the rapid development and fluidity of this situation, we cannot make any prediction as to the ultimate material adverse impact of the COVID -19 pandemic on our business, financial condition and results of operations.
The sharp decline in oil and natural gas prices and continued volatility in the oil and natural gas markets have negatively impacted, and are likely to continue to negatively impact, our exploration and production activities, which has adversely impacted our business, financial condition and results of operations. In addition, lower oil and natural gas prices may adversely affect the borrowing base under our revolving credit facility and estimates of our proved reserves.
In early March 2020, oil prices dropped sharply and then continued to decline reaching negative levels. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed in April 2020 to cut production and subsequently extended such production cuts through December 2020, which helped to reduce a portion of the excess supply in the market and improve crude oil prices, they agreed to increase production by 500,000 barrels per day beginning in January 2021. As a result, downward pressure on commodity prices has continued and could continue for the foreseeable future. We cannot predict if or when commodity prices will stabilize and at what levels.
As a result of the reduction in crude oil demand caused by factors discussed above, we lowered our 2020 capital budget and production guidance, curtailed near term production and reduced our rig count, all of which may be subject to further reductions or curtailments if the commodity markets and macroeconomic conditions worsen. Although we have restored our curtailed production, actions taken in response to the COVID-19 pandemic and depressed commodity pricing environment have had and are expected to continue to have an adverse effect on our business, financial results and cash flows.
Based on the results of the quarterly ceiling test, we were required to record an impairment on our proved oil and natural gas interests for the year ended December 31, 2020. If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows will be adversely impacted.
Other significant factors that are likely to continue to affect commodity prices in future periods include, but are not limited to, the effect of U.S. energy, monetary and trade policies, U.S. and global political and economic developments, including the Biden Administration’s energy and environmental policies and the impact of the ongoing COVID-19 pandemic on conditions in the U.S. oil and natural gas industry, all of which are beyond our control.
Our results of operations may be also adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.
We cannot predict the ultimate impact of these factors on our business, financial condition and results of operation.
Increased costs of capital could adversely affect our business.
Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.
Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including; the domestic and foreign supply of oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports; political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; speculative trading in crude oil and natural gas derivative contracts; the level of consumer
product demand; extreme weather conditions and other natural disasters; risks associated with operating drilling rigs; technological advances affecting energy consumption; the price and availability of alternative fuels; domestic and foreign governmental regulations and taxes; the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2020, NYMEX WTI prices ranged from $(37.63) to $63.27 per Bbl and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $3.35 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.
In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.
A significant portion 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.
A significant portion of our net leasehold acreage is 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. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. 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.
Our development and exploration operations and our ability to complete acquisitions require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2020, our total capital expenditures, including expenditures for drilling, infrastructure and additions to midstream assets, were approximately $1.9 billion. Our 2021 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $1.4 billion to $1.6 billion, representing a decrease of 50% from our 2020 capital budget. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and the senior notes.
We intend to finance our future capital expenditures for our drilling operations with cash flow from operations, while future acquisitions may also be funded from operations as well as proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including; our proved reserves; the volume of oil and natural gas we are able to produce from existing wells; the prices at which our oil and natural gas are sold; our ability to acquire, locate and produce economically new reserves; and our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2021 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.
Our success depends on finding, developing or acquiring additional reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made, and expect to make in the future, substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.
Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings and slow our growth.
There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including; recoverable reserves, future oil and natural gas 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 attractive 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. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If these acquisitions include geographic regions in which we do not currently operate, as in the case of the pending merger with QEP, we could be subject to unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, 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. The inability to effectively manage the integration of acquisitions, including our pending acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
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. Rather, we rely upon the judgment of oil and gas lease brokers or landmen 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.
Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If future wells or the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.
Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 10,413 gross (6,863 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage. As of December 31, 2020, only 628 of our gross identified potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, we have identified approximately 2,708 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of 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 sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Through December 31, 2020, we are the operator of, have participated in, or have acquired working interest in a total of 2,380 horizontal wells completed on our acreage, we cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our operating results.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. 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. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases expiring in 2021, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy these rigs in this time frame, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.
We have entered into commodity price derivatives for a portion of our production. Although we have hedged a portion of our estimated 2021 and 2022 production, we may still be adversely affected by continuing and prolonged declines in the price of oil and may be exposed to other risks, including counterparty credit risk.
We use commodity price derivatives to reduce price volatility associated with certain of our oil and natural gas sales. To the extent that the prices of oil and natural gas remain at current levels or decline further, we may not be able to economically hedge future production at the same level as our current hedges, and our results of operations and financial condition may be negatively impacted.
At settlement, market prices for commodities may exceed the contract prices in our commodity price derivatives agreements, resulting in our need to make significant cash payments to our counterparties. Further, by using commodity derivative instruments, we expose ourselves to credit risk if we are in a positive position at contract settlement and the counterparty fails to perform under the terms of the derivative contract. We do not require collateral from our counterparties.
For additional information regarding our outstanding derivative contracts as of December 31, 2020, see Note 15-Derivatives to our consolidated financial statements included elsewhere in this report.
If production from our Permian Basin acreage decreases due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contract, which will result in deficiency payments to the counterparty and may have an adverse effect on our operations.
We are a party to long-term crude oil agreements under which, subject to certain terms and conditions, we are obligated to deliver specified quantities of oil to such companies. Our maximum delivery obligation under these agreements varies for different periods and depends in some cases upon certain conditions beyond our control. If production from our Permian Basin acreage decreases due to decreased developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under our oil purchase agreements, which may result in deficiency payments to certain counterparties or a default under such agreements and may have an adverse effect on our company.
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $56 million at December 31, 2020) and receivables from purchasers of our oil and natural gas production (approximately $281 million at December 31, 2020). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.
We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2020, four purchasers each accounted for more than 10% of our revenue. For each of the years ended December 31, 2019 and 2018, three purchasers each accounted for more than 10% of our revenue. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.
Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.
We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $11.30, $13.54 and $12.62 for the years ended December 31, 2020, 2019 and 2018, respectively. Depletion for oil and natural gas properties for the years ended December 31, 2020, 2019 and 2018 was $1.2 billion, $1.4 billion and $595 million, respectively.
The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.
An impairment on proved oil and natural gas properties of $6.0 billion and $790 million was recorded for the years ended December 31, 2020 and 2019, respectively. No impairments on proved oil and natural gas properties were recorded for the year ended December 31, 2018. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates-Method of accounting for oil and natural gas properties” for a more detailed description of our method of accounting.
Our estimated reserves and EURs are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.
The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil reserves.
The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.
Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities-Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Approximately 38% of our total estimated proved reserves as of December 31, 2020, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.
Our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids and extreme weather conditions, such as the recent severe winter storms in the Permian Basin, and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
In addition to the geographic concentration of our producing properties described above, as of December 31, 2020, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
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 and natural gas we produce.
The availability of a ready market for any oil and/or natural gas 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 natural gas 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 natural 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. For the year ended December 31, 2020, four purchasers each accounted for more than 10% of our revenue. For each of the years ended December 31, 2019 and 2018, three purchasers each accounted for more than 10% of our revenue. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of 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. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.
Our business operations have grown substantially since our initial public offering in October 2012 and we expect our business operations to continue to grow in the future. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
We have incurred losses from operations during certain periods since our inception and may do so in the future.
Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from our operating activities in the future.
Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of
multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.
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 declines in natural gas and oil prices, 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.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system, which interconnects with third party pipelines. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.
Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.
Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Further, these laws and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and
regulations may continue in the long-term, and at the state and local levels. See Item 1. “Business-Regulation” for a detailed description of certain laws and regulations that affect us.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. 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 and materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or 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 an adverse impact on our ability to develop and produce our reserves.
Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.
The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act, which we refer to as Dodd-Frank Act, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission, which we refer to as the CFTC, the SEC, and federal regulators of financial institutions, which we refer to as the Prudential Regulators, adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.
Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued many rules to implement the Dodd-Frank Act, including a rule, which we refer to as the Mandatory Clearing Rule, requiring clearing of hedges, or swaps, that are subject to it (currently, only certain interest rate and credit default swaps, a rule, which we refer to as the End User Exception, establishing an “end user” exception to the Mandatory Clearing Rule, a rule, which we refer to as the Margin Rule, setting forth collateral requirements in connection with swaps that are not cleared and also an exception to the Margin Rule for end users that are not financial end users, which exception we refer to as the Non-Financial End User Exception, and a rule imposing position limits, which we refer to as the Position Limit Rule, and also an exception to the Position Limit Rule for swaps that constitute a “bona fide hedging transaction or position” within the definition of such term under the Position Limit Rule, subject to the party claiming the exemption complying with the applicable filing, recordkeeping and reporting requirements of the Position Limit Rule, which we refer to as the Bona Fide Hedging Exception.
We qualify for the End User Exception to the Mandatory Clearing Rule, we qualify for the Non-Financial End User Exception and will not be required to post margin in connection with uncleared swaps under the Margin Rule, and each of our existing and anticipated hedging positions constitutes a “bona fide hedging transaction or position” under the Position Limit Rule and we intend to undertake the filing, recordkeeping and reporting necessary to utilize the Bona Fide Hedging Exception under the Position Limit Rule, so we do not expect to be directly affected by any of such rules. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations (including laws and regulations giving the European Union financial authorities the power to write-down amounts we may be owed on hedging agreements with counterparties subject to such laws and regulations and/or require that we accept equity interests in such counterparties in lieu of cash in satisfaction of such amounts), which we refer to collectively as Foreign Regulations, which may apply to our transactions with counterparties subject to such Foreign Regulations, which we refer to as Foreign Counterparties, and the U.S. adopted law and rules, which we call the U.S. Resolution Stay Rules, clarifying similar rights of U.S. banking authorities with respect to banking institutions subject to their regulation. The Dodd-Frank Act, the rules which have been adopted and not vacated, the Limit Rule and the U.S. Resolution Stay Rules could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulation, the U.S. Resolution Stay Rules and Foreign Regulations, 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 and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
Recently enacted U.S. tax legislation as well as future U.S. tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.
If third party pipelines or other facilities interconnected to Rattler LLC’s midstream systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our midstream operations could be adversely affected.
Our subsidiary Rattler LLC’s midstream systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport, treat or process natural gas or crude oil, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our midstream operations could be adversely affected.
We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.
Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.
We rely on a few key employees whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We do not have employment agreements with our executives and may not be able to assure their retention. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.
Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and
other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including; unusual or unexpected geological formations; loss of drilling fluid circulation; title problems; facility or equipment malfunctions; unexpected operational events; shortages or delivery delays of equipment and services; compliance with environmental and other governmental requirements; and adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our operations are subject to all of the hazards and operating risks associated with drilling for and production of 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, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operations.
In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for
environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
Since hydraulic fracturing activities are part of our operations, we maintain insurance to protect against claims made for bodily injury and property damage, and that insurance includes coverage for clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have limited coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
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.
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.
We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.
Increased costs of capital could adversely affect our business.
Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and cash flows.
The results of the 2020 U.S. presidential and congressional elections may create regulatory uncertainty for the oil and natural gas industry. Changes in environmental laws could increase our operating costs and adversely impact our business, financial condition and cash flows.
The results of the 2020 U.S. presidential election, as well as a closely divided Congress, may create regulatory uncertainty in the oil and natural gas industry. During his first weeks in office, President Biden has issued several executive orders promoting various programs and initiatives designed to, among other things, curtail climate change, control the release of methane from new and existing oil and natural gas operations, and pause new oil and natural gas leasing on public lands. It remains unclear what additional actions President Biden will take and what support he will have for any potential legislative changes from Congress. Further, it is uncertain to what extent any new environmental laws or regulations, or any repeal of existing environmental laws or regulations, may affect our business or operations. However, such actions could significantly increase our operating costs or impair our ability to explore and develop other projects, which could adversely impact our business, financial condition and cash flows.
Our operations depend heavily on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.
We are heavily dependent on electrical power, internet and telecommunications infrastructure and our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively operate our business will be limited and any such consequence could have a material adverse effect on our business.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We maintain specialized insurance for possible liability resulting from a cyberattack on our assets, however, we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Risks Related to Our Indebtedness
References in this section to “us, “we” or “our” shall mean Diamondback Energy, Inc. and Diamondback O&G LLC, collectively, unless otherwise specified.
We have relied in the past, and we may rely from time to time in the future, on borrowings under our revolving credit facility to fund a portion of our capital expenditures. Unless we are able to repay borrowings under the revolving credit facility with cash flow from operations and proceeds from equity or debt offerings, implementing our capital programs may require an increase in our total leverage through additional debt issuances. In addition, a reduction in availability under our revolving credit facility and the inability to otherwise obtain financing for our capital programs could require us to curtail our capital expenditures.
We have historically relied on availability under our revolving credit facility to fund a portion of our capital expenditures. We expect that we will continue to fund a portion of our capital expenditures with borrowings under the revolving credit facility, cash flow from operations and the proceeds from debt and equity offerings. In the past, we have created availability under the revolving credit facility by repaying outstanding borrowings with the proceeds from debt or equity offerings. We cannot assure you that we will choose to or be able to access the capital markets to repay any such future borrowings. Instead, we may be required or choose to finance our capital expenditures through additional debt issuances, which would increase our total amount of debt outstanding. If the availability under the revolving credit facility were reduced, and we were otherwise unable to secure other sources of financing, we may be required to curtail our capital expenditures, which could limit our ability to fund our drilling activities and acquisitions or otherwise finance the capital expenditures necessary to replace our reserves.
Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.
As of December 31, 2020, we had total consolidated outstanding principal indebtedness of $5.8 billion, including $4.6 billion outstanding under our senior notes and $23 million outstanding under our revolving credit facility, and we had $1.98 billion available for borrowing under our revolving credit facility. As of December 31, 2020, Viper LLC, one of our subsidiaries, had $84 million in outstanding borrowings, and $496 million available for borrowing, under its revolving credit facility and $480 million outstanding under its 5.375% Senior Notes due 2027. As of December 31, 2020, Rattler LLC, one of our subsidiaries, had $79 million in outstanding borrowings, and $521 million available for borrowing, under its revolving credit facility and $500 million outstanding under its 5.625% Senior Notes due 2025.
We may in the future incur significant additional indebtedness under our revolving credit facility or otherwise in order to make acquisitions, to develop our properties or for other purposes. Our level of indebtedness could have important consequences to you and affect our operations in several ways, including the following: our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our debt instruments, including any repurchase obligations that may arise thereunder; a significant portion of our cash flows could be used to service our indebtedness, which could reduce the funds available to us for operations and other purposes; our high level of debt could increase our vulnerability to general adverse economic and industry conditions; the covenants contained in the agreements governing certain of our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; our high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing; our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to, changes in the economy and in our industry; our high level of debt could limit our ability to access the capital markets to raise capital on favorable terms; our high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.
We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidies face.
Restrictive covenants in certain of our existing and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.
Certain of our debt instruments contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness; make certain investments; create
liens; sell or transfer assets; issue preferred stock; merge or consolidate with another entity; pay dividends or make other distributions; create unrestricted subsidiaries; and engage in transactions with affiliates.
Under our revolving credit facility we are allowed, among other things, to designate one or more of our subsidiaries as “unrestricted subsidiaries” that are not subject to certain restrictions contained in the revolving credit facility. Under our revolving credit facility, we designated Viper, Viper’s general partner, Viper’s subsidiary, Rattler, Rattler’s general partner and Rattler’s subsidiaries as unrestricted subsidiaries, and upon such designation, they were automatically released from any and all obligations under the revolving credit facility, including the related guaranty. Further Viper, Viper’s general partner, Viper’s subsidiaries, Rattler, Rattler’s general partner and Rattler’s subsidiaries are designated as unrestricted subsidiaries under the indentures governing our outstanding senior notes.
We and our subsidiaries may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants and financial covenants contained in our and our subsidiaries’ debt instruments. As an example, our revolving credit facility requires us to maintain a total net debt to capitalization ratio. The requirement that we and our subsidiaries comply with these provisions may materially adversely affect our and our subsidiaries ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
A breach of any of these restrictive covenants could result in default under the applicable debt instrument. If default occurs under our revolving credit facility, the lenders thereunder may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.
Our indebtedness is structurally subordinated to the indebtedness and other liabilities of our subsidiaries, and our obligations are not obligations of any of our subsidiaries.
Our senior indebtedness obligations are obligations exclusively of Diamondback Energy, Inc. and Diamondback O&G LLC, and not of any of our other subsidiaries. None of our subsidiaries is a guarantor of our senior indebtedness. Any assets of our subsidiaries will not be directly available to satisfy the claims of our creditors, including lenders under our revolving credit facility and holders of the senior notes. Except to the extent we are a creditor with recognized claims against our subsidiaries, all claims of creditors of our subsidiaries will have priority over our equity interests in such subsidiaries (and therefore the claims of our creditors, including lenders under our revolving credit facility and holders of the senior notes) with respect to the assets of such subsidiaries. Even if we are recognized as a creditor of one or more of our subsidiaries, our claims would still be effectively subordinated to any security interests in the assets of any such subsidiary and to any indebtedness or other liabilities of any such subsidiary senior to our claims. Consequently, our senior indebtedness will be structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries and any subsidiaries that we may in the future acquire or establish. For additional information regarding our subsidiaries outstanding debt as of December 31, 2020, see Note 11-Debt to our consolidated financial statements included elsewhere in this report.
Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.
Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. The indenture governing the 2025 Senior Notes restricts our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.
We depend on our subsidiaries for dividends, distributions and other payments.
We depend on our subsidiaries for dividends, distributions and other payments. We are a legal entity separate and distinct from our operating subsidiaries. There are statutory and regulatory limitations on the payment of dividends or distributions by certain of our subsidiaries to us. If our subsidiaries are unable to make dividend or distribution payments to us and sufficient cash or liquidity is not otherwise available, we may not be able to make dividend payments to our stockholders or principal and interest payments on our outstanding indebtedness.
We and our subsidiaries may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our and our subsidiaries’ revolving credit facilities and the indentures restrict, but in each case do not completely prohibit, us from doing so. Further, the indentures governing our and our subsidiaries’ notes allow us to issue additional notes, incur certain other additional debt and to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
Borrowings under our, Viper LLC’s and Rattler LLC’s revolving credit facilities expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under our and our subsidiaries’ revolving credit facilities. The terms of our and our subsidiaries’ revolving credit facilities provide for interest on borrowings at a floating rate equal to an alternate base rate tied to LIBOR. LIBOR tends to fluctuate based on multiple facts, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. We use interest rate swaps to reduce interest rate exposure with respect to our floating rate debt. Our weighted average interest rate on borrowings under our revolving credit facility was 2.02% during the year ended December 31, 2020. Viper LLC’s weighted average interest rate on borrowings from its revolving credit facility was 2.20% during the year ended December 31, 2020. Rattler LLC’s weighted average interest rate on borrowings from its revolving credit facility was 2.10% during the year ended December 31, 2020. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.
On July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established or if LIBOR will continue to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United States or elsewhere.
Risks Related to Our Common Stock
The corporate opportunity provisions in our certificate of incorporation could enable affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.
Subject to the limitations of applicable law, our certificate of incorporation, among other things; permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested; permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.
These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.
We have engaged in the past and may in the future engage in transactions with our affiliates. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.
In the past, we have engaged in transactions with affiliated companies and may do so again in the future. These transactions, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests.
If the price of our common stock fluctuates significantly, your investment could lose value.
Although our common stock is listed on the Nasdaq Global Select Market, we cannot assure you that an active public market will continue for our common stock. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including; our quarterly or annual operating results; changes in our earnings estimates; investment recommendations by securities analysts following our business or our industry; additions or departures of key personnel; changes in the business, earnings estimates or market perceptions of our competitors; our failure to achieve operating results consistent with securities analysts’ projections; changes in industry, general market or economic conditions; and announcements of legislative or regulatory changes.
The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.
The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.
On February 13, 2018, we initiated payment of quarterly cash dividends on our common stock payable beginning with the first quarter of 2018. The decision to pay any future dividends, however, is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns to our stockholders.
In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. This repurchase program is at the discretion of our board of directors and may be suspended from time to time, modified, extended or discontinued by our board of directors at any time. The repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020.
A change of control could limit our use of net operating losses.
As of December 31, 2020, we had a net operating loss, or NOL, carry forward of approximately $2.3 billion for federal income tax purposes. If we were to experience an “ownership change,” as determined under Section 382 of the Code, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by an interest rate periodically promulgated by the IRS referred to as the long-term tax-exempt rate. In general, an ownership change will occur if there is a cumulative increase in the ownership of our stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our 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 downgrade our stock or if our operating results do not meet their expectations, our stock price could decline.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock 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.
Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.
The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including; provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders; limitations on the ability of our stockholders to call a special meeting and act by written consent; the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws; the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors; the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.
These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
We are a party to various legal proceedings, disputes and claims arising in the course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
For additional information regarding contingencies, see Note 17-Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Annual Report.
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
Listing and Holders of Record
Our common stock is listed on the Nasdaq Global Select Market under the symbol “FANG”. There were 2,564 holders of record of our common stock on February 19, 2021.
Dividend Policy
On February 13, 2018, we announced the initiation of an annual cash dividend in the amount of $0.50 per share of our common stock payable quarterly which began with the first quarter of 2018. Beginning with the first quarter of 2019, the annual cash dividend was set at $0.75 per share of our common stock. Then, beginning with the fourth quarter of 2019, the annual cash dividend was increased to $1.50 per share for our common stock and, beginning with the fourth quarter of 2020, the annual cash dividend was further increased to $1.60 per share of our common stock. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.
Unregistered Sales of Equity Securities
As previously disclosed in our Current Report on Form 8-K filed with the SEC on December 21, 2020, we entered into a definitive purchase and sale agreement, dated as of December 18, 2020, with Guidon and certain of Guidon’s affiliates to acquire approximately 32,500 net acres in the Northern Midland Basin and certain related oil and gas assets. Consideration for the Pending Guidon Acquisition consists of $375 million in cash and 10.6 million shares of our common stock, subject to adjustment. The shares to be issued in the Pending Guidon Acquisition will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering. We have agreed to file with the SEC, and use our reasonable best efforts to cause to be declared effective, a shelf registration statement registering for resale these shares within 60 days following the closing of the Pending Guidon Acquisition, which is expected to occur on February 26, 2021.
Repurchases of Equity Securities
Our common stock repurchase activity for the three months ended December 31, 2020 was as follows:
(1)The average price paid per share is net of any commissions paid to repurchase stock.
(2)In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. This repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020.
ITEM 6. SELECTED FINANCIAL DATA
[Reserved.]
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 notes thereto appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Item 1A. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”
Overview
We operate in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.
Upstream Operations
In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.
As of December 31, 2020, we had approximately 378,678 net acres, which primarily consisted of approximately 194,591 net acres in the Midland Basin and approximately 152,587 net acres in the Delaware Basin. As of December 31, 2020, we had an estimated 10,413 gross horizontal locations that we believe to be economic at $60.00 per Bbl WTI.
In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 787,264 gross acres and 24,350 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 52% of these net royalty acres are operated by us.
Midstream Operations
In our midstream operations segment, Rattler’s crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for its customers. Rattler’s facilities gather crude oil from horizontal and vertical wells in our ReWard, Spanish Trail, Pecos and Fivestones areas within the Permian Basin. Rattler’s natural gas gathering and compression system consists of gathering pipelines, compression and metering facilities, which collectively service the production from our Pecos area assets within the Permian Basin. Rattler’s water sourcing and distribution assets consists of water wells, frac pits, pipelines and water treatment facilities, which collectively gather and distribute water from Permian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Rattler’s gathering and disposal system spans approximately 517 miles and consists of gathering pipelines along with produced water disposal, or PWD, wells and facilities which collectively gather and dispose of produced water from operations throughout our Permian Basin acreage.
We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler’s infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in the Delaware and Midland Basins. Our agreements with Rattler include substantial acreage dedications.
2020 Transactions and Recent Developments
COVID-19 and Collapse in Commodity Prices
On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a “pandemic.” To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Although many stay-at-home orders have expired and certain restrictions on conducting business have been lifted, the COVID-19 pandemic resulted in a
widespread health crisis and a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets.
In early March 2020, oil prices dropped sharply and continued to decline reaching negative levels. During 2020, the posted price for the WTI price for crude oil ranged from $(37.63) to $63.27 per barrel, or Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $3.35 per MMBtu. On January 29, 2021, the NYMEX WTI price for crude oil was $52.20 per Bbl and the NYMEX Henry Hub price of natural gas was $2.56 per MMBtu. In response to recent volatility in commodity prices, many producers have reduced their capital expenditure budgets. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed in April 2020 to cut production and subsequently extended such production cuts through December 2020, which helped to reduce a portion of the excess supply in the market and improve crude oil prices, they agreed to increase production by 500,000 barrels per day beginning in January 2021. We cannot predict if or when commodity prices will stabilize and at what levels.
As a result of the reduction in crude oil demand caused by factors discussed above, in 2020, we lowered our 2020 capital budgets and production guidance, curtailed near term production and reduced rig count, all of which may be subject to further reductions or curtailment if the commodity markets and macroeconomic conditions worsen. Although we have restored curtailed production, actions taken in response to the COVID-19 pandemic and depressed commodity pricing environment have had and are expected to continue to have an adverse effect on our business, financial results and cash flows.
In addition, as a result of the sharp decline in commodity prices in early March 2020, and the continued depressed oil pricing throughout the second and third quarters of 2020, we recorded $6.0 billion of aggregate non-cash ceiling test impairments for the year ended December 31, 2020. These impairment charges adversely affected our results of operations but did not reduce our cash flows. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters. Our production, proved reserves and cash flows will also be adversely impacted. Our results of operations may be further adversely impacted by any government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.
Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic, the depressed commodity prices and the adverse macroeconomic conditions will persist, the full extent of the impact they will have on our industry and our business, financial condition, results of operations or cash flows, or the pace or extent of any subsequent recovery.
Pending Merger with QEP Resources, Inc.
On December 20, 2020, we, QEP and the Merger Sub, entered into the merger agreement under which the Merger Sub will be merged with and into QEP, with QEP surviving as our wholly owned subsidiary. If the pending merger is completed, each QEP stockholder will receive, in exchange for each share of QEP common stock held by such stockholder immediately prior to the closing of the pending merger, 0.050 of a share of our common stock. The completion of the pending merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including the receipt of the required approvals from QEP’s stockholders. The pending merger is expected to close shortly following the special meeting of the QEP stockholders, which is scheduled for March 16, 2021, subject to QEP stockholder approval and other customary closing conditions. See “Items 1 and 2. Business and Properties-Overview-Pending Merger with QEP Resources, Inc.” for additional information regarding the pending merger.
We expect that the pending merger will:
•add material Tier-1 Midland Basin inventory;
•be accretive on all relevant 2021 per share metrics including cash flow per share, free cash flow per share and leverage, before accounting for synergies;
•lower 2021 reinvestment ratio and enhance ability to generate free cash flow, de-lever and return capital to our stockholders; and
•realize significant, tangible annual synergies of $60 to $80 million comprised of general and administrative expense savings, cost of capital and interest expense savings, improved capital efficiency from high-graded development of
combined acreage, physical adjacencies to increase lateral lengths and significant adjacent Permian Basin midstream assets.
In addition, we expect to maintain our investment grade credit ratings following the completion of the pending merger.
Pending Guidon Acquisition
On December 18, 2020, we entered into a definitive purchase and sale agreement with Guidon and certain of Guidon’s affiliates to acquire approximately 32,500 net acres in the Northern Midland Basin and certain related oil and natural gas assets, which we refer to as the Pending Guidon Acquisition. Consideration for the Pending Guidon Acquisition consists of $375 million in cash and 10.6 million shares of our common stock, subject to adjustment. The cash portion of this transaction is expected to be funded through a combination of cash on hand and borrowings under our credit facility. The Pending Guidon Acquisition is expected to close on February 26, 2021.
Fourth Quarter 2020 Dividend Declaration and Increase
On February 18, 2021, our board of directors declared a cash dividend for the fourth quarter of 2020 of $0.40 per share of common stock, payable on March 11, 2021 to our stockholders of record at the close of business on March 4, 2021, representing a 6.7% increase per share from the previously paid quarterly dividend.
Implementation of Viper’s Common Unit Repurchase Program
On November 6, 2020, the board of directors of Viper’s general partner approved an expansion of Viper’s return of capital program with the implementation of a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Viper repurchased approximately $24 million of its common units under its repurchase program. As of December 31, 2020, $76 million remained available for use to repurchase common units under Viper’s common unit repurchase program.
Implementation of Rattler’s Common Unit Repurchase Program
On October 29, 2020, the board of directors of Rattler’s general partner approved a common unit repurchase program to acquire up to $100 million of Rattler’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Rattler repurchased approximately $15 million of its common stock under its repurchase program. As of December 31, 2020, $85 million remained available for use to repurchase common units under Rattler’s common unit repurchase program.
May 2020 Notes Offering
On May 26, 2020, we completed a notes offering of $500 million in aggregate principal amount of our 4.750% Senior Notes due 2025, which we refer to as the May 2020 Notes. We received net proceeds of approximately $496 million from the offering of the May 2020 Notes which we used to, among other things, make an equity contribution to Energen to purchase $209 million in aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer. For additional information regarding this notes offering, see “-Liquidity and Capital Resources-Indebtedness-The May 2020 Notes and Tender Offer for Energen’s 4.625% Senior Notes and Repurchase of Energen’s 7.35% Medium-term Notes” below.
Rattler Notes Offering
On July 14, 2020, Rattler completed an offering, which we refer to as the Rattler Notes Offering, of its 5.625% senior notes due 2025 in the aggregate principal amount of $500 million, which we refer to as the Rattler Notes. Rattler received net proceeds of approximately $490 million from the Rattler Notes Offering and loaned the gross proceeds of the Rattler Notes Offering to Rattler LLC to pay down borrowings under its revolving credit facility. For additional information regarding the Rattler Notes Offering, see “-Liquidity and Capital Resources-Indebtedness-Rattler’s Notes” below.
Operational Update
Our development program is focused entirely within the Permian Basin, where we continue to focus on long-lateral multi-well pad development. Our horizontal development consists of multiple targeted intervals, primarily within the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Springs formations in the Delaware Basin.
As of December 31, 2020, we were operating eight drilling rigs and currently intend to operate between eight and 12 drilling rigs in 2021 on average across our current acreage position in the Midland and Delaware Basins.
In the Midland Basin, we continued to have positive results across our core development areas located within Midland, Martin, Howard, Glasscock and Andrews counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations.
In the Delaware Basin, we have now drilled and completed a significant number of wells in Pecos, Reeves and Ward counties targeting the Wolfcamp A, which we believe has been de-risked across a significant portion of our total acreage position and remains our primary development target. In 2021, we expect to focus development on these areas.
In the fourth quarter of 2020, we executed on our business strategy, providing a foundation for continued solid operational performance in 2021. We are starting to see the benefits from our strategy to cut activity and high-grade development focusing on our most productive areas in terms of capital efficiency and early-time well performance. While the impact of the recent winter storms in the Permian Basin on the first quarter 2021 production is expected to be significant (ranging from four to five days of total net production lost), we expect to overcome this adverse impact for the full year 2021. Well costs and cash operating costs remain near all-time lows, providing for increased returns to our stockholders as commodity prices have risen in recent months. In 2021, we intend to continue to focus on low cost operations and best in class execution and currently plan to hold our fourth quarter 2020 production flat while generating free cash flow used to pay dividends and pay down debt. To combat potential fluctuation in service costs, we have worked to implement new and more efficient drilling and completions methodologies and will continue to seek opportunities to control additional well cost where possible. Our 2021 drilling and completion budget accounts for capital costs that we expect to occur during the year.
In 2021, we remain focused on navigating our industry challenges by staying disciplined, improving our industry-leading cost structure, maintaining production and increasing environmental transparency.
Environmental Responsibility Initiatives and Highlights
In February 2021, we announced significant enhancements to our commitment to environmental, social responsibility and governance, or ESG, performance and disclosure, including Scope 1 and methane emission intensity reduction targets. Our goals include the reduction of our Scope 1 greenhouse gas intensity by at least 50% and methane intensity by at least 70%, in each case by 2024 from the 2019 levels. To further underscore our commitment to carbon neutrality, we are also implementing our “Net Zero Now” initiative under which, effective January 1, 2021, every hydrocarbon molecule we produce is anticipated to be produced with zero Scope 1 emissions. To the extent our greenhouse gas and methane intensity targets do not eliminate our carbon footprint, we intend to purchase carbon credits to offset the remaining emissions. We also plan to increase the weighting of ESG metrics in our annual short-term incentive compensation plan to motivate our executives to advance our environmental responsibility goals.
With respect to flaring, we flared 0.9% of our gross natural gas production in the fourth quarter of 2020. For the full year ended 2020, we flared 2.0% of our gross natural gas production, down 64% from 2019.
2021 Capital Budget
We have currently budgeted 2021 total capital spend of $1.4 billion to $1.6 billion, consisting of $1.2 billion to $1.4 billion for horizontal drilling and completions including non-operated activity, $60 million to $80 million for midstream investments, excluding joint venture investments, and $70 million to $90 million for infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions. We expect to drill and complete 215 to 235 gross horizontal wells in 2021. Should commodity prices weaken, we intend to act responsibly and, consistent with our prior practices, reduce capital spending. If commodity prices strengthen, we intend to grow oil production within our 2021 budget, pay down indebtedness and return cash to our stockholders.
Results of Operations
For a discussion of the results of operations for the year ended December 31, 2019 as compared to the year ended December 31, 2018, please refer to “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year ended December 31, 2019 (filed with the SEC on February 27, 2020), which discussion is incorporated in this report by reference from such prior report on Form 10-K. The following table sets forth selected historical operating data for the periods indicated:
(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.
Production Data
Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables set forth our production data for the years ended December 31, 2020 and 2019:
Comparison of the Years Ended December 31, 2020 and 2019
Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.
The net dollar effect of the change in prices are shown below:
(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.
Our oil, natural gas and natural gas liquids revenues decreased by approximately $1.1 billion, or 29%, to $2.8 billion for the year ended December 31, 2020 from $3.9 billion for the year ended December 31, 2019, largely attributable to lower oil average sales prices resulting from the impact of the COVID-19 pandemic and other volatility in global commodity prices as discussed in “-COVID-19 and collapse in Commodity Prices” above.
Average daily production sold increased by 17,359 BOE/d to 300,331 BOE/d during the year ended December 31, 2020 from 282,972 BOE/d during the year ended December 31, 2019, primarily due to an increase in natural gas liquids and natural gas production, which was partially offset by temporarily curtailing a portion of our oil production volumes during 2020 in response to the sudden drop in demand and prices for oil stemming from the COVID-19 pandemic.
Midstream Services Revenue. The following table shows midstream services revenue for the years ended December 31, 2020 and 2019:
Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. Midstream services revenue decreased by $14 million for the year ended December 31, 2020 as compared to the year ended December 31, 2019 primarily due to a reduction in sourced water volumes due to the lower level of drilling and completion activity in 2020.
Lease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2020 and 2019:
Lease operating expenses for the year ended December 31, 2020 as compared to the year ended December 31, 2019 decreased by $65 million, or $0.87 per BOE. Lease operating expenses decreased due to a reduction in work over and well maintenance activity through overall efficiencies gained, as well as improvements in infrastructure which reduced power generation costs and trucking fees. In addition to these efficiencies we have seen a reduction in service pricing in 2020, driven by the reduction in current industry activity levels. We expect service pricing may increase in future periods, particularly if current industry activity levels increase.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the years ended December 31, 2020 and 2019:
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes for the year ended December 31, 2020 as compared to the year ended December 31, 2019 decreased by $49 million, or $0.55 per BOE, due to current year commodity prices. Production taxes as a percentage of production revenues remained consistent for the year ended December 31, 2020 compared to the year ended December 31, 2019.
Gathering and Transportation Expense. The following table shows gathering and transportation expense for the year ended December 31, 2020 and 2019:
For the year ended December 31, 2020, the per BOE increases for gathering and transportation expenses are primarily attributable to recording minimum volume commitment fees in 2020, as well as an increase in fees for our gas production and an overall change in our product mix, with gas and natural gas liquids production becoming a greater percentage of overall production.
Midstream Services Expense. The following table shows midstream services expense for the years ended December 31, 2020 and 2019:
Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities. Midstream services expense for the year ended December 31, 2020 as compared to the year ended December 31, 2019 increased by $14 million primarily due to increased volume and build out of the Rattler systems.
Depreciation, Depletion and Amortization. The following table provides the components of our depreciation, depletion and amortization expense for the years ended December 31, 2020 and 2019:
The decrease in depletion of proved oil and natural gas properties of $156 million for the year ended December 31, 2020 as compared to the year ended December 31, 2019 resulted primarily from a reduction in the average depletion rate for our oil and natural gas properties in 2020, which stemmed from a decrease in the net book value of our properties due to the full cost ceiling impairments recorded in the first three quarters of 2020 as well as lower production levels in 2020 as compared to 2019.
Impairment of Oil and Natural Gas Properties. As a result of the decline in commodity prices during 2020 and 2019, we recorded non-cash ceiling test impairments for the years ended December 31, 2020 and 2019 of $6.0 billion and $790 million, respectively, which is included in accumulated depletion, depreciation, amortization and impairment on our consolidated balance sheet. The impairment charges affected our results of operations but did not reduce cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will continue to have material write-downs in subsequent quarters.
General and Administrative Expenses. The following table shows general and administrative expenses for the years ended December 31, 2020 and 2019:
General and administrative expenses for the year ended December 31, 2020 as compared to the year ended December 31, 2019 decreased by $16 million primarily due to a decrease in non-cash stock-based compensation.
Net Interest Expense. The following table shows net interest expense for the years ended December 31, 2020 and 2019:
Net interest expense increased by $25 million for the year ended December 31, 2020 as compared to the year ended December 31, 2019. This increase was primarily due to an increase in borrowings resulting from the issuance of the May 2020 Notes and the Rattler Notes. See Note 11-Debt for further details regarding outstanding borrowings and interest expense.
Derivatives. The following table shows the net gain (loss) on derivative instruments and the net cash received (paid) on settlements of derivative instruments for the years ended December 31, 2020 and 2019:
Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains; while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.
Net cash received (paid) on settlements of derivative instruments for the years ended December 31, 2020 and 2019 include cash received on contracts terminated prior to their contractual maturity of $17 million related to commodity contracts and $43 million related to interest rate swap contracts, respectively.
Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the years ended December 31, 2020 and 2019:
The change in our income tax provision was primarily due to the pre-tax loss for the year ended December 31, 2020 as compared to pre-tax income for the year ended December 31, 2019, and the impact of recording a valuation allowance on Viper’s deferred tax assets during the year ended December 31, 2020.
Liquidity and Capital Resources
Historically, our primary sources of liquidity have been cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility and proceeds from the issuance of the senior notes. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties.
As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the depressed commodity markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.
Liquidity and Cash Flow
Our cash flows for the years ended December 31, 2020 and 2019 are presented below:
Operating Activities
Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See “-Sources of our revenue” and Item 1A. “Risk Factors” above.
Net cash provided by operating activities decreased to $2.1 billion for the year ended December 31, 2020 as compared to $2.7 billion for the year ended December 31, 2019, primarily due to a decline in our oil and natural gas revenues, which was partially offset by a decrease in lease operating expenses and other operating expenses and an increase in cash received on settlements of our derivative contracts.
Investing Activities
The purchase and development of oil and natural gas properties and related assets, and contributions to our equity method investments accounted for the majority of our $2.1 billion and $3.9 billion in cash outlays for investing activities during the years ended December 31, 2020 and 2019, respectively.
Contributions to equity method investments decreased to $102 million for the year ended December 31, 2020 as compared to $485 million for the year ended December 31, 2019 as construction of both the EPIC Pipeline and Gray Oak Pipeline, which required substantial capital in 2019, was completed during April 2020. As of December 31, 2020, Rattler’s anticipated future capital commitments for its equity method investments total $72 million in the aggregate. For additional information regarding our equity method investments, see Note 10-Equity Method Investments included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Capital Expenditure Activities
Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:
(1) During the year ended December 31, 2020, in conjunction with our development program, we drilled 208 gross (195 net) operated horizontal wells, of which 75 gross (70 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 171 gross (159 net) operated horizontal wells to production, of which 78 gross (74 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin.
(2) During the year ended December 31, 2019, in conjunction with our development program, we drilled 330 gross (296 net) operated horizontal wells, of which 159 gross (142 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 317 gross (289 net) operated horizontal wells to production, of which 139 gross (126 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin.
Financing Activities
During the year ended December 31, 2020, the amount used in financing activities was primarily attributable to $348 million of repayments, net of borrowings, on our credit facilities, $239 million in aggregate repayments on the Energen Notes and Viper Notes, $236 million in dividends paid to stockholders, $98 million of share repurchases as part of our stock repurchase program, and $93 million in distributions to non-controlling interest. These cash outlays were partially offset by net proceeds of $997 million from the issuance of the May 2020 Notes and the Rattler Notes during 2020.
During the year ended December 31, 2019, the amount provided by financing activities was primarily attributable to $341 million in net proceeds from Viper’s public offering completed on March 1, 2019, $720 million in net proceeds from the Rattler Offering, $39 million in proceeds from joint ventures and $2.2 billion in proceeds from the December 2019 Notes, net of repayments, partially offset by $1.4 billion of repayments, net of borrowings, under our credit facility, $44 million of premium on debt extinguishment, $122 million of distributions to our non-controlling interest, $13 million of share
repurchases for tax withholdings, $593 million of share repurchases as part of our stock repurchase program and $112 million of dividends to stockholders.
Indebtedness
Second Amended and Restated Credit Facility
At December 31, 2020, the maximum credit amount available under our credit agreement was $2.0 billion and the maturity date is November 1, 2022. As of December 31, 2020, we had approximately $23 million of outstanding borrowings under our revolving credit facility, which we believe provides ample availability for future borrowings, including funding for the cash portion of the Guidon acquisition in the first quarter of 2021. As of December 31, 2020, there was an aggregate of $3 million in letters of credit outstanding under our credit agreement, which reduce available borrowings on a dollar for dollar basis. The weighted average interest rate on the credit agreement was 2.02% for the year ended December 31, 2020.
The credit agreement contains a financial covenant that requires us to maintain a total net debt to capitalization ratio (as defined in the credit agreement) of no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets.
At December 31, 2020, we were in compliance with all financial maintenance covenants under the credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.
The May 2020 Notes and Tender Offer for Energen’s 4.625% Senior Notes and Repurchase of Energen’s 7.35%
Medium-term Notes
On May 26, 2020, we completed a registered offering of $500 million in aggregate principal amount of our 4.750% Senior Notes due 2025. Interest on the May 2020 Notes accrues from May 26, 2020, and is payable in cash semi-annually on May 31 and November 30 of each year, beginning November 30, 2020. The May 2020 Notes mature on May 31, 2025. We received net proceeds of approximately $496 million from the offering.
We used the net proceeds, among other things, to make an equity contribution to Energen to purchase $209 million in aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer. As of December 31, 2020, $191 million in aggregate principal amount of Energen’s 4.625% senior notes remained outstanding.
During the third quarter of 2020, we repurchased all $10 million in principal amount of Energen’s outstanding 7.350% medium-term notes due on July 28, 2027 at a price of 120% of the aggregate principal amount.
For additional information, see Note 11-Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Energen Notes
On November 29, 2018, Energen became our wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes, which we refer to as the Energen Notes. As of December 31, 2020, the aggregate principal amount of the Energen Notes had been reduced to $311 million consisting of: (a) $191 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (b) $100 million of 7.125% notes due on February 15, 2028, and (c) $20 million of 7.32% notes due on July 28, 2022.
For additional information regarding the Energen Notes, See Note 11-Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Viper’s Credit Agreement
The Viper credit agreement provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $580 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st, and was reaffirmed at $580 million by the
lenders during the regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of December 31, 2020, Viper LLC had $84 million of outstanding borrowings and $496 million available for future borrowings under the Viper credit agreement. During the year ended December 31, 2020, the weighted average interest rate on Viper’s revolving credit facility was 2.20%.
As of December 31, 2020, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement, as then in effect.
Viper’s Notes
On October 16, 2019, Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of $500 million. Viper received net proceeds of approximately $490 million from the notes offering and loaned the gross proceeds to Viper LLC to pay down borrowings under the Viper credit agreement. Interest on the Viper notes accrues at a rate of 5.375% per annum, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2020. The Viper notes will mature on November 1, 2027.
During the year ended December 31, 2020, Viper repurchased $20 million of outstanding principal of the Viper notes at a cash price ranging from 97.5% to 98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt, and $480 million in aggregate principal amount remained outstanding at December 31, 2020.
See additional discussion in Note 11-Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Rattler’s Credit Agreement
In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, as administrative agent, and a syndicate of banks, as lenders party thereto, which we refer to as the Rattler credit agreement.
The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million and has a maturity date of May 28, 2024. As of December 31, 2020, Rattler LLC had $79 million of outstanding borrowings and $521 million available for future borrowings under the Rattler credit agreement. During the year ended December 31, 2020, the weighted average interest rate on the Rattler LLC revolving credit facility was 2.10%.
As of December 31, 2020, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.
Rattler’s Notes
On July 14, 2020, Rattler completed an offering of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025, or the Rattler Notes Offering. Interest on the Rattler notes is payable on January 15 and July 15 of each year, beginning on January 15, 2021. The Rattler notes mature on July 15, 2025. Rattler received net proceeds of approximately $490 million from the Rattler Notes Offering. Rattler loaned the gross proceeds to Rattler LLC under the terms of a subordinated promissory note, dated as of July 14, 2020. The promissory note requires Rattler LLC to repay the intercompany loan to Rattler on the same terms and in the same amounts as the Rattler notes and has the same maturity date, interest rate, change of control repurchase and redemption provisions. Rattler LLC used the proceeds from the Rattler Notes Offering to repay a portion of the outstanding borrowings under the Rattler credit agreement.
For additional information regarding our indebtedness, see Note 11-Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Capital Requirements and Sources of Liquidity
Our board of directors approved a 2021 capital budget for drilling, midstream and infrastructure of $1.4 billion to $1.6 billion, representing a decrease of 50% from our 2020 capital budget. We estimate that, of these expenditures, approximately:
•$1.2 billion to $1.4 billion will be spent on drilling and completing 215 to 235 gross (197 to 215 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,100 feet;
•$60 million to $80 million will be spent on midstream infrastructure, excluding joint venture investments; and
•$70 million to $90 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.
We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
During the year ended December 31, 2020, we spent $1.6 billion on drilling and completion, $140 million on midstream, $108 million on infrastructure and $58 million on non-operated properties, for total capital expenditures of $1.9 billion.
In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. We repurchased approximately $98 million of our common stock under this program during the year ended December 31, 2020, prior to the program’s expiration.
The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer 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 and natural gas, 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. We are currently operating eight drilling rigs and nine completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.
Based upon current oil and natural gas prices and production expectations for 2021, we believe our cash flows from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2021. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2021 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.
We monitor and adjust our projected capital expenditures in response to the results of our drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. If there is a decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.
Guarantor Financial Information
As of December 31, 2020, Diamondback O&G LLC is the sole guarantor under the December 2019 Notes Indenture governing the December 2019 Notes, the May 2020 Notes and the 2025 Indenture governing the 2025 Senior Notes.
Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the December 2019 Notes Indenture and the 2025 Indenture, such as, with certain exceptions, (1) in the event Diamondback O&G LLC (or all or substantially all of its assets) is sold or disposed of, (2) in the event Diamondback O&G LLC ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (3) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.
Diamondback O&G LLC’s guarantees of the December 2019 Notes, the May 2020 Notes and the 2025 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.
The rights of holders of the Senior Notes against Diamondback O&G LLC may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback O&G LLC’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of Diamondback O&G LLC. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback O&G LLC, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity.
Contractual Obligations
The following table summarizes our contractual obligations and commitments as of December 31, 2020:
(1)Includes the outstanding principal amount under the revolving credit facilities, the table does not include commitment fees, interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.
(2)Interest represents the scheduled cash payments on the senior notes and Energen Notes.
(3)Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 9-Asset Retirement Obligations in the notes to the consolidated financial statements included elsewhere in this Annual Report.
(4)Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2020.
(5)Timing of when capital commitments will be requested can vary.
(6)Operating lease obligations represent future commitments for building, equipment and vehicle leases.
The table above does not include estimated deficiency fees related to certain volume commitments as they are based off future volume deliveries and differences from market pricing which we cannot predict.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.
Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Critical accounting policies cover accounting estimates that are inherently uncertain because the future resolution of such matters is unknown and actual results could differ from those estimates.
Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include (i) the method of accounting for our oil and natural gas properties, (ii) estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, (iii) impairments of the carrying value of oil and natural gas properties, (iv) fair value estimates of commodity derivatives and (v) estimates of income taxes.
Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments.
Method of accounting for oil and natural gas properties
We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties.
Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. If our production remains at approximately the same level from year to year, depletion expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Oil and natural gas reserve quantities and standardized measure of future net revenue
Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Impairment
Under the full cost method of accounting, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. Impairments of our evaluated oil and natural gas properties are not reversible.
Derivatives
From time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and the counterparties’ creditworthiness.
We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.
Income Taxes
The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and provincial tax jurisdictions. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when 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 the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.
The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.
See Note 2-Summary of Significant Accounting Policies of the notes to the consolidated financial statements included elsewhere in this Annual Report for a full discussion of our significant accounting policies.
Recent Accounting Pronouncements
For information regarding recent accounting pronouncements, See Note 2-Summary of Significant Accounting Policies included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2020. Please read Note 17-Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Form 10-K for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
Our major market risk exposure in our exploration and production business is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control.
We use derivatives, including swaps, basis swaps, swaptions, roll hedges and costless collars, to reduce price volatility associated with certain of our oil and natural gas sales.
At December 31, 2020, we had a net liability derivative position of $255 million related to our commodity price risk derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of December 31, 2020, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $284 million, an increase of $29 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position to $226 million, a decrease of $29 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.
In our midstream operations business, we have indirect exposure to commodity price risk in that persistent low commodity prices may cause us or Rattler’s other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If we or Rattler’s other customers delay drilling or temporarily shut in production due to persistently low commodity prices or for any other reason, our revenue in the midstream operations segment could decrease, as Rattler’s commercial agreements do not contain minimum volume commitments.
For additional information on our open commodity derivative instruments at December 31, 2020, see Note 15-Derivatives.
Counterparty and Customer Credit Risk
Our principal exposures to credit risk are due to the concentration of receivables from the sale of our oil and natural gas production (approximately $281 million at December 31, 2020), and to a lesser extent, receivables resulting from joint interest receivables (approximately $56 million at December 31, 2020).
We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2020, four purchasers each accounted for more than 10% of our revenue. For each of the years ended December 31, 2019 and 2018, three purchasers each accounted for more than 10% of our revenue. No other customer accounted for more than 10% of our revenue during these periods. Our allowances for credit losses were insignificant at December 31, 2020.
Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.
The ongoing COVID-19 pandemic, depressed commodity pricing environment and adverse macroeconomic conditions may enhance our customer credit risk.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.0% per annum in the case of the alternative base rate and from 1.125% to 2.0% per annum in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. Historically, we have used interest rate swaps and treasury locks to reduce our exposure to variable rate interest payments associated with our revolving credit facility.
The following table summarizes the Company’s interest rate swaps as of December 31, 2020:
For additional information on our variable interest rate debt at December 31, 2020, see Note 11-Debt. See Note 18-Subsequent Events for discussion of derivative transactions which occurred subsequent to December 31, 2020.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears beginning on page of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures
Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
As of December 31, 2020, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2020, our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting
There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internal control over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2020.
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.
Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2020. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2020, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Diamondback Energy, Inc.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2020, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2020, and our report dated February 25, 2021 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 25, 2021
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2020.
We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accounting officer and controller and persons performing similar functions. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. The Company also has made the Code of Business Conduct and Ethics available on our website under the “Corporate Governance” section at http://ir.diamondbackenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.
ITEM 11. EXECUTIVE COMPENSATION
Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2020.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2020.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2020.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2020.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
_______________
*
Filed herewith.
**
The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
+
Management contract, compensatory plan or arrangement.
#
The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DIAMONDBACK ENERGY, INC.
Date: February 25, 2021
/s/ Travis D. Stice
Travis D. Stice
Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities and 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.
Signature Title Date
/s/ Steven E. West Chairman of the Board and Director February 25, 2021
Steven E. West
/s/ Travis D. Stice Chief Executive Officer and Director February 25, 2021
Travis D. Stice (Principal Executive Officer)
/s/ Vincent K. Brooks Director February 25, 2021
Vincent K. Brooks
/s/ Michael P. Cross Director February 25, 2021
Michael P. Cross
/s/ David L. Houston Director February 25, 2021
David L. Houston
/s/ Stephanie K. Mains Director February 25, 2021
Stephanie K. Mains
/s/ Mark L. Plaumann Director February 25, 2021
Mark L. Plaumann
/s/ Melanie M. Trent Director February 25, 2021
Melanie M. Trent
/s/ Kaes Van’t Hof Chief Financial Officer and Executive Vice President-Business Development February 25, 2021
Kaes Van’t Hof (Principal Financial Officer)
/s/ Teresa L. Dick Chief Accounting Officer, Executive Vice President and Assistant Secretary February 25, 2021
Teresa L. Dick (Principal Accounting Officer)
S-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Diamondback Energy, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (collectively the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 25, 2021 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Estimation of proved reserves as it relates to the calculation and recognition of depletion expense and the evaluation of impairment
As described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues to record depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or impairment expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others.
•We tested the design and operating effectiveness of key controls relating to the preparation of the ceiling test calculation and management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment. Specifically, these controls related to the use of historical information in the estimation of proved reserves derived from the Company’s accounting records and the management review controls on information provided to the reservoir engineering specialists and the management review controls on the final proved reserve report prepared by the Company’s specialists.
•We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
•To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows:
-Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
-Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;
-Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations;
-Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of land and division order records;
-Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s or the operator’s intent to develop the proved undeveloped properties;
-Evaluated the estimated ultimate recovery of proved undeveloped properties to the estimated ultimate recovery of comparable proved developed producing properties; and
-Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2009.
Oklahoma City, Oklahoma
February 25, 2021
Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
See accompanying notes to consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
See accompanying notes to consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statement of Stockholders’ Equity
See accompanying notes to consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
See accompanying notes to consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows - Continued
(1)Includes $7 billion of common stock issued for business combination, $14 million for stock options assumed and $52 million for restricted stock units assumed.
See accompanying notes to consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION
Organization and Description of the Business
Diamondback Energy, Inc. (“Diamondback” or the “Company”) is an independent oil and gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas.
The wholly-owned subsidiaries of Diamondback, as of December 31, 2020, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company (“Viper’s General Partner”), Rattler Midstream GP LLC, a Delaware limited liability company (“Rattler’s General Partner”), and Energen Corporation, an Alabama corporation (“Energen”). The consolidated subsidiaries include these wholly owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (“Viper”), Viper’s subsidiary Viper Energy Partners LLC, a Delaware limited liability company (“Viper LLC”), Rattler Midstream LP (formerly known as Rattler Midstream Partners LP), a Delaware limited partnership (“Rattler”), Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC), a Delaware limited liability company (“Rattler LLC”), Rattler LLC’s wholly owned subsidiaries Tall City Towers LLC, a Delaware limited liability company (“Tall City”), Rattler Ajax Processing LLC, a Delaware limited liability company, Rattler OMOG LLC, a Delaware limited liability company, Energen’s wholly owned subsidiaries Energen Resources Corporation, an Alabama corporation (“Energen Resources”), EGN Services, Inc., an Alabama corporation and Bohemia Merger Sub Inc., a Delaware corporation.
Basis of Presentation
The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.
Viper and Rattler are consolidated in the financial statements of the Company. As of December 31, 2020, the Company owned approximately 58% of Viper’s total units outstanding. The Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper. As of December 31, 2020, the Company owned approximately 72% of Rattler’s total units outstanding. The Company’s wholly owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler. The results of operations attributable to the non-controlling interest in Viper and Rattler are presented within equity and net income and are shown separately from the Company’s equity and net income attributable to the Company.
The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which includes midstream services and real estate operations.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Making accurate estimates and assumptions is particularly difficult as the oil and natural gas industry experiences challenges resulting from negative pricing pressure from the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets. Companies in the oil and natural gas industry have changed near term business plans in response to changing market conditions. The aforementioned circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.
The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities assumed, equity-based compensation, fair value estimates of derivative instruments and estimates of income taxes.
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.
Accounts Receivable
Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date.
The Company adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications
to the rule on January 1, 2020. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for expected losses as estimated by the Company when collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. At December 31, 2020 and 2019, the Company recorded immaterial allowances for credit losses related to joint interest receivables and credit losses related to sales of oil and natural gas production.
Derivative Instruments
The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. For additional information regarding the Company’s derivative instruments, see Note 15-Derivatives.
Oil and Natural Gas Properties
The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $11.30, $13.54 and $12.62 for the years ended December 31, 2020, 2019 and 2018, respectively. Depletion expense for oil and natural gas properties was $1.2 billion, $1.4 billion and $595 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. For additional information regarding the Company’s impairments on proved oil and natural gas properties, see Note 8-Property and Equipment.
Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on at least an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Real Estate Assets
Real estate assets are stated at cost, less accumulated depreciation and amortization. The Company considers the period of future benefit of each respective asset to determine the appropriate useful life and depreciation and amortization is calculated using the straight-line method over the assigned useful life.
Upon acquisition of real estate properties, the purchase price is allocated to tangible assets, consisting of land and building, and to identified intangible assets and liabilities, which may include the value of above market and below market leases and the value of in-place leases. The allocation of the purchase price is based upon the fair value of each component of the property. Although independent appraisals may be used to assist in the determination of fair value, in many cases these values will be based upon management’s assessment of each property, the selling prices of comparable properties and the discounted value of cash flows from the asset. For additional information regarding the Company’s real estate assets, see Note 7-Real Estate Assets.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Other Property, Equipment and Land
Other property, equipment and land is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight-line method over their estimated useful lives, which range from three to 15 years.
Asset Retirement Obligations
The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.
Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties.
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. For additional information regarding the Company’s asset retirement obligations, see Note 9-Asset Retirement Obligations.
Impairment of Long-Lived Assets
Other property and equipment used in operations and midstream assets are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no significant impairment losses for the years ended December 31, 2020, 2019 and 2018.
Capitalized Interest
The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these unevaluated properties to their intended use. Capitalized interest cannot exceed gross interest expense. See Note 11-Debt for further details.
Inventories
Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2020 and 2019. The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units.
Debt Issuance Costs
Long-term debt includes capitalized costs related to the senior notes, net of accumulated amortization. The costs associated with the senior notes are netted against the senior notes balances and are amortized over the term of the senior notes using the effective interest method. See Note 11-Debt for further details. The costs associated with the Company’s credit facilities are included in other assets on the consolidated balance sheet and are amortized over the term of the facility.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Other Accrued Liabilities
Other accrued liabilities consist of the following:
Revenue and Royalties Payable
For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.
Non-controlling Interests
Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interests in Viper and Rattler do not result in a change of control, the transactions are accounted for as equity transactions under ASC Topic 810, “Consolidation”, which requires that any differences between the carrying value of the Company’s basis in Viper and Rattler and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 12-Capital Stock and Earnings Per Share for a discussion of changes of the Company’s ownership interest in consolidated subsidiaries during the year ended December 31, 2020.
Revenue Recognition
Revenue from Contracts with Customers
Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.
Oil sales
The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Natural gas and natural gas liquids sales
Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities 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 natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations.
In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids 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 ultimate 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 control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations.
Midstream Revenue
Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.
Transaction price allocated to remaining performance obligations
The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of our product sales contracts.
Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Contract balances
Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.
Prior-period performance obligations
The Company records revenue in the month production is delivered to the purchaser. However, purchaser and settlement statements for natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the years ended December 31, 2020, 2019 and 2018 revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.
Investments
An investment of less than 50% in an investee over which the Company exercises significant influence but does not have control is accounted for using the equity method. Additionally, an investment of greater than 50% in an investee over which the Company does not exercise significant influence or have control is also accounted for using the equity method. Under the equity method, the Company’s share of the investee’s earnings or loss is recognized in the consolidated statement of operations.
Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other shareholdings. Additionally, an investment in a limited liability company that maintains a specific ownership account for each investor shall be viewed as similar to an investment in a limited partnership for purposes of determining whether a noncontrolling investment shall be accounted for using the cost method or the equity method. The Company has determined it has the ability to exercise significant influence over its investments which constitute less than a 20% ownership interest, and does not have the ability to exercise significant influence over its investments which constitute greater than a 50% ownership interest, and therefore accounts for all of its investments under the equity method.
The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There were no material impairments for the Company’s equity investments for the years ended December 31, 2020, 2019 and 2018. For additional information on the Company’s investments, see Note 10-Equity Method Investments.
Accounting for Equity-Based Compensation
The Company has granted various types of stock-based awards including stock options and restricted stock units. Viper and Rattler have granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner, Rattler’s General Partner and the Company who perform services for the respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 13-Equity-Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed over the required service period. Forfeitures for these awards are recognized as they occur.
Environmental Compliance and Remediation
Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when 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 the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. For additional information regarding income taxes, see Note 14-Income Taxes.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Recent Accounting Pronouncements
Recently Adopted Pronouncements
In June 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on the Company’s financial position, results of operations or liquidity since it does not have a history of credit losses.
Accounting Pronouncements Not Yet Adopted
In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740) Simplifying the Accounting for Income Taxes", This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance. This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity.
The Company considers the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed.
3. REVENUE FROM CONTRACTS WITH CUSTOMERS
Disaggregation of Revenue
The following tables present the Company’s revenue from contracts with customers disaggregated by product type and basin:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Customers
The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2020, four purchasers each accounted for more than 10% of our revenue: Vitol Inc. (“Vitol”) (26%); Shell Trading (USA) Company (“Shell”) (22%); Plains Marketing LP (“Plains”) (20%); and Trafigura Trading LLC (11%). For the year ended December 31, 2019, three purchasers each accounted for more than 10% of the Company’s revenue: Shell (27%); Plains (23%); and Vitol (15%). For the year ended December 31, 2018, three purchasers each accounted for more than 10% of the Company’s revenue: Shell (26%); Koch Supply & Trading LP (15%); and Occidental Energy Marketing Inc. (11%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
4. ACQUISITIONS AND DIVESTITURES
2020 Activity
Viper’s Acquisition of Certain Mineral and Royalty Interests
During the year ended December 31, 2020, Viper acquired, from unrelated third-party sellers, mineral and royalty interests representing 4,948 gross (417 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $64 million, subject to post-closing adjustments. Viper funded these acquisitions with cash on hand and borrowings under Viper LLC’s revolving credit facility.
Pending Acquisitions
See Note 18-Subsequent Events for acquisition agreements entered into in 2020 that are expected to close in 2021.
2019 Activity
Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen
On May 23, 2019, the Company completed its divestiture of 6,589 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in its merger with Energen (as described below), for an aggregate sale price of $37 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.
On July 1, 2019, the Company completed its divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in the merger with Energen (as described below), for an aggregate sale price of $285 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.
2019 Drop-Down Transaction
On July 29, 2019, the Company entered into a definitive purchase agreement to divest certain mineral and royalty interests to Viper for approximately 18 million of Viper’s newly-issued Class B units, approximately 18 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits (the “Drop-Down”). The mineral and royalty interests divested in the Drop-Down represent approximately
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by the Company, and have an average net royalty interest of approximately 3.2% (the “Drop-Down Assets”). The Drop-Down closed on October 1, 2019 and was effective as of July 1, 2019. Viper funded the cash portion of the purchase price of the Drop-Down Assets through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility.
2018 Activity
Tall City Towers LLC
On January 31, 2018, Tall City, a subsidiary of the Company, completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located for a net purchase price of $110 million.
Ajax Resources, LLC
On October 31, 2018, the Company completed its acquisition of leasehold interests and related assets of Ajax Resources, LLC, which included approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900 million in cash and approximately 2.6 million shares of the Company’s common stock (the “Ajax acquisition”). This transaction was effective as of July 1, 2018. The cash portion of this transaction was funded through a combination of cash on hand, proceeds from the sale of mineral interests to Viper (described below under the caption “2018 Drop-Down Transaction”), borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 11-Debt for information relating to this offering.
2018 Drop-down Transaction
On August 15, 2018, the Company completed a transaction to sell Viper mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by the Company, for $175 million.
ExL Petroleum Management, LLC and EnergyQuest II LLC
On October 31, 2018, the Company completed its acquisitions of leasehold interests and related assets, one with ExL Petroleum Management, LLC and ExL Petroleum Operating, Inc. and one with EnergyQuest II LLC, for an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $313 million in cash. These transactions were effective as of August 1, 2018 and were funded through a combination of cash on hand, proceeds from the sale of assets to Viper and borrowing under the Company’s revolving credit facility.
Energen Corporation Merger
On November 29, 2018, the Company completed its acquisition of Energen in an all-stock transaction (the “Merger”), which was accounted for as a business combination. Upon completion of the Merger, the addition of Energen’s assets increased the Company’s assets to: (i) over 273,000 net Tier One acres in the Permian Basin, (ii) approximately 7,200 estimated total net horizontal Permian locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins. Under the terms of the Merger, each share of Energen common stock was converted into 0.6442 of a share of the Company’s common stock. The Company issued approximately 62.8 million shares of its common stock valued at a price of $112.00 per share on the closing date, resulting in total consideration paid by the Company to the former Energen shareholders of approximately $7.1 billion.
In connection with the closing of the Merger, the Company repaid outstanding principal under Energen’s revolving credit facility and assumed all of Energen’s long-term debt. See Note 11-Debt for additional information.
Purchase Price Allocation
The Merger has been accounted for as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of Energen to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date resulting in no goodwill or bargain purchase gain.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The following table sets forth the Company’s purchase price allocation:
The Company has included revenues of $102 million and direct operating expenses of $17 million in its consolidated statements of operations for the period from December 1, 2018 to December 31, 2018 due to the acquisition.
Pro Forma Financial Information
The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the years ended December 31, 2018 and 2017 have been prepared to give effect to the Merger as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Energen’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Energen’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Energen’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.
Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $37 million for the year ended December 31, 2018 and acquisition-related costs incurred by Energen of $59 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Energen assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The pro forma consolidated statement of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2017 and is not intended to be a projection of future results.
5. VIPER ENERGY PARTNERS LP
Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback to, among other things, own, acquire and exploit oil and natural gas properties in the Permian Basin in North America.
During the years ended December 31, 2020, 2019, and 2018, Diamondback received distributions of $62 million, $133 million and $155 million, respectively, in respect of its interests in Viper and Viper LLC.
Viper completed the following equity offerings during the years ended December 31, 2019 and 2018:
There were no equity offerings during the year ended December 31, 2020.
The Company’s ownership percentage in Viper is reflected as a non-controlling interest in the consolidated financial statements of Viper. The Company’s ownership percentage in Viper changes as a result of Viper’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on its units. These changes in ownership percentage and the disproportionate allocation of net income to the Company under Viper’s partnership agreement for a set period of time following Viper’s tax status change result in the difference between the Company’s share of the underlying net book value in Viper before and after the respective Partnership common unit transactions. See Note 12-Capital Stock and Earnings Per Share for further details.
Recapitalization, Tax Status Election and Related Transactions by Viper
In March 2018, the Board of Directors of Viper’s General Partner unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 Viper (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of the Operating Company, (iii) amended and restated its existing registration rights agreement with the Company and (iv) entered into an exchange agreement with the Company, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, the Company delivered and assigned to Viper 73,150,000 common units the Company owned in exchange for (i) 73,150,000 of Viper’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, Viper continued to be the managing member of the Operating Company, with sole control of its operations. The Operating Company units and Viper’s Class B units owned by the Company are exchangeable from time to time for Viper’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
On May 10, 2018, in connection with the change in Viper’s income tax status becoming effective, the Company, among other things, exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of Viper. After the effectiveness of the tax status election and the completion of related transactions, Viper’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. The Company is party to a partnership agreement and tax sharing agreement with Viper which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2020, 2019 and 2018.
Implementation of Viper’s Common Unit Repurchase Program
On November 6, 2020, the board of directors of Viper’s general partner approved an expansion of Viper’s return of capital program with the implementation of a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Viper repurchased approximately $24 million of its common units under its repurchase program. As of December 31, 2020, $76 million remained available for use to repurchase Viper’s common units under its common unit repurchase program.
Viper LLC’s Revolving Credit Facility
Viper has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 11-Debt for a description of this credit facility.
6. RATTLER MIDSTREAM LP
Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR”. Rattler was formed by Diamondback in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler Midstream GP LLC (“Rattler’s General Partner”), a wholly owned subsidiary of Diamondback, serves as the general partner of Rattler. As of December 31, 2020, Diamondback owned approximately 72% of Rattler’s total units outstanding.
Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May of 2019, Diamondback owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of $17.50 per common unit. Rattler received net proceeds of approximately $720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions.
In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B Units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a $1 million cash contribution from Diamondback, (ii) issued a general partner interest in Rattler to Rattler’s General Partner, in exchange for a $1 million cash contribution from Rattler’s General Partner and (iii) caused Rattler LLC to make a distribution of approximately $727 million to Diamondback.
The Company is party to a partnership agreement, services and secondment agreement and tax sharing agreement with Rattler which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2020, 2019 and 2018.
Implementation of Rattler’s Common Unit Repurchase Program
On October 29, 2020, the board of directors of Rattler’s general partner approved a common unit repurchase program to acquire up to $100 million of Rattler’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Rattler repurchased approximately $15 million of its common units under its repurchase program. As of December 31, 2020, $85 million remained available for use to repurchase common units under Rattler’s common unit repurchase program.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Rattler LLC’s Revolving Credit Facility
Rattler LLC has entered into a secured revolving credit facility with Wells Fargo, as administrative agent, sole book runner and lead arranger. See Note 11-Debt for a description of this credit facility.
7. REAL ESTATE ASSETS
In conjunction with Diamondback’s acquisition of the Fasken Center, the Company allocated the $110 million purchase price between real estate assets and an insignificant amount of intangible lease assets related to in-place and above-market leases. The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of Diamondback’s real estate assets:
8. PROPERTY AND EQUIPMENT
Property and equipment includes the following:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Capitalized internal costs were approximately $53 million, $49 million and $29 million for the years ended December 31, 2020, 2019 and 2018, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within five years.
As a result of the decline in commodity prices during 2020, the Company recorded a non-cash ceiling test impairment for the year ended December 31, 2020 of $6.0 billion which is included in accumulated depletion, depreciation, amortization and impairment on the consolidated balance sheet. The impairment charge affected the Company’s reported net income but did not reduce its cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, the Company may have material write downs in subsequent quarters. The Company also recorded a non-cash ceiling test impairment on proved oil and natural gas properties of $790 million for the year ended December 31, 2019. No such impairment was recorded for the year ended December 31, 2018. Given the rate of change impacting the oil and natural gas industry described above, it is possible that circumstances requiring additional impairment testing will occur in future interim periods, which could result in potentially material impairment charges being recorded.
At December 31, 2020, there were $85 million in exploration costs and development costs and $51 million in capitalized interest that are not subject to depletion. At December 31, 2019, there were $228 million in exploration costs and development costs and $118 million capitalized interest that are not subject to depletion.
9. ASSET RETIREMENT OBLIGATIONS
The following table describes the changes to the Company’s asset retirement obligations liability for the following periods:
(1) The current portion of the asset retirement obligation is included in other accrued liabilities in the Company’s consolidated balance sheets.
The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
10. EQUITY METHOD INVESTMENTS
At December 31, 2020 and 2019, Rattler had the following investments:
The following summarizes the income (loss) of equity method investees for the periods presented:
On February 1, 2019, Rattler LLC acquired a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which owns and operates a pipeline (the “EPIC pipeline”) that transports crude oil and natural gas liquids across Texas for delivery into the Corpus Christi market. The EPIC pipeline became fully operational in April 2020.
On February 15, 2019, Rattler LLC acquired a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which owns and operates a pipeline (the “Gray Oak pipeline”) that transports crude oil from the Permian to Corpus Christi on the Texas Gulf Coast. The Gray Oak pipeline became fully operational in April 2020.
On March 29, 2019, Rattler LLC executed a short-term promissory note to Gray Oak. The note allowed for borrowing by Gray Oak of up to $123 million at a 2.52% interest rate with a maturity date of March 31, 2022. The short-term promissory note was repaid on May 31, 2019 and was terminated in the third quarter of 2020.
On July 30, 2019, Rattler LLC joined Wink to Webster Pipeline LLC as a 4% member, together with affiliates of ExxonMobil, Plains All American Pipeline, Delek US, MPLX LP and Lotus Midstream. The joint venture is developing a crude oil pipeline with origin points at Wink and Midland in the Permian Basin and delivery points at multiple Houston area locations (the “Wink to Webster pipeline”). The Wink to Webster pipeline’s main segment began interim service operation in the fourth quarter of 2020, and the joint venture is expected to begin full commercial operations in the fourth quarter of 2021. Upon completion, this pipeline will be capable of transporting approximately 1,500,000 Bbl/d.
On October 1, 2019, Rattler LLC acquired a 60% equity interest in OMOG JV LLC (“OMOG”). On November 7, 2019, OMOG acquired 100% of Reliance Gathering, LLC which owns and operates a crude oil gathering system in the Permian and was renamed as Oryx Midland Oil Gathering LLC following the acquisition. While Rattler’s equity interest is 60%, the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling minority investor.
On December 20, 2019, Rattler LLC acquired a 50% equity interest in Amarillo Rattler LLC, which currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. This joint venture also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
County, Texas, as well as incremental gas gathering and compression and regional transportation pipelines. However, development of the new processing plant has been postponed pending a recovery in commodity prices and activity levels. The Company has contracted for up to 30,000 Mcf/d of the capacity of the new processing plant pursuant to a gas gathering and processing agreement entered into with the joint venture in exchange for the Company’s dedication of certain leasehold interests to that agreement. While Rattler’s equity interest is 50%, the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling investor.
Rattler reviews its investments to determine if a loss in value which is other than temporary has occurred. If such a loss has occurred, Rattler recognizes an impairment provision. No significant impairments were recorded for Rattler’s equity method investments for the year ended December 31, 2020, 2019 or 2018. Rattler’s investees all serve customers in the oil and natural gas industry, which has been experiencing economic challenges as described above. It is possible that prolonged industry challenges could result in circumstances requiring impairment testing, which could result in potentially material impairment charges in future interim periods.
11. DEBT
The Company’s debt consisted of the following as of the dates indicated:
(1) Each of these revolving credit facilities matures on November 1, 2022.
(2) The Rattler revolving credit facility matures on May 28, 2024.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Debt maturities as of December 31, 2020, excluding debt issuance costs, premiums and discounts, are as follows:
Diamondback Notes
May 2020 Notes Offering
On May 26, 2020, the Company completed a notes offering of $500 million in aggregate principal amount of its 4.750% Senior Notes due 2025 (the “May 2020 Notes”). Interest on the May 2020 Notes accrues from May 26, 2020, and is payable in cash semi-annually on May 31 and November 30 of each year, beginning November 30, 2020. The May 2020 Notes mature on May 31, 2025. The Company received net proceeds of approximately $496 million from the offering of the May 2020 Notes. The May 2020 Notes are the Company’s senior unsecured obligations and are guaranteed by Diamondback O&G LLC (the “Guarantor”), but are not guaranteed by any of the Company’s other subsidiaries. The May 2020 Notes are senior in right or payment to any of the Company’s and the Guarantor’s future subordinated indebtedness and rank equal in right of payment with all of the Company’s and the Guarantor’s existing and future senior indebtedness. The May 2020 Notes are effectively subordinated to the Company’s and the Guarantor’s existing and future secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all of the existing and future indebtedness and other liabilities of the Company’s subsidiaries other than the Guarantor.
4.750% Senior Notes
On October 28, 2016, the Company issued $500 million in aggregate principal amount of 4.750% senior notes due 2024 (“4.750% senior notes”), under an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On September 25, 2018, the Company issued $750 million aggregate principal amount of new 4.750% senior notes as additional notes under, and subject to the terms of, the same indenture governing the 4.750% senior notes.
On December 20, 2019, the Company redeemed all of the outstanding 4.750% senior notes, which included $1.25 billion of aggregate outstanding principal at a redemption price of 103.563% plus accrued and unpaid interest on the outstanding principal amount to the Redemption Date, resulting in a loss on extinguishment of debt of $56 million. On December 5, 2019, the indenture governing the 4.750% senior notes was fully satisfied and discharged and the guarantors were released from their guarantees of the 4.750% senior notes. The Company funded the redemption with a portion of the net proceeds from the issuance of the December 2019 Notes.
2025 Senior Notes
On December 20, 2016, the Company issued $500 million in aggregate principal amount of 5.375% senior notes due 2025, under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee (the “2025 indenture”). On January 29, 2018, the Company issued an additional $300 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture and received approximately $308 million in net proceeds, after deducting discounts and offering expenses, but disregarding accrued interest. The Company used these net proceeds to repay a portion of the outstanding borrowings under its revolving credit facility. Collectively, the aggregate $800 million principal amount of 5.375% senior notes due in 2025 are referred to as the 2025 senior notes.
All of the 2025 senior notes will mature on May 31, 2025 and the 5.375% per annum interest is payable semi-annually, in arrears on May 31 and November 30 each year. Currently, the 2025 senior notes are not guaranteed by any of the
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Company’s subsidiaries other than its restricted subsidiary, Diamondback O&G LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries. These notes may be guaranteed by future restricted subsidiaries.
The Company may on any one or more occasions redeem some or all of the 2025 senior notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption.
December 2019 Notes Offering
On December 5, 2019, the Company issued $1.0 billion in aggregate principal amount of 2.875% senior notes due 2024 (the “2024 notes”), $800 million in aggregate principal amount of 3.250% senior notes due 2026 (the “2026 notes”), and $1.2 billion aggregate principal amount of 3.500% senior notes due 2029, (the “2029 notes” and, together with the 2024 notes and the 2026 notes, the “December 2019 Notes”). The 2024 notes will mature on December 1, 2024, the 2026 notes will mature on December 1, 2026 and the 2029 notes will mature on December 1, 2029. Interest will accrue and be payable semi-annually, in arrears on June 1 and December 1 of each year, commencing on June 1, 2020. The December 2019 Notes are fully and unconditionally guaranteed by Diamondback O&G LLC and are not guaranteed by any of the Company’s other subsidiaries.
The December 2019 Notes were issued under an indenture, dated as of December 5, 2019, among the Company and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019 (the “December 2019 Notes Indenture”).
The Company may redeem (i) the 2024 Notes in whole or in part at any time prior to November 1, 2024 (one month prior to the maturity date of the 2024 Notes), (ii) the 2026 Notes in whole or in part at any time prior to October 1, 2026 (two months prior to the maturity date of the 2026 Notes) and (iii) the 2029 Notes in whole or in part at any time prior to September 1, 2029 (three months prior to the maturity date of the 2029 Notes) (each such date, a “par call date”), in each case at the redemption price set forth in the indenture governing the December 2019 Notes. If any of the December 2019 Notes are redeemed on or after their respective par call dates, in each case, they will be redeemed at a redemption price equal to 100% of the principal amount plus interest accrued thereon up to but not including the redemption date.
Upon the occurrence of a Change of Control Triggering Event (as defined in the indenture governing the December 2019 Notes), holders may require the Company to purchase some or all of their December 2019 Notes for cash at a price equal to 101% of the principal amount of the December 2019 Notes being purchased, plus accrued and unpaid interest, if any, to the date of purchase.
The indenture governing the December 2019 Notes contains customary terms and covenants, including limitations on the Company’s ability and the ability of certain of its subsidiaries to incur liens securing funded indebtedness and on the Company’s ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of its assets.
Second Amended and Restated Credit Facility
The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. On June 28, 2019, the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied (the “investment grade changeover date”). On November 20, 2019, Diamondback O&G LLC caused Diamondback O&G LLC to deliver a notice as borrower under the revolving credit facility to trigger the “investment grade changeover date.” As of December 31, 2020, the maximum credit amount available under the credit agreement is $2.0 billion. As of December 31, 2020, the Company had approximately $23 million of outstanding borrowings under its revolving credit facility and $1.98 billion available for future borrowings under the revolving credit facility. As of December 31, 2020, there was an aggregate of $3 million in letters of credit outstanding under the credit agreement, which reduce available borrowings on a dollar for dollar basis.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Diamondback O&G LLC is the borrower under the credit agreement and, as of December 31, 2020, the credit agreement is guaranteed by Diamondback Energy, Inc. None of the Company’s other subsidiaries are guarantors under the revolving credit facility.
The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to the alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5%, and 3 month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin with range from 0.125% to 1.0% per annum and from 1.125% to 2.0% per annum in the case of LIBOR, in each case, depending on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt. The weighted average interest rates on the credit facility were 2.02%, 4.10% and 3.75% for the years ended December 31, 2020, 2019 and 2018, respectively.
Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction of the aggregate maximum credit amount and (b) at the maturity date of November 1, 2022.
The credit agreement contains a financial covenant that requires us to maintain a Total Net Debt to Capitalization Ratio (as defined in the credit agreement) of no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets.
As of December 31, 2020 and 2019, the Company was in compliance with all financial maintenance covenants under the revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.
Energen Notes
At the effective time of the Merger, Energen became the Company’s wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes (the “Energen Notes”), issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee (the “Energen Indenture”). As of December 31, 2020, the aggregate principal amount of the Energen Notes had been reduced to $311 million, consisting of: (1) $191 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $100 million of 7.125% notes due on February 15, 2028 and (3) $20 million of 7.32% notes due on July 28, 2022.
The Company used the net proceeds from the offering of May 2020 Notes, among other things, to make an equity contribution to Energen to purchase $209 million in previously outstanding aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer.
During the third quarter of 2020, the Company repurchased $10 million in principal amount of the outstanding Energen 7.35% medium-term notes due on July 28, 2027 at a price of 120% of the aggregate principal amount, which resulted in an immaterial loss on extinguishment of debt.
The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as a wholly owned subsidiary, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen if any, and are effectively subordinated to Energen’s senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. None of the Company’s other subsidiaries guarantee the Energen Notes.
The Energen Indenture contains certain covenants that, subject to certain exceptions and qualifications, limit Energen’s ability to incur or suffer to exist liens, to enter into sale and leaseback transactions, to consolidate with or merge
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
into any other entity, and to convey, transfer or lease its properties and assets substantially as an entirety to any person or entity. The Energen Indenture not include a restriction on the payment of dividends.
On November 29, 2018, Energen guaranteed the Company’s indebtedness under its credit facility and granted a lien on certain of its assets to secure such indebtedness, and on December 21, 2018, Energen’s subsidiaries guaranteed the Company’s indebtedness under its credit agreement and granted liens on certain of their assets to secure such indebtedness.
Viper’s Credit Agreement
On July 20, 2018, Viper LLC, as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended (the “Viper credit agreement”), provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $580 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. The borrowing base was reaffirmed at $580 million by the lenders during the regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of December 31, 2020, Viper LLC had $84 million of outstanding borrowings and $496 million available for future borrowings under the Viper credit agreement. The weighted average interest rates on borrowings under the Viper credit agreement were 2.20%, 4.51%, and 4.37% for the years ended December 31, 2020, 2019 and 2018, respectively.
The outstanding borrowings under the Viper credit agreement bear interest at a per annum rate elected by Viper LLC that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. Viper LLC is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of Viper and Viper LLC.
The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $1.0 billion in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.
As of December 31, 2020, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Viper’s Notes
On October 16, 2019, Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of $500 million (the “Viper Notes”). Viper received gross proceeds of $500 million from the such offering, which it loaned to Viper LLC. Viper LLC paid the expenses of the offering, resulting in net proceeds of the offering of $490 million, which Viper LLC used to pay down borrowings under the Viper credit agreement.
The Viper Notes were issued under an indenture, dated as of October 16, 2019, among Viper, as issuer, Viper LLC, as guarantor and Wells Fargo, as trustee (the “Viper Indenture”). Pursuant to the Viper Indenture and the Viper Notes, interest on the Viper Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2020. The Viper Notes will mature on November 1, 2027.
During the year ended December 31, 2020, Viper repurchased $20 million of outstanding principal of the Viper notes at a cash price ranging from 97.5% to 98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt, and $480 million in aggregate principal amount remained outstanding at December 31, 2020.
Viper LLC guarantees the Viper Notes pursuant to the Viper Indenture. Neither the Company nor any of its other subsidiaries guarantee the Viper Notes.
The Viper Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Viper’s ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events.
Rattler’s Credit Agreement
In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo, as administrative agent, and a syndicate of banks, as lenders party thereto (the “Rattler credit agreement”).
The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid at the maturity date of May 28, 2024. The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. As of December 31, 2020, Rattler LLC had $79 million of outstanding borrowings and $521 million available for future borrowings under the Rattler credit agreement. The weighted average interest rates on borrowings under the Rattler credit agreement were 2.10% and 3.13% for the years ended December 31, 2020 and 2019, respectively.
The outstanding borrowings under the Rattler credit agreement bear interest at a per annum rate elected by Rattler LLC that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum for prime-based loans and 1.250% to 2.250% per annum for LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as defined in the Rattler credit agreement). Rattler LLC is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused portion of the commitment, which fee is also dependent on the Consolidated Total Leverage Ratio.
The Rattler credit agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler, Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowing Rattler LLC or Rattler to issue unsecured debt securities and an exception allowing payment of distributions if no default exists. The Rattler credit agreement may be used to fund capital expenditures, to finance working
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
capital, for general company purposes, to pay fees and expenses related to the credit agreement, and to make distributions permitted under the Rattler credit agreement.
The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below:
As of December 31, 2020, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control.
Rattler’s Notes
On July 14, 2020, Rattler completed an offering of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025, (the “Rattler Notes”). The Rattler Notes mature on July 15, 2025, and interest on the Rattler Notes is payable on January 15 and July 15 of each year, beginning on January 15, 2021. Rattler received net proceeds of approximately $490 million from the Rattler Notes and loaned the gross proceeds to Rattler LLC to repay then outstanding borrowings under the Rattler Credit Agreement. The Rattler Notes are senior unsecured obligations of Rattler, rank equally in right of payment with all of Rattler’s existing and future senior indebtedness and initially are guaranteed on a senior unsecured basis by Rattler LLC, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. Neither the Company nor Rattler’s General Partner guarantee the Rattler Notes. In the future, each of Rattler’s restricted subsidiaries that either (1) guarantees any of its or a guarantor’s other indebtedness or (2) is classified as a domestic restricted subsidiary under the indenture governing the Rattler Notes and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the Rattler Notes.
The indenture under which the Rattler Notes were issued contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Rattler’s ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events.
Alliance with Obsidian Resources, L.L.C.
The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300 million, to fund drilling programs on locations provided by the Company. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo Agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9%
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15%, while the Company’s interest will increase to 85%. As of December 31, 2020, the amount due to CEMOF related to this alliance was $79 million. As of December 31, 2020, fifteen joint wells have been drilled and completed.
Interest expense
The following amounts have been incurred and charged to interest expense for the years ended December 31, 2020, 2019 and 2018:
12. CAPITAL STOCK AND EARNINGS PER SHARE
The Company did not complete any equity offerings during the years ended December 31, 2020, 2019 and 2018.
Viper Equity Offerings
For information regarding Viper’s completed equity offerings during the years ended December 31, 2019 and 2018, refer to Note 5-Viper Energy Partners LP.
Rattler’s Initial Public Offering
For information regarding Rattler’s initial public offering during the year ended December 31, 2019, refer to Note 6-Rattler Midstream LP.
Stock Repurchase Program
In May 2019, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock through December 31, 2020. Purchases under the repurchase program were made from time to time in open market or privately negotiated transactions, and were subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program did not require the Company to acquire any specific number of shares. During the years ended December 31, 2020 and 2019, the Company repurchased $98 million and $598 million, respectively, of its common stock under the repurchase program. The repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020.
Earnings Per Share
The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, the per share earnings of Viper and Rattler are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiaries.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
(1) For the year ended December 31, 2020, there were 696,223 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive due to recording a net loss.
Change in Ownership of Consolidated Subsidiaries
The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period:
(1) The year ended December 31, 2020 includes an adjustment to non-controlling interest for Rattler of $329 million and to additional paid-in-capital of $329 million to reflect the ownership structure that was effective at June 30, 2020. The adjustment had no impact on earnings.
13. EQUITY-BASED COMPENSATION
The following table presents the effects of the equity and stock based compensation plans and related costs:
Restricted Stock Units
Under the Equity Plan, approved by the Board of Directors, the Company is authorized to issue restricted stock and restricted stock units to eligible employees. The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The following table presents the Company’s restricted stock awards and units activity under the Equity Plan during the year ended December 31, 2020:
The aggregate fair value of restricted stock units that vested during the years ended December 31, 2020, 2019 and 2018 was $25 million, $45 million and $19 million, respectively. As of December 31, 2020, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $41 million. Such cost is expected to be recognized over a weighted-average period of 2.3 years.
During the year ended December 31, 2020, the Company modified an insignificant amount of restricted stock units to include dividend equivalent rights during the vesting period which did not result in any incremental compensation costs.
Performance-Based Restricted Stock Units
To provide long-term incentives for executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three-year performance period.
In February 2018, eligible employees received performance restricted stock unit awards totaling 117,423 units from which a minimum of 0% and a maximum of 200% units could be awarded based upon the TSR during the performance period of January 1, 2018 to December 31, 2020, subject to continued employment. All remaining awards under this grant cliff vested at December 31, 2020.
In March 2019, eligible employees received performance restricted stock unit awards totaling 199,723 units from which a minimum of 0% and a maximum of 200% units could be awarded based upon the TSR during the performance period of January 1, 2019 to December 31, 2021 and cliff vest at December 31, 2021 subject to continued employment. In March 2019, eligible employees received performance restricted stock unit awards totaling 32,958 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2019 to December 31, 2021 and vest in five equal installments beginning on March 1, 2025.
In March 2020, eligible employees received performance restricted stock unit awards totaling 225,047 units from which a minimum of 0% and a maximum of 200% units could be awarded based upon the TSR during the three-year performance period of January 1, 2020 to December 31, 2022 and cliff vest at December 31, 2022 subject to continued employment. The initial payout of the March 2020 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%.
The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period.
The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2020:
(1)Includes units granted to satisfy the final payout of vested performance restricted stock units based on the TSR ranking for the performance period.
(2)A maximum of 935,698 units could be awarded based upon the Company’s final TSR ranking.
As of December 31, 2020, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $22 million, which is expected to be recognized over a weighted-average period of 2.1 years.
Rattler Long-Term Incentive Plan
On May 22, 2019, the board of directors of Rattler’s General Partner adopted the Rattler Midstream LP Long Term Incentive Plan (“Rattler LTIP”), for employees, consultants and directors of Rattler’s General Partner and any of its affiliates, including Diamondback, who perform services for Rattler. The Rattler LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards.
Under the Rattler LTIP, the board of directors of Rattler’s General Partner is authorized to issue phantom units to eligible employees and non-employee directors. Rattler estimates the fair value of phantom units as the closing price of Rattler’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting, the phantom units entitle the recipient to one common unit of Rattler for each phantom unit. The recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one phantom unit between the grant date and the vesting date.
The following table presents the phantom unit activity under the Rattler LTIP for the year ended December 31, 2020:
The aggregate fair value of phantom units that vested during the year ended December 31, 2020 was $9 million. As of December 31, 2020, the unrecognized compensation cost related to unvested phantom units was $30 million which is expected to be recognized over a weighted-average period of 3.2 years.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
14. INCOME TAXES
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and the Texas margin tax. The Company and its subsidiaries, other than Viper, Viper LLC, Rattler and Rattler LLC, file a federal corporate income tax return on a consolidated basis. As discussed further below, Viper is a taxable entity for federal income tax purposes effective May 10, 2018, and as such files a federal corporate income tax return including the activity of its investment in Viper LLC. Subsequent to Rattler’s election to be treated as a corporation for federal income tax purposes effective May 24, 2019, Rattler is also a taxable entity and as such files a federal corporate income tax return including the activity of its investment in Rattler LLC. Viper’s and Rattler’s provision for income taxes is included in the Company’s consolidated income tax provision and, to the extent applicable, in net income attributable to the non-controlling interest.
The Company’s effective income tax rates were 19.1%, 13.0% and 15.1% for the years ended December 31, 2020, 2019 and 2018, respectively. Total income tax benefit for the year ended December 31, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss for the period primarily due to the impact of recording a valuation allowance on Viper’s deferred tax assets, partially offset by state income taxes net of federal benefit and by tax benefit resulting from the carryback of federal net operating losses. Total income tax expense for the year ended December 31, 2019 differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to the impact of deferred taxes recognized as a result of Viper’s change in tax status and state income taxes net of federal benefit. Total income tax expense for the year ended December 31, 2018 differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to the impact of deferred taxes recognized as a result of Viper’s change in tax status, net income attributable to the noncontrolling interest, and state income taxes net of federal benefit.
The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. This legislation included a number of provisions applicable to U.S. income taxes for corporations, including providing for carryback of certain net operating losses, accelerated refund of minimum tax credits, and modifications to the rules limiting the deductibility of business interest expense. The Company considered the impact of this legislation in the period of enactment, resulting in current income tax benefit of $62 million, offset by deferred income tax expense of $38 million, for the year ended December 31, 2020 related to the carryback of approximately $179 million of the Company’s federal net operating losses to tax years in which the corporate income tax rate was 35%. Prior to the enactment of the CARES Act in the first quarter of 2020, there was no tax refund available to the Company with respect to its losses, resulting in deferred tax assets associated with federal net operating loss carryforwards at the statutory 21% corporate income tax rate. As a result of the refund associated with such carryback as well as the accelerated refund available for minimum tax credits, the Company’s current federal taxes receivable totaled approximately $100 million as of December 31, 2020.
The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2020, 2019 and 2018 are as follows:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
A reconciliation of the statutory federal income tax amount from continuing operations to the recorded expense is as follows:
The components of the Company’s deferred tax assets and liabilities as of December 31, 2020 and 2019 are as follows:
The Company had net deferred tax liabilities of approximately $0.7 billion and $1.7 billion at December 31, 2020 and 2019, respectively. On November 29, 2018, the Company completed its acquisition of Energen. For federal income tax purposes, the acquisition was a tax-free merger whereby the Company’s tax basis in Energen assets and liabilities was unaffected by the acquisition. As of December 31, 2019, the Company had completed its purchase price allocation for the acquisition, including a deferred tax liability of $1.4 billion associated with the acquired assets.
The Company incurred a tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drilling and development costs under current law. There is no tax refund available to the Company as a result of its loss, nor is there any current federal income tax payable. At December 31, 2020, the Company had approximately $0.4 billion of federal NOLs expiring in 2032 through 2037 and $1.9 billion of federal NOLs with an indefinite carryforward
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
life, including NOLs acquired from Energen. The Company principally operates in the state of Texas and is subject to Texas Margin Tax, which currently does not include an NOL carryover provision. The Company’s federal tax attributes acquired from Energen are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period. The Company believes that the application of Section 382 will not have an adverse effect on future usage of the Company’s NOLs and credits.
In addition to the carryback of certain of the Company’s federal NOLs pursuant to the CARES Act as noted above, modifications to the rules regarding deductibility of business interest expense resulting from enactment of the CARES Act and from the issuance of final regulations by the U.S. Department of Treasury in July 2020 resulted in a reduction to carryforwards of the Company’s business interest expense and corresponding increase to its federal net operating loss carryforwards.
As of December 31, 2020, the Company had a valuation allowance of $5 million primarily related to certain state NOL carryforwards which the Company does not believe are realizable as it does not anticipate future operations in those states and a valuation allowance of $161 million related to Viper’s deferred tax assets, as discussed further below. Management’s assessment at each balance sheet date included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities. Management believes that the balance of the Company’s NOLs are realizable to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. As of December 31, 2020, management determined that it is more likely than not that the Company will realize its remaining deferred tax assets.
As discussed further in Note 5-Viper Energy Partners LP, on March 29, 2018, Viper announced that the Board of Directors of its General Partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. The transactions undertaken in connection with the change in Viper’s tax status were not taxable to the Company. Subsequent to Viper’s change in tax status, Viper’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest.
At December 31, 2020, the Company’s net deferred tax liabilities include deferred tax assets of approximately $11 million related to Viper’s NOL carryforwards and approximately $150 million related to Viper’s investment in Viper LLC, approximately $115 million of which was recorded as a result of Viper’s change in tax status. Based on information available regarding unitholders; tax basis, Viper revised its estimate of the difference between its tax basis and its basis for financial accounting purposes in Viper LLC on the date of the tax status change, resulting in deferred income tax benefit of $42 million and $73 million included in the Company’s consolidated income tax provision for the years ended December 31, 2019 and 2018, respectively. As of December 31, 2020, Viper had federal NOL carryforwards of approximately $50 million which may be carried forward indefinitely to offset future taxable income.
As of December 31, 2020, Viper had a valuation allowance of approximately $161 million related to deferred tax assets that Viper does not believe are more likely than not to be realized. Management considers the likelihood that Viper’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. The determination to record a valuation allowance was based on Management’s assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets as required by applicable accounting standards. In light of those criteria for recognizing the tax benefit of deferred tax assets, the assessment resulted in application of a valuation allowance against Viper’s federal deferred tax assets as of March 31, 2020 and subsequent balance sheet dates within the year ended December 31, 2020.
As discussed further in Note 6-Rattler Midstream LP, on May 28, 2019, Rattler completed its initial public offering. Even though Rattler is organized as a limited partnership under state law, Rattler is subject to U.S. federal and state income tax at corporate rates, subsequent to the effective date of Rattler’s election to be treated as a corporation for U.S. federal income tax purposes. As such, Rattler’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest.
At December 31, 2020, the Company’s net deferred tax liabilities include a deferred tax asset of approximately $58 million related to Rattler’s investment in Rattler LLC. In the second quarter of 2020, the Company recorded an increase through stockholders’ equity to the carrying value of its investment in Rattler LLC. A corresponding adjustment to the noncontrolling interest resulted in a decrease in Rattler’s deferred tax liability related to its investment in Rattler LLC and a
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
total net deferred tax asset balance for Rattler. Rattler incurred an NOL in the current year due principally to Rattler LLC’s tax deductions for accelerated depreciation, which exceeded its other items of taxable income. At December 31, 2020, Rattler has federal net operating loss carryforwards of approximately $75 million which may be carried forward indefinitely to offset future taxable income.
Management considers the likelihood that Rattler’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. At December 31, 2020, Rattler’s assessment included consideration of all available positive and negative evidence, including Rattler’s projected future taxable income and the anticipated timing of reversal of deferred tax assets. As a result of the assessment, management determined that it is more likely than not that Rattler will realize its deferred tax assets as of December 31, 2020.
The following table sets forth changes in the Company’s unrecognized tax benefits:
The Company recognizes the tax benefit from a tax position only if it is more likely than not that it will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. During the year ended December 31, 2020, the statute of limitations related to an uncertain tax position of the Company expired, and upon expiration the Company recognized tax benefit of $0.3 million and recorded a reduction to interest expense of less than $0.1 million. The Company’s federal and state income tax returns for 2012 through the current tax year remain open and subject to examination by the IRS and major state taxing jurisdictions. Energen is currently under IRS examination of its federal consolidated income tax returns for 2014 and 2016. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax positions may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, the Company does not expect the change in unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.
The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2020 and 2019, there was less than $0.2 million of interest and no penalties related to each period associated with uncertain tax positions recognized in the Company’s consolidated financial statements.
15. DERIVATIVES
All derivative financial instruments are recorded at fair value in the accompanying balance sheet. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”
Commodity Contracts
The Company has entered into multiple crude oil, natural gas, natural gas liquids and diesel fuel derivatives, indexed to the respective indices as noted in the table below, to reduce price volatility associated with certain of its oil and natural gas sales.
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk.
As of December 31, 2020, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed:
(1) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.
(2) The Company has rolling hedge basis swaps for the differential between the NYMEX prices between the calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, oil price for the notional volumes covered by the rolling hedge basis swap contracts.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Interest Rate Swaps
The Company currently uses interest rate swaps to reduce the Company’s exposure to variable rate interest payments associated with the Company’s revolving credit facility. The interest rate swaps have not been designated as hedging instruments and as a result, the Company recognizes all changes in fair value immediately in earnings.
See Note 18-Subsequent Events for discussion of derivative transactions which occurred subsequent to December 31, 2020.
Balance sheet offsetting of derivative assets and liabilities
The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 16-Fair Value Measurements for further details.
Gains and Losses on Derivative Instruments
None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:
(1)The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million.
(2)The year ended December 31, 2019 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $43 million.
16. FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.
Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
The Company estimates the fair values of proved oil and natural gas properties assumed in business combinations using discounted cash flow techniques and based on market assumptions as to the future commodity prices, internal estimates of future quantities of oil and natural gas reserves, future estimated rates of production, expected recovery rates and risk-adjustment discounts. The estimated fair values of unevaluated oil and natural gas properties were based on the location, engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of business combinations are estimated using the same assumptions and methodology as described in Note 2-Summary of Significant Accounting Policies.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments and Viper’s investment. Viper measured its previously outstanding investment, which was included in other assets on the consolidated balance sheet at December 31, 2019, utilizing the fair value option, and as such the investment was classified as Level 1 in the fair value hierarchy. The fair values of the Company’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.
The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2020 and December 31, 2019. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:
(1)The carrying value includes associated deferred loan costs and any remaining discount or premium.
The fair values of the revolving credit facility, the Viper credit agreement and the Rattler credit agreement approximate their carrying values based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair values of the outstanding notes were determined using the December 31, 2020 quoted market prices, a Level 1 classification in the fair value hierarchy.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Fair Value of Financial Assets
The carrying amount of cash and cash equivalents, receivables, funds held for escrow, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.
17. COMMITMENTS AND CONTINGENCIES
The Company is a party to various legal proceedings, disputes and claims arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable, and the amount of the loss can be reasonably estimated.
Commitments
The following is a schedule of minimum future payments with commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2020:
(1)The Company has committed to transport gross quantities of crude oil on various pipelines under a variety of contracts including throughput and take-or-pay agreements. The Company’s failure to purchase the minimum level of quantities would require it to pay shortfall fees up to the amount of the original monthly commitment amounts included in the table above.
(2)The Company has committed to purchase minimum quantities of sand for use in its drilling operations. Our failure to purchase the minimum level of quantities would require us to pay shortfall fees up to the commitment amounts included in the table above.
(3)Rattler entered into a minimum volume commitment to purchase produced water disposal services under a 14 year agreement beginning in 2021.
At December 31, 2020, the Company’s delivery commitments covered the following gross volumes of oil:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
As of December 31, 2020, Rattler’s anticipated future capital commitments for its equity method investments total $72 million in the aggregate. The timing of when capital commitments will be requested can vary, but at December 31, 2020, approximately $57 million of the remaining commitment is expected to be funded in 2021, $7 million in 2022 and $8 million in 2023.
18. SUBSEQUENT EVENTS
Announced Acquisition of QEP Resources
On December 21, 2020, the Company announced a definitive agreement to acquire QEP Resources Inc. (“QEP”) in an all-stock transaction valued at $2.2 billion including QEP’s net debt of $1.6 billion as of September 30, 2020 based upon closing share prices on October 16, 2020. The consideration will consist of 0.050 shares of Diamondback common stock for each share of QEP common stock, representing an implied value to each QEP stockholder of $2.29 per share based on the closing price of Diamondback common stock on December 18, 2020. The transaction was unanimously approved by the Board of Directors of each company. The transaction is anticipated to close shortly following the special meeting of QEP Stockholders, which is scheduled for March 16, 2021, subject to QEP stockholder approval and other customary closing conditions. See Item 1A. “Risk Factors” for further discussion of risks related to the QEP acquisition.
Announced Acquisition of Guidon Operating LLC
On December 21, 2020, the Company announced a definitive purchase agreement to acquire all leasehold interests and related assets of Guidon Operating LLC (“Guidon”) in exchange for 10.6 million shares of Diamondback common stock and $375 million of cash. In accordance with the terms of the purchase agreement, the Company deposited $50 million into an escrow account in December 2020, which will be released to Guidon upon the closing of the transaction. The cash portion of this transaction is expected to be funded through a combination of cash on hand and borrowings under the Company’s credit facility. The transaction is anticipated to close on February 26, 2021.
Fourth Quarter 2020 Dividend Declaration
On February 18, 2021, the Board of Directors of the Company declared a cash dividend for the fourth quarter of 2020 of $0.40 per share of common stock, payable on March 11, 2021 to its stockholders of record at the close of business on March 4, 2021.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Commodity Contracts
Subsequent to December 31, 2020, the Company entered into new fixed price swaps and basis swaps, costless collars and roll hedges. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges noted in the table below. When aggregating multiple contracts, the weighted average contract price is disclosed. The following table presents the derivative contracts entered into by the Company between January 1, 2021 and February 19, 2021:
(1) The Company has fixed price basis swaps for the spread between the WTI Midland crude oil price and the NYMEX WTI crude oil price as well as the spread between the Waha Hub natural gas price and the Henry Hub natural gas price. The weighted average differential represents the amount of reduction to Cushing, Oklahoma oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.
(2) The Company has rolling hedge basis swaps for the differential between the NYMEX prices between the calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to Cushing, Oklahoma oil price for the notional volumes covered by the rolling hedge basis swap contracts.
Interest Rate Swaps
The following table presents the interest rate swap contracts terminated by the Company between January 1, 2021 and February 19, 2021:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
19. SEGMENT INFORMATION
The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which includes midstream services and real estate operations. All of the Company’s equity method investments are included in the midstream operations segment. The segments comprise the structure used by its Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance.
The following tables summarize the results of the Company's operating segments during the periods presented:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
20. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)
The Company’s oil and natural gas reserves are attributable solely to properties within the United States.
Capitalized oil and natural gas costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Costs incurred in oil and natural gas activities
Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:
Results of Operations from Oil and Natural Gas Producing Activities
For revenues and expenses related to the production and sale of oil, natural gas and natural gas liquids, see the results of the Company's upstream business segment in Note 19-Segment Information.
Oil and Natural Gas Reserves
Proved oil and natural gas reserve estimates as of December 31, 2020, 2019 and 2018 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The changes in estimated proved reserves are as follows:
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
During the year ended December 31, 2020, the Company’s extensions and discoveries of 302,092 MBOE resulted primarily from the drilling of 682 new wells and from 298 new proved undeveloped locations added. Viper royalty interests accounted for 8% of the extension volumes. The Company’s downward revisions of previous estimates of 6,290 MBOE were the result of negative revisions due to lower product pricing of 54,645 MBOE, which were partially offset by positive revisions of 23,066 MBOE associated with a reduction in lease operating expenses, resulting in a total negative pricing revision of 31,579 MBOE. Downgrades of 31,074 MBOE are primarily from changes in the corporate development plan. These revisions were offset by positive performance revisions of 56,362 MBOE associated with less gas flaring and a corresponding increase in natural gas liquid recoveries.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
During the year ended December 31, 2019, the Company’s extensions and discoveries totaling 376,287 MBOE resulted primarily from the drilling of 283 new wells and from 291 new proved undeveloped locations added. Viper royalty interests accounted for 5% of the extension volumes. The Company’s downward revisions of 117,898 MBOE were the result of proved undeveloped downgrades associated with inventory refinement following the Energen acquisition along with updated development plans and lower realized prices. Purchases of 21,092 MBOE were the result of 10,939 MBOE of working interest purchases and 10,153 MBOE of Viper royalty purchases, excluding mineral interests dropped down to Viper.
During the year ended December 31, 2018, the Company’s extensions and discoveries of 202,089 MBOE resulted primarily from the drilling of 135 new wells and from 138 new proved undeveloped locations added in which the Company owns a working interest. Viper royalty interests accounted for 10% of the extension volumes. The Company’s revisions of previous estimates were primarily the result of positive technical and performance revisions of 14,218 MBOE, upward revisions of 6,032 MBOE due to higher pricing and downward revisions of 4,815 MBOE from PUD reclassifications due to timing. Purchases of 486,992 MBOE were the result of 477,686 MBOE of working interest purchases, primarily attributable to Energen, and 9,306 MBOE of Viper royalty purchases.
At December 31, 2020, the Company’s estimated PUD reserves were approximately 499,643 MBOE, a 131,784 MBOE increase over the reserve estimate at December 31, 2019 of 367,859 MBOE. The following table includes the changes in PUD reserves for 2020 (MBOE):
The increase in proved undeveloped reserves was primarily attributable to extensions of 220,023 MBOE from 277 gross (236 net) wells in which the Company has a working interest and 15,686 MBOE from 299 gross wells in which Viper owns royalty interests. Of the 277 gross working interest wells, 98 were in the Delaware Basin. Transfers of 89,133 MBOE were the result of drilling or participating in 102 gross (94 net) horizontal wells in which the Company has a working interest and 82 gross wells in which the Company has a royalty interest or mineral interest through Viper. The Company owns a working interest in 78 of the 82 gross Viper wells. Downward revisions of 15,742 MBOE were the result of (i) negative revisions of 4,226 MBOE due to lower product pricing, which were partially offset by positive revisions of 1,494 MBOE associated with a reduction in lease operating expenses, resulting in a total negative pricing revision of 2,732 MBOE, and (ii) PUD downgrades of 26,329 MBOE primarily from changes in the corporate development plan. These revisions were offset with positive performance revisions of 13,319 MBOE associated with less gas flaring and a corresponding increase in shrunk gas and natural gas liquid recoveries.
As of December 31, 2020, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2020, approximately $381 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2020, 2019 and 2018.
(1) Includes $1.0 billion, $1.3 billion, and $1.1 billion, for the years ended December 31, 2020, 2019 and 2018, respectively, attributable to the Company’s consolidated subsidiary, Viper, in which there is a 42% non-controlling interest at December 31, 2020.
The table below presents the unweighted arithmetic average first-day-of-the-month price for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows.
Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: