Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible–from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations–prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 20172022 were estimated using a deterministic method.
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods:
(1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves forIn general, our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 90% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 10%In certain cases where there was inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the estimates was considered to be inappropriate, the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.
To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scottwe considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.
The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2017, 20162022, 2021 and 2015 based on the reserve reports prepared by Ryder Scott. Each reserve report has been2020, which were prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States.
All of our PUD drilling locations are scheduled to be drilled within five years from the date they were initially recorded. As of December 31, 2017,2022, none of our total proved reserves were classified as proved developed non-producing.
Our net interest in production from our mineral interests is based on lease royalty terms which vary from property to property. Our interest in the majority of these properties is perpetual in nature, however approximately 6.27%an insignificant portion of theour net royalty acreage consists of over-ridingoverriding royalty interests which may be subject to expiration. Net royalty acres are defined as gross acreagenet mineral acres multiplied by the average lease royalty interest.interest and other burdens.
The oil and natural gas industry is intensely competitive, and we compete with other companies that may have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties, mineral interests and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices.prices than operators of our mineral and royalty acreage. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.
Our ability to acquire additional mineral, royalty, overriding royalty, net profits and similar interests in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for these and other oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions such as the severe winter storms in the Permian Basin in early 2021, and lease stipulations, can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for our operators in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.
The following disclosure describes regulation more directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties. To the extent we elect in the future to engage in the exploration, development and production of oil and natural gas properties, we would be directly subject to the same regulations described below. For purposes of this section, where applicable, references to “we,” “us,” and “our” refer to Viper Energy Partners LP to the extent the partnership were to acquire working interests in the future as well as to any operators of our properties, including our current operators.
Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.
Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations.
Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our business and prospects.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase the costs to manage and dispose of wastes.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.
The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” or the CWA, the Safe Drinking Water Act, the Oil Pollution Act, or the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water ActCWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “–Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
The operations of our operators are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states, and some counties and municipalities, in which our operators conduct business also regulate one or more of the following:
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that our operators can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure our unitholders that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.
Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, the U.S. Congress could reenact price controls in the future.
Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act, and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as to our or their competitors.
Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure our unitholders that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations our operators can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
We do not have any employees. We are managed and operated by the board of directors and executive officers of our general partner.General Partner. All of the employeesindividuals that conduct our business, including our executive officers, are employed by Diamondback.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge on the Investor Relations page of our website at www.viperenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC. Reports filed or furnished with the SEC are also made available on its website at www.sec.gov.
ITEM 1A. RISK FACTORS
We may not have sufficient available cash to pay any quarterly distribution on our common units.units, our cash available for distribution may vary significantly from quarter to quarter and the board of directors of our General Partner has recently modified, and may in the future further modify or revoke, our cash distribution policy at any time at its discretion. Our distribution policy could limit our ability to grow and make acquisitions.
We may not have sufficient available cash each quarter to enable us to pay any distributions to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. The amount of cash we have to distribute each quarter principally depends primarily upon the amount of royalty revenuesincome we generate, which areis dependent upon the volumes of production sold and the prices that our operators realize from the sale of such
the timing and amount of capital expenditures by our operators, which could be significantly more than anticipated;
the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
the rate of production of the reserves.
The operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in our royalty revenuesincome and cash available for distribution to our unitholders. If reductions in production by the operators are implemented on our properties and sustained, our revenues may also be substantially affected. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures by operators than we currently anticipate.
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, complete 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.
We may not be able to terminate our leases if any of our operators declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.
A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to bankruptcy proceedings that could prevent the execution of a new lease or the assignment of the existing lease to another operator. In addition, if we enter into a new lease, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.
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 propertiesmineral and royalty acreage, we could experience any of the samethese conditions at the same time, resulting in a relatively greater impact on our results of operationsus than they might have on other companies that have a more diversified portfolio of properties.assets. Such delays or interruptions could have a material adverse effect on our business, financial condition and resultscash flow.
In addition to the geographic concentration of our producing properties described above,mineral and royalty acreage, as of December 31, 2017, all2022, most of our proved reserves were attributable toare concentrated in the Wolfberry resource 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 usour operators to permanently or temporarily shut-in all of our wells within a field.
Our future 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 successful exploration or development activities are conducted on our properties or we acquire properties containing proved reserves, or both. To increase reservesmineral and production, we would need to undertake development, exploration and other replacement activities or use third parties to accomplish these activities. Substantial capital expenditures will be necessary for the development, production, exploration and acquisition of oil and natural gas reserves. Neither we nor our third-party operators may 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 efforts to drill productive wells at low finding and development costs may be unsuccessful. In addition, we do not expect to retain cash from our operations for replacement capital expenditures. Furthermore, although our revenues and cash available for distribution may increase if prevailing oil and natural gas prices increase significantly, finding costs for additional reserves could also increase.royalty acreage.
Our failure to successfully identify, complete and integrate acquisitions of properties or businesses could slow our growth and adversely affect our results of operations and cash available for distribution.
There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:
including; recoverable reserves;
reserves, future oil and natural gas prices and their applicable differentials;
differentials, operating costs;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 including title or environmental issues, 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. Unless our operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.
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. Further, these acquisitions may be in geographic regions in which we do not currently hold properties, which could result in unforeseen operating difficulties. In addition, ifproperties. If we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements.requirements and other unforeseen difficulties. 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 effectively integrate effectively the acquired business into our existing operations. Theoperations, the process of integrating acquired businesseswhich 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 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 Any of the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficultiesunfavorable circumstances mentioned above could have a material adverse effect on our financial condition, results of operations and cash available for distribution. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for distribution.
Properties we acquireWe may not produceincur losses as projected, and we may be unable to determine reserve potential, identify liabilities associated witha result of title defects in the properties thatin which we acquire or obtain protection from sellers against such liabilities. have an interest.
AcquiringWhen acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence,leases, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be ableelect to obtain contractual indemnities fromincur the seller for liabilities created priorexpense of retaining lawyers to our purchase ofexamine the property. We may be required to assume the risk of the physical condition of the properties in additiontitle to the risk thatmineral interest. Rather, we may rely upon the properties may notjudgment of oil and gas lease brokers or landmen who perform the fieldwork in accordance withexamining 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 an interest worthless and can adversely affect our expectations. results of operations, financial condition and cash available for distribution.
Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. During the year ended December 31, 2017, Diamondback, which is the operator for approximately 36% of the acreage associated with our properties, drilled a total of 100 gross wells and participated in 11 additional gross non-operated wells, of which 57 wells were completed as producing wells and 54 wells were in various stages of completion. If the wells in the process of being completed are on our property and do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for distribution may be materially affected.
Our method of accounting for investments in oil and natural gas properties resulted in impairments of asset value for the years ended December 31, 2016 and 2015 and may result in further impairments in future periods.
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. 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. 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 $10.07, $12.67 and $17.88 for the years ended December 31, 2017, 2016 and 2015, 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.
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
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.costs, if any. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves and related valuations as of December 31, 2017, 2016 and 2015, were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all our properties for the period covered by its reserve report using information provided by us. 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, if any, 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 estimatesWe are dependent on electrical power, internet and telecommunication infrastructure and information and computer systems.If any of reserves asthese systems are compromised or unavailable, our business could be adversely affected.
We are dependent on electric power, internet and telecommunication infrastructure and our information systems and computer based programs. If any of December 31, 2017, 2016 and 2015such infrastructure, systems or programs were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2017, 2016 and 2015, respectively,fail or become unavailable or compromised, or create erroneous information in accordance with the SEC guidelines applicable to reserve estimates for such period. Commodity prices have deteriorated significantly since that time and, accordingly, using more recent prices in estimating our proved reserves, without giving effect to any acquisition activities we have executed during 2017, would result in a reduction in proved reserve volumes due to economic limits.
SEC rules could limithardware or software network infrastructure, our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may onlysafely and effectively conduct our business will be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit
our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe because they have become uneconomic or otherwise.
Concerns over general economic, business or industry conditions mayany such consequence could have a material adverse effect on our results of operations, financial conditionbusiness.
We are subject to cybersecurity risks. A cyber incident could occur and cash available for distribution.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the European, Asian and the U.S. markets contribute to economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, volatility in consumer confidence and job markets, may result in an economic slowdown information theft, data corruption, operational disruption and/or recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United Statesfinancial loss.
We rely extensively on information technology systems, including internally developed software, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other countries. Concerns about global economic growth have had a significant adverse impact on global financial marketsinternally or externally hosted hardware and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids fromsoftware platforms, to (i) estimate our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.
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 advancesreserves, (ii) process and record financial and operating data and (iii) communicate with our employees and vendors, suppliers and other third parties. Further, our reliance on technology has increased due to the increased use of personal devices, remote communications and work-from-home or hybrid work practices that evolved in fuel economyresponse to the COVID-19 pandemic. Our systems and energy generation devicesnetworks, and those of our vendors, service providers and other third party providers, may become the target of cybersecurity attacks, including, without limitation, denial-of-service attacks; malicious software; data privacy breaches by insiders or others with authorized access; cyber or phishing-attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. If any of these security breaches were to occur, we could reduce demandsuffer disruptions to our operations, normal business functions and other aspects of our business.
We have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threat. Such measures, however, cannot entirely eliminate cybersecurity threats and the controls, procedures and protections we have implemented and invested in may prove to be ineffective. 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 oil and natural gas. The impactpossible 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 business, financial condition results of operations and cash availableflows.
Risks Related to Our Indebtedness
Implementing our capital programs may, under certain circumstances, require an increase in our total leverage through additional debt issuances. In addition, a significant reduction in availability under the revolving credit facility and the inability to otherwise obtain financing for distribution.our capital programs could require us to curtail our capital expenditures.
We rely on a few key individuals whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of individuals. 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 the Chief Executive Officer of our general partner, Travis D. Stice, could disrupt our business. Diamondback has employment agreements with Travis D. Stice and Teresa L. Dick, the Chief Financial Officer of our general partner, and certain other employees of our general partner which contain restrictions on competition with the business or operations of Diamondback and its subsidiaries until the later of the termination of their employment with or other affiliation with such entities and for a period of six months thereafter. However, as a practical matter, such employment agreements may not assure the retention of Diamondback’s employees. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result of our cash distribution policy, we are not insured against any losses resultinghave limited cash available to reinvest in our business or to fund acquisitions and have historically relied on availability under the Operating Company’s revolving credit facility to fund a portion of our capital expenditures and for other purposes. We expect that we will continue to fund a portion of our capital expenditures and other needs with borrowings under the revolving credit facility and from the deathproceeds of these key individuals.debt and equity offerings. In the past, we have created availability under the revolving credit facility by repaying outstanding borrowings with the proceeds from equity and debt offerings. We cannot assure you that we will choose to or be able to access the capital markets to repay any such future borrowings. 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 result in an inability to complete acquisitions or finance the capital expenditures necessary to replace our reserves.
CompetitionRestrictive covenants in the oilOperating Company’s revolving credit facility, the indenture governing the Notes and naturalfuture debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.
The Operating Company’s revolving credit facility and the indenture governing the Notes outstanding contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our and the Operating Company’s ability to, among other things: incur or guarantee additional indebtedness; make certain investments; create additional liens; sell or transfer assets; lease property as a lessee; issue redeemable or preferred equity; voluntarily redeem or prepay debt (including the Notes); merge or consolidate with another entity; pay dividends or make distributions; designate certain of our subsidiaries as unrestricted subsidiaries; create unrestricted subsidiaries; engage in transactions with affiliates; enter into gas industry is intense, whichimbalance, take-or-pay and similar agreements; and enter into certain swap agreements.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us and the Operating Company by the restrictive covenants contained in the revolving credit facility and the indenture that governs the Notes. In addition, the revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to succeed.
The oil and natural gas industry is intensely competitive, andreact to changes in market conditions, take advantage of business opportunities we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products onbelieve to be desirable, obtain future financing, fund needed capital expenditures or withstand a regional, nationalcontinuing or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companiesdownturn in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.business.
Our credit agreement has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.
The operating and financial restrictions and covenants in our credit agreement and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Ourthe Operating Company’s future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions
deteriorate, our ability to comply with these covenants may be impaired. A breach of any of these restrictive covenants could result in default under the revolving credit facility. If we violate any provisions of oura default occurs, the lenders under the revolving credit agreement that are not cured or waived within the appropriate time periods provided in our credit agreement, a significant portion of our indebtednessfacility may becomeelect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, our abilitywhich would result in an event of default under the indenture governing the Notes. The lenders will also have the right in these circumstances to make distributionsterminate any commitments they have to our unitholders will be inhibitedprovide further borrowings. If we and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement are secured by substantially all of our assets, and if wethe Operating Company are unable to repay ouroutstanding borrowings when due, the lenders under the revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under the revolving credit facility and the Notes were to be accelerated, we cannot assure you that our credit agreement, the lenders could seekassets would be sufficient to foreclose on our assets.repay in full that indebtedness.
Our credit agreement allows us to borrowAny significant reduction in an amount up to the borrowing base which is based on our oil and natural gas reserves and other factorsunder the Operating Company’s revolving credit facility as determined semi-annually by our lenders in their sole discretion. Asa result of December 31, 2017, the periodic borrowing base was set at $400.0 million,redeterminations or otherwise may negatively impact our ability to fund our operations, and we had $93.5 million of outstanding borrowings and $306.5 million available for futuremay not have sufficient funds to repay borrowings under ourthe revolving credit facility. facility if required as a result of a borrowing base redetermination.
A decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding in excess of the borrowing base. If we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.
Loss of our information and computer systems could adversely affect our business.
We are dependent on our information systems and computer based programs. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
Risks Related to Operators and Other Working Interest Owners
The following describes risks that may directly affect our business and operations to the extent we electsignificant reduction in the future to engage in the exploration, development and production of oil and natural gas properties. In addition, any operators of our properties, including our current operators, are subject to the risks and uncertainties described below, and, as the owner of mineral interests, we are indirectly exposed to the same risks and uncertainties. For purposes of this section, where applicable, references to “we,” “us” and “our” refer to Viper Energy Partners LP to the extent the partnership were to acquire working interests in the future, as well as to any operators of our properties, including the current operators.
If a significant portion of any future net leasehold acreage is undeveloped, and that acreage is not ultimately developed or does not become commercially productive, we could lose rights under these leases, and any such events could have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our financial condition, results of operations and cash available for distribution.
To the extent we acquire working interests in the future, 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, we could lose our rights under those leases if we do not timely develop such acreage. In addition, if we are required under any such oil and natural gas leases to drill wells that are commercially productive and 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 financial condition, results of operations and cash available for distribution may be highly dependent on successfully developing our undeveloped leasehold acreage.
Development and exploration operations 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. To the extent we acquire working interests in the future, we will not be able to assure our unitholders 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 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 reserveborrowing 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 our unitholders that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we acquire working interests in the future and we are unable to fund our capital requirements, we may be required to curtail 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, results of operations and cash available for distribution. 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.
We may incur losses as a result of title defects in the properties in which we invest.
If we acquire working interests in the future, when acquiring oil and natural gas leases, we may not elect to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we may 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, financial condition and cash available for distribution.
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 defectsborrowing base redeterminations or otherwise may delay or prevent us from utilizing the associated mineral interest, which may adverselynegatively impact our ability in the future to increase productionliquidity 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, our business, results of operations and cash available for distribution may be adversely affected.
Identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
To the extent we acquire working interests in the future, our ability to drill and develop identified potential drilling locations will depend on a number of uncertainties, including the availability of capital, construction of infrastructure, regulatory changes and approvals, costs, drilling results, the availability of water and weather conditions. Further, identified potential drilling locations are typically in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We will not be able to 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 or whether wells drilled on different spacing assumptions will produce at materially different rates. 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 wells that we identify as dry holes in current and future drilling locations,fund our drilling success rate may decline and materially harm our business.
We will not be able to assure our unitholders that the analogies drawn from available data from wells drilled, 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 identify 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 identified, which could adversely affect our business.
For information on Diamondback’s identified potential drilling locations, see “Items 1 and 2. Business and Properties.”
Acreage must be drilled before lease expiration, generally within three to five years, to hold the acreage by production. The 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. To the extent we acquire working interests in the future, the cost to renew our 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 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. Any such losses of leases could materially and adversely affect the growth of our financial condition, results of operations and, cash available for distribution.
The inability of one or more of our customers to meet their obligations may adversely affect our financial condition, results of operations and cash available for distribution.
To the extent we acquire working interests in the future, we may have exposure to credit risk through receivables from joint interest owners on properties we operate and receivables from purchasers of our oil and natural gas production.
Joint interest receivables will arise from billing entities that own partial interests in any wells we operate. These entities will typically participate in our wells primarily based on their ownership in leases on which we wish to drill. We will generally be unable to control which co-owners participate in our wells.
We also may be subject to credit risk due to the concentration of oil and natural gas receivables with several significant customers. 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. Generally, customers are not required 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 condition, results of operations and cash available for distribution.
To the extent we depend upon certain 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 and adversely affect our results of operations and cash available for distribution.
To the extent we acquire working interests in the future, the availability of a ready market for any oil and natural gas we produce will depend 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, to the extent we depend upon certain significant purchasers for the sale of most of our oil and natural gas production, the loss of one or more of such purchasers, or their failure or inability to meet their obligations to us, could adversely affect our results of operations and cash available for distribution. We cannot assure our unitholders that we will have ready access to suitable markets for our oil and natural gas production if we acquire working interests in the future.
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. To the extent we acquire working interests in the future, in accordance with customary industry practice, we will 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 may not have long-term contracts securing the use of our 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 adversely affect our financial condition, results of operations and cash available for distribution.
Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash available for distribution.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Over the past several years, parts of Texas have 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. To the extent we acquire working interests in the future, 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 available for distribution.
The results of our exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
To the extent we acquire working interests in the future, our operations will involve utilizing the latest drilling and completion techniques. Risks that we will 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 will face while completing 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 identified vertical drilling locations. Furthermore, certain of the new techniques we may adopt, 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 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 will be 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.
The marketability of oil and natural gas 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 results of operations and cash available for distribution could be adversely affected.
To the extent we acquire working interests in the future, the marketability of our oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. We may not control these 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, our operators have experienced high line pressure at their tank batteries with occasional flaring due to the inability of the gas gathering systems to support the increased production of natural gas in the Permian Basin. If 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, could adversely affect our financial condition, results of operations and cash available for distribution.
Our operations will be subject to various governmental laws and regulations which require compliance that can be burdensome and expensive and could expose us to significant liabilities, which could adversely affect our cash available for distribution.
To the extent we acquire working interests in the future, our oil and natural gas operations will be 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 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. Moreover, these laws and regulations impose strict requirements for water and air pollution control and solid waste management.
Laws and regulations governing exploration and production may also affect production levels. To the extent we acquire working interests in the future, we will be required to comply with federal and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging and abandonment of wells; and the removal of related production equipment. Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increase capital costs on the part of operators and third party downstream natural gas transporters.
If we acquire working interests in the future, we will also be required to comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.
Significant expenditures may be required to comply with the governmental laws and regulations described above. 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 “Items 1 and 2. Business and Properties—Regulation” for a description of the laws and regulations that affect our operators and that, to the extent we acquire working interests in the future, will affect us. These and other potential regulations could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, any of which could have a material adverse effect on the amount of cash available for distribution to our unitholders.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.
In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures. Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic
fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For a more detailed discussion of state and local laws and initiatives concerning hydraulic fracturing, see “Items 1 and 2. Business and Properties–Regulation–Regulation of Hydraulic Fracturing.”
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.
To the extent we acquire working interests in the future, we may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. Moreover, public interest in the protection of the environment has tended to increase over time. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected.
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.
To the extent we acquire working interests in the future, our operations may 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 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.
If we acquire working interests in the future, the regulation of greenhouse gas emissions could result in increased operating costs and reduced demand for the oil and natural gas we produce.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. While we are subject to certain federal greenhouse gas monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed greenhouse gas rules and regulations, see “Items 1 and 2. Business and Properties–Regulation–Environmental Regulation-Climate Change.”
At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may adversely affect our business, financial condition, results of operations and cash available for distribution.
If we acquire working interests in the future, our drilling activities will be subject to many risks. For example, we will not be able to assure our unitholders that 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 used do not provide conclusive knowledge 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. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our unitholders may be adversely affected.
Operating hazards and uninsured risks may result in substantial losses and could adversely affect our results of operations and cash available for distribution.
To the extent we acquire working interests in the future, our operations will be 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 will be 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 would 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 agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors would 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 would 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 may 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, results of operation and cash available for distribution.
In accordance with what we believe to be customary industry practice, we would expect to maintain 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 available for distribution. 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.
We may not have coverage if we are unaware of a sudden and accidental pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We do not have, and do not intend to have, coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure our unitholders 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 operationsoperation and cash available for distribution.flow. Further, if the outstanding borrowings under the revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we and the Operating Company would be required to repay the excess.
We may not have sufficient funds to make such repayments. If we acquire working interests indo not have sufficient funds and we are otherwise unable to negotiate renewals of the future,borrowings or arrange new financing, we may operate in areas of high industry activity, which may make it difficulthave to hire, train or retain qualified personnel needed to manage and operate oursell significant assets.
If we acquire working interests in the future, our operations and drilling activity will likely be concentrated in the Permian Basin, 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 to continue or complete development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs,sale could have a material adverse effect on our business and financial condition, resultsresults.
Servicing our indebtedness requires a significant amount of operationscash, and we may not have sufficient cash available for distribution.flow from our business to pay our substantial indebtedness.
Our useability to make scheduled payments of 2-D and 3-D seismic datathe principal of, to pay interest on or to refinance our indebtedness depends on our future performance, which is subject to interpretationeconomic, financial, competitive and other factors beyond our control. We are dependent on cash flow generated by the Operating Company to repay the Notes. The Operating Company’s business may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
To the extent we acquire working interestsgenerate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If the Operating Company is unable to generate such cash flow, we will relymay be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional capital on 2-Dterms 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 3-D seismic data. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools usedmight be required to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpretersell material assets to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismicattempt to meet our debt service and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies,obligations. The Operating Company’s revolving credit facility and we could incur losses as a result of such expenditures. As a result,the indenture governing the Notes outstanding restrict our drilling activities may not be successful or economical.
ability to use the proceeds from asset sales. We may not be able to keep pace with technological developments inconsummate 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 industry.
The oilindebtedness will depend on the capital markets and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. Toour financial condition at the extent we acquire working interests in the future, 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.time. We may not be able to respondengage 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.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, these competitive pressuresand negatively impact the terms of, current or implement new technologiesfuture 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 timely basisrating will not be lowered or at an acceptable cost. If onewithdrawn 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 moresales 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 or the Operating Company’s borrowing costs.
The borrowings under the Operating Company’s revolving credit facility expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under the Operating Company’s revolving credit facility. The terms of the technologies we use now orOperating Company’s revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate that, since November 2022 has been tied to SOFR. SOFR tends to fluctuate based on multiple facts, including general short-term interest rates, rates set by the U.S. Federal Reserve, which may increase further in 2023, and other central banks and general economic conditions. We have not hedged our interest rate exposure with respect to our floating rate debt. The Operating Company’s weighted average interest rate on borrowings under its revolving credit facility was 4.22% during the future were to become obsolete,year ended December 31, 2022. If interest rates increase, so will our business, financial condition orinterest costs, which may have a material adverse effect on our results of operations and cash available for distribution could be materially and adversely affected.financial condition.
Increased costs of capital could adversely affect our business.
Our business and operating results 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 operations. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
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, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and, to the extent we acquire working interests in the future, 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 its 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 its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage 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 do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.
Risks Inherent in an Investment in Us
Diamondback owns and controls our general partner,General Partner, which has sole responsibility for conducting our business and managing our operations. Our general partnerGeneral Partner and its affiliates, including Diamondback, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.
Diamondback owns and controls our general partnerGeneral Partner and appoints all of the directors of our general partner.General Partner. All of the executive officers and certain of the directors of our general partnerGeneral Partner are also officers and/or directors of Diamondback. Although our general partnerGeneral Partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partnerGeneral Partner have a fiduciary duty to manage our general partnerGeneral Partner in a manner beneficial to Diamondback. Therefore, conflicts of interest may arise between Diamondback or any of its affiliates, including our general partner,General Partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partnerGeneral Partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:
Our general partnerFor instance, our General Partner is allowed to take into account the interests of parties other than us, such as Diamondback, in exercising
certain rights under our partnership agreement.
Neither our partnership agreement nor any other agreement requires Diamondback to pursue a business strategy that favors us.
Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partnerGeneral Partner with contractual standards governing its duties, limits our general partner’sGeneral Partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.
Except in limited circumstances, our general partnerGeneral Partner has the power and authority to (i) conduct our business without unitholder approval.
Our general partner determinesapproval (ii) determine the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders.
Our general partner determinesunitholders, (iii) determine which costs incurred by it and its affiliates are reimbursable by us, (iv) exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units, (v) control the enforcement of obligations that it and its affiliates owe to us, and (vi) decide whether to retain separate counsel, accountants or others to perform services for us.
Our partnership agreement does not restrict our general partnerGeneral Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf.
Our general partnerGeneral Partner intends to limit its liability regarding our contractual and other obligations.
Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.
Our general partner controls the enforcement of obligations that it and its affiliates owe to us.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
In addition, Diamondback or its affiliates, may compete with us.
The board of directors of our general partner has adopted a policy to distribute an amount equal to the available cash we generate each quarter, which could limit our ability to grow and make acquisitions.
As a result of our cash distribution policy, we have limited cash available to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.
To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders.
Neither we nor our general partnerGeneral Partner have any employees, and we rely solely on the employees of Diamondback to manage our business. The management team of Diamondback, which includes the individuals who manage us, also perform similar services for Diamondback and own and operate Diamondback’s assets,certain of its affiliates, and thus are not solely focused on our business.
Neither we nor our general partnerGeneral Partner have any employees and we rely solely on Diamondback to operate our assets and perform other management, administrative and operating services for us and our general partner.General Partner. Diamondback provides similar activities with respect to its own assets and operations.operations and those of certain of its affiliates. Because Diamondback provides services to us that are similar to those performed for itself Diamondbackand its affiliates, it may not have sufficient human, technical and other resources to provide those services at a level that Diamondbackit would be able to provide to us if it were solely focused on our business and operations. Diamondback may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Diamondback’s interests. There is no requirement that Diamondback favor us over itself or others in providing its services. If the employees of Diamondback and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced. Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of the executive team of our General Partner, including the Chief Executive Officer, President and Chief Financial Officer of our General Partner, Travis D. Stice, Kaes Van’t Hof and Teresa L. Dick, respectively, could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.
Our partnership agreement replaces our general partner’sGeneral Partner’s fiduciary duties to our unitholders.
Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partnerGeneral Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partnerlaw, such as permitting it to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, orGeneral Partner, which are otherwise free of fiduciary duties to us and our unitholders. This entitles our general partnerGeneral Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partnerGeneral Partner may make in its individual capacity include:
include; how to allocate business opportunities among us and its affiliates;
affiliates, whether to exercise its call right;
right, how to exercise its voting rights with respect to the units it owns;
owns, whether to exercise its registration rights;rights and
whether or not to consent to any merger or consolidation of the partnership or any amendment to the partnership agreement.
By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to holders of our units for actions taken by our general partnerGeneral Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partnerGeneral Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
that (i) whenever our general partnerGeneral Partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partnerGeneral Partner, it is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
equity, (ii) our general partnerGeneral Partner and its executive officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been
a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner orGeneral Partner, its executive officers or directors engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and
(iii) our general partnerGeneral Partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction, even a transaction with an affiliate or the resolution of a conflict of interest, is:
is (a) approved by the conflicts committee of the board of directors of our general partner,General Partner, although our general partnerGeneral Partner is not obligated to seek such approval;approval or
(b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partnerGeneral Partner and its affiliates.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors of our General Partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Diamondback and other affiliates of our general partnerGeneral Partner may compete with us.
Our partnership agreement provides that our general partnerGeneral Partner is restricted from engaging in any business activities other than acting as our general partner,General Partner, engaging in activities incidental to its ownership interest in us and providing management, advisory and administrative services to its affiliates or to other persons. However, affiliates of our general partner,General Partner, including Diamondback, are not prohibited from the following; engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Diamondback may competeus; competing with us for investment opportunities and may ownopportunities; owning an interest in entities that compete with us. Further, Diamondback and its affiliates, may acquire, developus, and; acquiring, developing or disposedisposing of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.
Diamondback is an established participant in the oil and natural gas industry and has resources greater than ours, which factors may make it more difficult for us to compete with Diamondback with respect to commercial activities as well as for potential acquisitions. As a result, competition from Diamondback and its affiliates could adversely impact our results of operations and cash available for distribution to our common unitholders.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partnerGeneral Partner or any of its affiliates, including its executive officers and directors, and Diamondback. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partnerGeneral Partner and result in less than favorable treatment of us and our unitholders.
Holders of our common units have limited voting rights and are not entitled to elect our general partnerGeneral Partner or its directors, which could reduce the price at which our common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our general partnerGeneral Partner or its board of directors. The board of directors of our general partner,General Partner, including the independent directors, is chosen entirely by Diamondback, as a result of it owning our general partner,General Partner, and not by our unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Even if holders of our common units are dissatisfied, they cannot initially remove our general partnerGeneral Partner without its consent.
If our unitholders are dissatisfied with the performance of our general partner,General Partner, they have limited ability to remove our general partner.General Partner. Unitholders will be unable to remove our general partnerGeneral Partner without its consent because affiliates of our general partnerGeneral Partner own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units, voting as a single class, is required to remove our general partner. AsGeneral Partner, and as of December 31, 2017,2022, Diamondback owned 64%approximately 56% of ourall outstanding common units.units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partnerGeneral Partner and its affiliates and permitted transferees).
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner,General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner,General Partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.
Cost reimbursements due to our general partnerGeneral Partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. Our partnership agreement does not set aThere is no limit on the amount of expenses for which our general partnerGeneral Partner and its affiliates may be reimbursed. Thereimbursed, and it determines the amount and timing of such reimbursements will be determined by our general partner.reimbursements.
Prior to making any distribution onto its unitholders, including us, the common units, weOperating Company will reimburse our general partnerGeneral Partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set aThere is no limit on the amount of expenses for which our general partnerGeneral Partner and its affiliates may be reimbursed.reimbursed, and the amounts may be substantial. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partnerGeneral Partner by its affiliates. Our partnership agreement provides that our general partnerGeneral Partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partnerGeneral Partner and its affiliates will reduce the amount of cash available for distribution from the Operating Company to us and from us to our common unitholders.
At the time of the IPO, we and our general partner entered into an advisory services agreement with Wexford Capital LP, or Wexford, pursuant to which Wexford agreed to provide general finance and advisory services. Any fee paid would reduce the amount of cash available for distribution to our unitholders. We paid no amounts to Wexford under the advisory services agreement during 2016 and 2017. In addition, we have entered into a tax sharing agreement with Diamondback pursuant to which we are required to reimburse Diamondback for our share of state and local income and other taxes borne by Diamondback as a result of our results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on the closing date of the IPO. No amounts have been paid to Diamondback under the tax sharing agreement.Diamondback.
Our general partnerGeneral Partner interest or the control of our general partnerGeneral Partner may be transferred to a third party without unitholder consent.
Our general partnerGeneral Partner may transfer its general partnerGeneral Partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partnerGeneral Partner to transfer its membership interests in our general partnerGeneral Partner to a third party. After any such transfer, the new member or members of our general partnerGeneral Partner would then be in a position to replace the board of directors and executive officers of our general partnerGeneral Partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner.General Partner. This effectively permits a “change of control” without the vote or consent of the unitholders.
UnitholdersCommon unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.
Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner.General Partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partnerGeneral Partner if a limited partner were to lose limited liability through any fault of our general partner.General Partner.
Our general partnerGeneral Partner has a call right that may require unitholders to sell their common units at an undesirable time or price.
If at any time our general partnerGeneral Partner and its affiliates (including Diamondback) own more than 97%80% of the common units, our general partnerGeneral Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1)(i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call
right is first mailed and (2)(ii) the highest per-unit price paid by our general partnerGeneral Partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. If our general partner and its affiliates (including Diamondback) reduce their ownership to below 75% of the outstanding common units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partnerGeneral Partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partnerGeneral Partner from causing us to issue additional common units and then exercising its call right. If our general partnerGeneral Partner exercised its limited call right,
the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. The common units and Class B units are considered limited partner interests of a single class for these provisions. As of December 31, 2017,2022, Diamondback owned 64%approximately 56% of our common units.total units outstanding.
We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.
Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
effects; the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;
decrease, the amount of cash distributions on each common unit may decrease;
decrease, the ratio of our taxable income to distributions may increase;
increase, the relative voting strength of each previously outstanding common unit may be diminished;diminished, and
the market price of the common units may decline.
There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.
In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.
The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.
As of December 31, 2017, we had 113,882,045 common units outstanding. Sales by holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have provided registration rights to Diamondback. Pursuant to these registration rights, we have registered, under the Securities Act, all of the common units owned by Diamondback for resale.resale (including common units issuable in respect of the Class B units and the OpCo units). Under our partnership agreement, our general partnerGeneral Partner and its affiliates have registration rights relating to the offer and sale of any common units that they hold.
For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements, including those relating to accounting standards and disclosure about our executive compensation and internal control auditing requirements that apply to other public companies.
We are classified as an “emerging growth company” under Section 2(a)(19) of the Securities Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the Public Company Accounting Oversight Board after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosures regarding executive compensation required of larger public companies.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Diamondback is a publicly traded corporation and has developed a system of internal controls for compliance with public reporting requirements. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and
operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.
Nasdaq does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the Nasdaq Global Select Market. Because we are a publicly traded partnership, Nasdaq does not require us to have a majority of independent directors on our general partner’sGeneral Partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of certain corporations that are subject to all of Nasdaq’s corporate governance requirements.
Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.
Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. In addition, if any person brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses,
that the parties may incur in connection with such claim, suit, action or proceeding. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.
Our general partnerGeneral Partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partnerGeneral Partner to redeem the units of certain unitholders.
Our general partnerGeneral Partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partnerGeneral Partner to redeem the units held by any person (i) whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (iii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.
Risks RelatedWe are treated as a corporation for U.S. federal income tax purposes and our cash available for distribution to Recently Enactedour common unitholders may be substantially reduced.
We are a Delaware limited partnership that since May 10, 2018, has elected to be treated as a corporation for U.S. Tax Legislationfederal income tax purposes. As a result, we are subject to tax at the corporate tax rate of 21%. As of December 31, 2022, the Operating Company’s special allocation to Diamondback of priority allocations of the Operating Company’s income and Tax Risksgains over losses and deductions (but before depletion) expired. As such, our taxable income for subsequent years is expected to Common Unitholdersinclude our share of allocations of the Operating Company’s income, gains, losses and deductions, as a result of our equity interests in the Operating Company. Because an entity-level tax is imposed on us due to our status as a corporation for U.S. federal income tax purposes, our distributable cash flow may be substantially reduced by our tax liabilities.
Recently enactedDistributions to common unitholders may be taxable as dividends.
Because we are treated as a corporation for U.S. federal income tax legislationpurposes, if we make distributions to our common unitholders from current or accumulated earnings and profits as wellcomputed for U.S. federal income tax purposes, such distributions will be treated as future distributions on corporate stock for U.S. federal income tax purposes, and generally be taxable to our common unitholders as ordinary dividend income for U.S. federal income tax purposes (to the extent of our current and accumulated earnings and profits). Such dividend distributions paid to non-corporate U.S. unitholders will be subject to U.S. federal income tax at preferential rates, provided that certain holding period and other requirements are satisfied. Any portion of our distributions to common unitholders that exceeds our current and accumulated earnings and profits as computed for U.S. federal income tax purposes will constitute a non-taxable return of capital distribution to the extent of a unitholder’s basis in its common units, and thereafter as gain on the sale or exchange of such common units. Subsequent to the expiration of the Operating Company’s special allocation to Diamondback of priority allocations of the Operating Company’s income and gains over losses and deductions (but before depletion) as of December 31, 2022, a greater proportion of our distributions may be made from current or accumulated earnings and profits and thus generally would be taxable to our common unitholders as dividends.
U.S. tax legislations may adversely affect ourbusiness, results of operations, financial condition and cash flow.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to U.S. federal income tax laws. Among other changes, the Tax Act (i) introduces a new deduction on certain pass-through income, (ii) repeals the partnership technical termination rule and (iii) imposes a new limitation on the deductibility of interest expense. The Tax Act is complex and far-reaching and we have not completed our analysis of the impact its enactment has on us. There may be other material adverse effects resulting
from the Tax Act that we have not identified and that could have an adverse effect on our business, results of operations, financial condition and cash flow.
OurFrom time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax treatment dependslaws 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 status asactivities 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.
On August 16, 2022, President Biden signed into law the IRA, which, among other changes, imposes a partnership for federal15% corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income tax purposes,on their consolidated financial statements) as well as our not being subject to a material amountan excise tax of entity-level taxation by individual states.1% on the fair market value of certain public company stock/unit repurchases for tax years beginning after December 31, 2022. If the IRS were to treat us as a corporation for federal income tax purposeswe are or we were to become subject to entity-level taxation for state tax purposes, thenthe CAMT, our cash available for distribution to our unitholders could be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporationobligations for U.S. federal income taxes could be
significantly accelerated. To the extent the 1% excise tax purposes unlessapplies to our repurchases of units under our common unit repurchase program, the number of units we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested,repurchase and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. We would also be subject to certain state taxes. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to unitholders. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Additionally on January 24, 2017, theaffected.
The U.S. Treasury Department, the Internal Revenue Service and other standard-setting bodies are expected to issue guidance on how the IRS published final regulations regarding qualifying income under Section 7704(d)(1)(E)CAMT, stock/unit buyback excise tax and other provisions of the Code effective as of January 19, 2017, that provide industry-specific guidance regarding whether income earned from certain activitiesIRA will be treated as qualifying income. We believe the incomeapplied or otherwise administered that we treat as qualifying income satisfies the requirements for qualifying income under the current law and the final regulations.
Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to satisfy the requirements of the exception pursuant to which we are treated as a partnership for income tax purposes. While the Tax Act does not negatively impact the final regulations or the qualifying income exception, there is no guarantee that such proposal will not become part of any future legislation. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and our cash available for distribution to our unitholders might substantially be reduced.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our interpretations. We continue to evaluate the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materiallyIRA and adversely impact the market forits effect on our common unitsfinancial results and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction inoperating cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.flow.
Legislation applicable to partnership tax years beginning after 2017 alters the procedures for auditing large partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level federal income tax
audit. If the IRS makes audit adjustments to our partnership tax returns, to the extent possible under the new rules, our general partner may cause the partnership to pay the taxes (including any applicable penalties and interest) directly to the IRS in the year in which the audit is completed or, if we are eligible, elect to cause our unitholders and former unitholders to take such audit adjustments into account. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. If we make payments of taxes and any penalties and interest directly to the IRS in the year in which the audit is completed, our cash available for distribution to our unitholders might be substantially reduced, in which case our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit.
Even if our unitholders do not receive any cash distributions from us, our unitholders will be required to pay taxes on their share of our taxable income.
Our unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not our unitholders receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability with respect to that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing a gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if they sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), raises issues unique to them. For example, a portion of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person may be required to file United States federal tax returns and pay tax on their share of our taxable income if it is treated as effectively connected income. Prospective unitholders who are a tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our common units.
Pursuant to the Tax Act, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from distributions to the transferee amounts that should have been withheld by the transferee but were not withheld. However, the Department of the Treasury and the IRS have determined that this withholding requirement should not apply to any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.
We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of our common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.
We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The Department of the Treasury and the IRS adopted final Treasury regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Our unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to federal income taxes, our unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if such unitholders do not live in any of those jurisdictions. We may be treated as doing business directly or indirectly in a number of jurisdictions and many of these jurisdictions impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. Our unitholders may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. It is a unitholder’s responsibility to file all U.S. federal, foreign, state and local tax returns.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Note 12—Commitments and Contingencies of the 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 UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market InformationListing and Cash Distributions to UnitholdersHolders of Record
Our common units are listed on the Nasdaq Global Select Market under the symbol “VNOM.” Our common units began trading on June 18, 2014 at an initial public offering price of $26.00 per common unit. The following table shows the low and high sales price per common unit, as reported by the Nasdaq Global Select Market, for the periods indicated:
|
| | | | | | | | | | | |
| Period: | High | | Low | | Cash Distributions per Common Unit(1) |
| 2017 | | | | | |
| 1st Quarter | $ | 19.38 |
| | $ | 15.37 |
| | $ | 0.302 |
|
| 2nd Quarter | $ | 18.63 |
| | $ | 15.19 |
| | $ | 0.332 |
|
| 3rd Quarter | $ | 18.98 |
| | $ | 14.76 |
| | $ | 0.337 |
|
4th Quarter(2) | $ | 24.00 |
| | $ | 18.02 |
| | $ | 0.460 |
|
| 2016 | | | | | |
| 1st Quarter | $ | 17.50 |
| | $ | 12.69 |
| | $ | 0.149 |
|
| 2nd Quarter | $ | 20.25 |
| | $ | 16.07 |
| | $ | 0.189 |
|
| 3rd Quarter | $ | 19.60 |
| | $ | 15.10 |
| | $ | 0.207 |
|
| 4th Quarter | $ | 17.41 |
| | $ | 13.53 |
| | $ | 0.258 |
|
| |
(1) | Distributions are shown for the quarter in which they were generated. |
| |
(2) | The Q4 2017 distribution is payable on February 26, 2018 to unitholders of record at the close of business on February 19, 2018. |
There were five10 holders of record of our common units on January 31, 2018.February 17, 2023.
Cash Distribution Policy
The board of directors of our general partnerGeneral Partner has adoptedestablished a distribution policy for us to distributewhereby the Operating Company distributes all or a portion of its available cash generated on a quarterly basis.
Cash distributions are madebasis to its unitholders (including Diamondback and the Partnership). We in turn distribute all or a portion of the available cash we receive from the Operating Company to our common unitholdersunitholders. Our available cash and the available cash of record on the applicable record date, generally within 60 days after the end of each quarter. Available cashOperating Company for each quarter is determined by the board of directors of our general partnerGeneral Partner following the end of such quarter. AvailableThe cash available for each quarterdistribution by the Operating Company, a non-GAAP measure, generally equals our consolidated Adjusted EBITDA reduced for the applicable quarter, less cash needed for income taxes payable, debt service, and other contractual obligations, and fixed charges and reserves for future operating or capital needs that the board of directors of our general partnerGeneral Partner deems necessary or appropriate, lease bonus income, distribution of equivalent rights payments and preferred distributions, if any.
Our cash available for distribution each quarter generally equals the proportional share of the cash distributed by the Operating Company for the quarter, less cash needed by us for the payment of income taxes, if any, and the preferred distribution. Further, in July 2022, the board of directors of the General Partner Interestapproved a distribution policy, effective beginning with our distribution payable for the third quarter of 2022, consisting of a base and variable distribution, that takes into account capital returned to unitholders via our common unit repurchase program. The board updated the distribution policy in November 2022, providing that lease bonus payments and other similar, one-time, non-recurring payments will be excluded from the calculation of the Partnership’s and the Operating Company’s available cash.
The percentage of cash available for distribution pursuant to the distribution policy discussed above may change quarterly to enable the Operating Company to retain cash flow to help strengthen our balance sheet while also expanding the return of capital program through our common unit repurchase program. We are not required to pay distributions to our common unitholders on a quarterly or other basis.
Repurchases of Equity Securities
Our general partner owns a non-economic general partner interest and therefore is not entitled to receive cash distributions. However, it may acquirecommon unit repurchase activity for the three months ended December 31, 2022 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Total Number of Units Purchased(1) | | Average Price Paid Per Unit(2) | | Total Number of Units Purchased as Part of Publicly Announced Plan | | Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan(3) |
| | (In thousands, except unit amounts) |
| October 1, 2022 - October 31, 2022 | | 21,800 | | $ | 30.01 | | | 21,800 | | $ | 560,389 | |
| November 1, 2022 - November 30, 2022 | | 597,500 | | $ | 33.06 | | | 597,500 | | $ | 540,638 | |
| December 1, 2022 - December 31, 2022 | | 357,996 | | $ | 31.44 | | | 357,996 | | $ | 529,381 | |
| Total | | 977,296 | | $ | 32.40 | | | 977,296 | | |
(1)Includes common units repurchased from employees in order to satisfy tax withholding requirements, if any. Such units are cancelled and retired immediately upon repurchase.
(2)The average price paid per common unit includes any commissions paid to repurchase a common unit.
(3)On July 26, 2022, the board of directors of our General Partner increased the authorization under our then-in-effect common unit repurchase program from $250.0 million to $750.0 million. This repurchase program remains subject to market conditions, applicable legal requirements, contractual obligations and other equity interests infactors and may be suspended from time to time, modified, extended or discontinued by the future and will be entitled to receive pro rata distributions in respectboard of those equity interests.directors of our General Partner at any time.
Recent Sales of Unregistered Securities
On May 9, 2017, we issued 174,513 common units to Roger Letz as consideration for our acquisition of certain mineral, royalty and other interests and certain other assets from Mr. Letz. These units were 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.
Repurchases of Equity Securities
None.
ITEM 6. SELECTED FINANCIAL DATA[RESERVED]
This section presents our selected historical consolidated financial data. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. The following selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report.
Viper Energy Partners LP was formed in February 2014 and did not own any assets prior to June 17, 2014, the date Viper Energy Partners, LLC, the then-subsidiary of Diamondback, was contributed to Viper Energy Partners LP. We refer to Viper Energy Partners, LLC as “Viper Energy Partners LP Predecessor.” Viper Energy Partners LP Predecessor acquired its assets on September 19, 2013.
The contribution of Viper Energy Partners LP Predecessor to Viper Energy Partners LP was accounted for as a combination of entities under common control. Therefore, the following table presents the historical financial data of Viper Energy Partners LP as if Viper Energy Partners LP Predecessor and Viper Energy Partners LP were combined since inception.
Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years ended December 31, 2017, 2016 and 2015 and the balance sheet data as of December��31, 2017 and 2016 are derived from our audited consolidated financial statements included elsewhere in this Annual Report.
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Period From Inception
Through
December 31, 2013 |
| | 2017 | | 2016 | | 2015 | | 2014 | |
| | (in thousands) |
| Statement of Operations Data: | | | | | | | | | |
| Royalty income | $ | 160,163 |
| | $ | 78,837 |
| | $ | 74,859 |
| | $ | 77,767 |
| | $ | 14,987 |
|
| Lease bonus | 11,870 |
| | 309 |
| | — |
| | — |
| | — |
|
| Total operating income | 172,033 |
| | 79,146 |
| | 74,859 |
| | 77,767 |
| | 14,987 |
|
| Costs and expenses: | | | | | | | | | |
| Production and ad valorem taxes | 10,608 |
| | 5,544 |
| | 5,531 |
| | 5,377 |
| | 972 |
|
| Gathering and transportation | 789 |
| | 415 |
| | 259 |
| | — |
| | — |
|
| Depletion | 40,519 |
| | 29,820 |
| | 35,436 |
| | 27,601 |
| | 5,199 |
|
| Impairment | — |
| | 47,469 |
| | 3,423 |
| | — |
| | — |
|
| General and administrative expenses | 6,296 |
| | 5,209 |
| | 5,835 |
| | 4,372 |
| | 87 |
|
| Total costs and expenses | 58,212 |
| | 88,457 |
| | 50,484 |
| | 37,350 |
| | 6,258 |
|
| Income (loss) from operations | 113,821 |
| | (9,311 | ) | | 24,375 |
| | 40,417 |
| | 8,729 |
|
| Other income (expense): | | | | | | | | | |
| Interest expense, net | (3,164 | ) | | (2,455 | ) | | (1,110 | ) | | (487 | ) | | — |
|
| Interest expense—related party, net of capitalized interest | — |
| | — |
| | — |
| | (10,755 | ) | | (5,741 | ) |
| Other income, net | 821 |
| | 867 |
| | 1,154 |
| | 459 |
| | — |
|
| Total other income (expense), net | (2,343 | ) | | (1,588 | ) | | 44 |
| | (10,783 | ) | | (5,741 | ) |
| Net income (loss) | $ | 111,478 |
| | $ | (10,899 | ) | | $ | 24,419 |
| | $ | 29,634 |
| | $ | 2,988 |
|
| | | | | | | | | | |
| Allocation of net income: | | | | | | | | | |
| Net income attributable to the period January 1, 2014 through June 22, 2014 | | | | | | | $ | 7,021 |
| | |
| Net income attributable to the period June 23, 2014 through December 31, 2014 | | | | | | | 22,613 |
| | |
| Total net income | | | | | | | $ | 29,634 |
| | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Period From Inception
Through
December 31, 2013 |
| | 2017 | | 2016 | | 2015 | | 2014 | |
| | (in thousands) |
| Net income (loss) attributable to common limited partners per unit: | | | | | | | | | |
| Basic | $ | 1.07 |
| | $ | (0.13 | ) | | $ | 0.31 |
| | 0.29 |
| | |
| Diluted | $ | 1.07 |
| | $ | (0.13 | ) | | $ | 0.31 |
| | 0.29 |
| | |
| | | | | | | | | | |
| Statement of Cash Flow Data: | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | |
| Operating activities | $ | 139,219 |
| | $ | 68,627 |
| | $ | 63,832 |
| | $ | 51,813 |
| | $ | 4,845 |
|
| Investing activities | (344,079 | ) | | (205,721 | ) | | (43,907 | ) | | (96,815 | ) | | (4,083 | ) |
| Financing activities | 219,844 |
| | 145,768 |
| | (34,496 | ) | | 59,350 |
| | — |
|
| | | | | | | | | | |
| Other Financial Data: | | | | | | | | | |
Adjusted EBITDA(1) | $ | 157,556 |
| | $ | 72,660 |
| | $ | 68,317 |
| | $ | 70,579 |
| | $ | 13,928 |
|
| | | | | | | | | | |
| Balance Sheet Data (at period end): | | | | | | | | | |
| Cash and cash equivalents | $ | 24,197 |
| | $ | 9,213 |
| | $ | 539 |
| | 15,110 |
| | |
| Total assets | 1,013,037 |
| | 670,549 |
| | 529,731 |
| | 537,402 |
| | |
| Total liabilities | 99,129 |
| | 122,651 |
| | 34,587 |
| | 2,051 |
| | |
| Unitholders’ equity/Members’ equity | 913,908 |
| | 547,898 |
| | 495,144 |
| | 535,351 |
| | |
| |
(1) | For more information, please read “—Non-GAAP Financial Measure” below. |
Non-GAAP Financial Measure
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure.
We define Adjusted EBITDA as net income (loss) plus net interest expense, interest expense–related party (net of capitalized interest), non-cash unit-based compensation expense, depletion expense and impairment expense. Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA.
Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods indicated.
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Period From Inception Through December 31, 2013 |
| | 2017 | | 2016 | | 2015 | | 2014 | |
| | (in thousands) |
| Net income (loss) | $ | 111,478 |
| | $ | (10,899 | ) | | $ | 24,419 |
| | $ | 29,634 |
| | $ | 2,988 |
|
| Interest expense, net | 3,164 |
| | 2,455 |
| | 1,110 |
| | 487 |
| | — |
|
| Interest expense–related party, net of capitalized interest | — |
| | — |
| | — |
| | 10,755 |
| | 5,741 |
|
| Non-cash unit-based compensation expense | 2,395 |
| | 3,815 |
| | 3,929 |
| | 2,102 |
| | — |
|
| Depletion | 40,519 |
| | 29,820 |
| | 35,436 |
| | 27,601 |
| | 5,199 |
|
| Impairment | — |
| | 47,469 |
| | 3,423 |
| | — |
| | — |
|
| Adjusted EBITDA | $ | 157,556 |
| | $ | 72,660 |
| | $ | 68,317 |
| | $ | 70,579 |
| | $ | 13,928 |
|
| |
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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 presented 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“Item 1A. Risk Factors”Factors” and “Cautionary“Cautionary Statement Regarding Forward-Looking Statements.Statements.”
Overview
We are a publicly traded Delaware limited partnership formed by Diamondback on February 27, 2014 to among other things, own and acquire mineral and exploitroyalty interests in oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas propertiesprimarily in the Permian Basin. As of December 31, 2017, our general partner held a 100% non-economic general partner interest in us, and Diamondback had an approximate 64% limited partner interest in us.
We operate in one reportable segment engagedsegment.
2022 Transactions and Recent Developments
Commodity Prices and Certain Other Market Considerations
Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in the acquisitionfuture, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. During 2022, 2021 and 2020, NYMEX WTI has ranged from $(37.63) to $123.70 per Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $1.48 to $9.68 per MMBtu, with seven-year highs reached in 2022 and historic lows for oil reached in 2020. The war in Ukraine, the COVID-19 pandemic, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and recent measures to combat persistent inflation have continued to contribute to economic and pricing volatility during 2022. Additionally, OPEC and its non-OPEC allies, known collectively as OPEC+, continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels. However, pricing may remain volatile during 2023.
Due to improved commodity prices and industry conditions and based on the results of the quarterly ceiling tests, we were not required to record an impairment on our proved oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties principally located ininterests during the Permian Basin of West Texas.
2017 Transactions and Recent Developments
Our Equity Offerings
In January 2017, we completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. We received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which $120.5 million was used to repay the outstanding borrowings under our revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.
In July 2017, we completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Diamondback purchased 700,000 common units, an affiliate of our general partner purchased 3,000,000 common units and certain officers and directors of Diamondback and our general partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, Diamondback had an approximate 64% limited partner interest in us. We received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which we used $152.8 million to repay all of the then-outstanding borrowings under our revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes, which included additional acquisitions.
Recent Acquisitions
During 2017, we acquired mineral interests underlying 3,157 net royalty acres for an aggregate purchase price of approximately $343.1 million and, as ofyear ended December 31, 2017, had mineral interests underlying 9,570 net royalty acres. We funded these acquisitions primarily with borrowings under2022. 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 revolving credit facility, with a portion ofproduction, proved reserves and cash flows may be adversely impacted. Our business may also be adversely impacted by any pipeline capacity and storage constraints.
Acquisitions and Divestitures Update
Acquisitions
During the net proceeds from our January and July 2017 offerings of common units and with the issuance of 174,513 common units to a selleryear ended December 31, 2022, in a private placement in May 2017.
Since the end of the fourth quarter of 2017,individually insignificant transactions, we acquired from unrelated third partythird-party sellers, additional mineral and royalty interests underlying 137,443 gross acres, 1,617 net acres and 900representing 375 net royalty acres in the Permian Basin and Eagle Ford Shale for an aggregate net purchase price of approximately $149.4$65.9 million, subject to post-closingincluding certain customary closing adjustments. These transactions included 681 net royalty acres in DeWitt, Karnes and Gonzales Counties that we acquired for approximately $123.4 million, subject to post-closing adjustment. These assets are in the core of the Eagle Ford Shale of South Texas, with internally estimated 2018 net production of 900 BOE/d (approximately 77% liquids). As of February 2, 2018, there were four rigs running on this Eagle Ford acreage, with 225 active horizontal well permits. As a result ofWe funded these transactions, as of February 2, 2018, our assets included mineral interests underlying 385,046 gross acres, 45,460 net acres and 10,470 net royalty acres primarily in the Permian Basin and Eagle Ford Shale. These acquisitions were primarily funded with cash on hand and borrowings under ourthe Operating Company’s revolving credit facility.
Divestitures
In the first quarter of 2022, we divested 325 net royalty acres of third party operated acreage located entirely in Upton and Reagan counties in the Midland Basin for an aggregate net sales price of $29.3 million, including customary closing adjustments.
SourcesIn the third quarter of Our Revenue2022, we divested 93 net royalty acres of third party operated acreage located entirely in Loving county in the Delaware Basin for an aggregate net sales price of $29.9 million, including customary closing adjustments.
Our revenues
In the fourth quarter of 2022, we divested our entire position in the Eagle Ford Shale, consisting of 681 net royalty acres of third party operated acreage for an aggregate sales price of $53.8 million, including certain customary closing adjustments.
As a result of the 2022 acquisitions and divestitures, our footprint of mineral and royalty interests totaled 26,315 net royalty acres at December 31, 2022.
Cash Distribution Update
In July 2022, the board of directors of our General Partner approved a distribution policy, effective beginning with our distribution payable for the third quarter of 2022, consisting of a base and variable distribution, that takes into account capital returned to unitholders via our unit buyback program. The board updated the distribution policy in November 2022, providing that lease bonus payments and other similar, one-time, non-recurring payments will be excluded from the calculation of the Partnership’s and the Operating Company’s available cash.
Repurchases of Notes
During the year ended December 31, 2022, we repurchased an aggregate $49.6 million principal amount of the outstanding Notes for total cash consideration of $49.0 million with a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. See Note 6—Debt of the notes to the consolidated financial statements included elsewhere in this Annual Report for further details.
Production and Operational Update
Third party operated net wells turned to production on our acreage during the third quarter of 2022 were at their highest level since the second quarter of 2019, and third party operated gross wells turned to production during the quarter were the highest in the Partnership’s history. There are primarily derived fromcurrently 44 rigs operating on our mineral and royalty payments we receive from our operators based on the saleacreage, 13 of which are operated by Diamondback. Although demand for oil and natural gas and commodity prices continued to increase in 2022, Diamondback and certain of our other operators kept production on our acreage relatively flat, using their excess cash flow for debt repayment and/or return to their stockholders rather than expanding their drilling programs. We expect our production and free cash flow outlooks to be driven by Diamondback’s continued focus on developing our acreage, as well as our exposure to other well-capitalized operators in the sale of natural gas liquids that are extracted from natural gas during processing. Royalty income may vary significantly from period to period asPermian Basin. As a result of changes in commodity prices, production mix and volumes of production sold byDiamondback’s consistent focus on developing our operators.
The following table presents the breakdown of our operating income for the following periods:
|
| | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Operating income | | | | | |
| Royalty income | | | | | |
| Oil sales | 81 | % | | 90 | % | | 93 | % |
| Natural gas sales | 5 | % | | 4 | % | | 4 | % |
| Natural gas liquid sales | 6 | % | | 6 | % | | 3 | % |
| Lease bonus income | 8 | % | | — | % | | — | % |
| | 100 | % | | 100 | % | | 100 | % |
As a result, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas liquids or natural gas prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2017, West Texas Intermediate posted prices ranged from $42.48 to $60.46 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On December 29, 2017, the West Texas Intermediate posted price for crude oil was $60.46 per Bbl and the Henry Hub spot market price of natural gas was $3.69 per MMBtu. Lower prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that our operators can produce economically. Lower oil and natural gas prices may also result in a reductionhigh concentration royalty acreage, primarily in the borrowing base underNorthern Midland Basin, we expect our credit agreement, which may be redetermined at the discretionDiamondback-operated full year 2023 oil production to increase by approximately 8% compared to 2022. We also expect that we will continue to return substantial amounts of our lenders.
Principal Components of Our Cost Structure
Production and Ad Valorem Taxes
Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.
General and Administrative
In connection with the closing of the IPO, our general partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated as of June 23, 2014. The partnership agreement requires us to reimburse our general partner for all direct and indirect expenses incurred or paid on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. The partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocatedcapital to our general partner by its affiliates. Our general partner is entitledunitholders as we can offer organic production growth with nearly no exposure to determine the expenses that are allocable to us.inflationary cost pressures.
Depreciation, Depletion and Amortization
Income Tax Expense
We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income.
We are subject to the Texas margin tax. Diamondback does not expect any Texas margin tax to be due for the years ended December 31, 2017, 2016 and 2015.
Results of Operations
The following table summarizes our revenuegross well information as of the dates indicated:
| | | | | | | | | | | | | | | | | | | |
| Diamondback Operated | | Third Party Operated | | Total | | |
Horizontal wells turned to production (fourth quarter 2022)(1): | | | | | | | |
| Gross wells | 42 | | 230 | | 272 | | |
| Net 100% royalty interest wells | 2.3 | | 2.3 | | 4.6 | | |
| Average percent net royalty interest | 5.4 | % | | 1.0 | % | | 1.7 | % | | |
| | | | | | | |
Horizontal wells turned to production (year ended December 31, 2022)(2): | | | | | | | |
| Gross wells | 193 | | 807 | | 1,000 | | |
| Net 100% royalty interest wells | 11.8 | | 7.0 | | 18.8 | | |
| Average percent net royalty interest | 6.1 | % | | 0.9 | % | | 1.9 | % | | |
| | | | | | | |
| Horizontal producing well count (as of January 18, 2023): | | | | | | | |
| Gross wells | 1,575 | | 3,624 | | 5,199 | | |
| Net 100% royalty interest wells | 114.9 | | 59.5 | | 174.4 | | |
| Average percent net royalty interest | 7.3 | % | | 1.6 | % | | 3.4 | % | | |
| | | | | | | |
Horizontal active development well count (as of January 18, 2023)(3): | | | | | | | |
| Gross wells | 118 | | 359 | | 477 | | |
| Net 100% royalty interest wells | 6.0 | | 4.3 | | 10.3 | | |
| Average percent net royalty interest | 5.1 | % | | 1.2 | % | | 2.2 | % | | |
| | | | | | | |
Line of sight wells (as of January 18, 2023)(4): | | | | | | | |
| Gross wells | 190 | | 311 | | 501 | | |
| Net 100% royalty interest wells | 9.9 | | 3.8 | | 13.7 | | |
| Average percent net royalty interest | 5.2 | % | | 1.2 | % | | 2.7 | % | | |
(1) Average lateral length of 10,630 feet.
(2) Average lateral length of 10,516 feet.
(3) The total 477 gross wells currently in the process of active development are those wells that have been spud and expensesare expected to be turned to production within approximately the next six to eight months.
(4) The total 501 line-of-sight wells are those that are not currently in the process of active development, but for which Viper has reason to believe that they will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third party operators or Diamondback’s current expected completion schedule. Existing permits or active development of our net royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices.
Results of Operations
The following table summarizes our income and production dataexpenses for the periods indicated.indicated:
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | |
| | (In thousands) |
| | | | | |
| Operating income: | | | | | |
| Oil income | $ | 667,281 | | | $ | 397,513 | | | |
| Natural gas income | 83,149 | | | 49,197 | | | |
| Natural gas liquids income | 87,546 | | | 54,824 | | | |
| Royalty income | 837,976 | | | 501,534 | | | |
| Lease bonus income | 27,791 | | | 2,763 | | | |
| | | | | |
| Other operating income | 700 | | | 620 | | | |
| Total operating income | 866,467 | | | 504,917 | | | |
| Costs and expenses: | | | | | |
| Production and ad valorem taxes | 56,372 | | | 32,558 | | | |
| | | | | |
| Depletion | 121,071 | | | 102,987 | | | |
| | | | | |
| General and administrative expenses | 8,542 | | | 7,800 | | | |
| | | | | |
| Total costs and expenses | 185,985 | | | 143,345 | | | |
| Income (loss) from operations | 680,482 | | | 361,572 | | | |
| Other income (expense): | | | | | |
| Interest expense, net | (40,409) | | | (34,044) | | | |
| | | | | |
| Gain (loss) on derivative instruments, net | (18,138) | | | (69,409) | | | |
| | | | | |
| Other income, net | 416 | | | 79 | | | |
| Total other expense, net | (58,131) | | | (103,374) | | | |
| Income (loss) before income taxes | 622,351 | | | 258,198 | | | |
| Provision for (benefit from) income taxes | (32,653) | | | 1,521 | | | |
| Net income (loss) | 655,004 | | | 256,677 | | | |
| Net income (loss) attributable to non-controlling interest | 503,331 | | | 198,738 | | | |
| Net income (loss) attributable to Viper Energy Partners LP | $ | 151,673 | | | $ | 57,939 | | | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Operating Results: | | | | | |
| Royalty income | $ | 160,163 |
| | $ | 78,837 |
| | $ | 74,859 |
|
| Lease bonus | 11,870 |
| | 309 |
| | — |
|
| Total operating income | 172,033 |
| | 79,146 |
| | 74,859 |
|
| Costs and expenses: | | | | | |
| Production and ad valorem taxes | 10,608 |
| | 5,544 |
| | 5,531 |
|
| Gathering and transportation | 789 |
| | 415 |
| | 259 |
|
| Depletion | 40,519 |
| | 29,820 |
| | 35,436 |
|
| Impairment | — |
| | 47,469 |
| | 3,423 |
|
| General and administrative expenses | 6,296 |
| | 5,209 |
| | 5,835 |
|
| Total costs and expenses | 58,212 |
| | 88,457 |
| | 50,484 |
|
| Income (loss) from operations | 113,821 |
| | (9,311 | ) | | 24,375 |
|
| Other income (expense): | | | | | |
| Interest expense, net | (3,164 | ) | | (2,455 | ) | | (1,110 | ) |
| Other income, net | 821 |
| | 867 |
| | 1,154 |
|
| Total other income (expense), net | (2,343 | ) | | (1,588 | ) | | 44 |
|
| Net income (loss) | $ | 111,478 |
| | $ | (10,899 | ) | | $ | 24,419 |
|
| | | | | | |
| Production Data: | | | | | |
| Oil (MBbls) | 2,899 |
| | 1,778 |
| | 1,555 |
|
| Natural gas (MMcf) | 3,549 |
| | 1,490 |
| | 1,129 |
|
| Natural gas liquids (MBbls) | 533 |
| | 328 |
| | 239 |
|
| Combined volumes (MBOE) | 4,024 |
| | 2,354 |
| | 1,982 |
|
| Daily combined volumes (BOE/d) | 11,023 |
| | 6,432 |
| | 5,431 |
|
| % Oil | 72 | % | | 76 | % | | 78 | % |
| | | | | | |
| Average sales prices: | | | | | |
| Oil, realized ($/Bbl) | $ | 48.36 |
| | $ | 40.23 |
| | $ | 44.75 |
|
| Natural gas realized ($/Mcf) | 2.62 |
| | 2.08 |
| | 2.36 |
|
| Natural gas liquids ($/Bbl) | 20.02 |
| | 12.84 |
| | 10.85 |
|
| Average price realized ($/BOE) | 39.81 |
| | 33.49 |
| | 37.76 |
|
| | | | | | |
| Average Costs ($/BOE) | | | | | |
| Production and ad valorem taxes | $ | 2.64 |
| | $ | 2.35 |
| | $ | 2.79 |
|
| Gathering and transportation expense | 0.20 |
| | 0.18 |
| | 0.13 |
|
| General and administrative - cash component | 0.97 |
| | 0.59 |
| | 0.96 |
|
| Total operating expense - cash | $ | 3.81 |
| | $ | 3.12 |
| | $ | 3.88 |
|
| | | | | | |
| General and administrative - non-cash component | $ | 0.59 |
| | $ | 1.62 |
| | $ | 1.98 |
|
| Interest expense | 0.79 |
| | 1.04 |
| | 0.56 |
|
| Depletion | 10.07 |
| | 12.67 |
| | 17.88 |
|
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | |
| (In thousands) |
| Production data: | | | | | |
| Oil (MBbls) | 7,097 | | | 6,068 | | | |
| Natural gas (MMcf) | 15,868 | | | 13,672 | | | |
| Natural gas liquids (MBbls) | 2,540 | | | 1,913 | | | |
Combined volumes (MBOE)(1) | 12,282 | | | 10,260 | | | |
| | | | | |
| Average daily oil volumes (BO/d) | 19,444 | | | 16,625 | | | |
| Average daily combined volumes (BOE/d) | 33,649 | | | 28,110 | | | |
| | | | | |
| | | | | |
| Average sales prices: | | | | | |
| Oil ($/Bbl) | $ | 94.02 | | | $ | 65.51 | | | |
| Natural gas ($/Mcf) | $ | 5.24 | | | $ | 3.60 | | | |
| Natural gas liquids ($/Bbl) | $ | 34.47 | | | $ | 28.66 | | | |
Combined ($/BOE)(2) | $ | 68.23 | | | $ | 48.88 | | | |
| | | | | |
Oil, hedged ($/Bbl)(3) | $ | 92.85 | | | $ | 50.25 | | | |
Natural gas, hedged ($/Mcf)(3) | $ | 4.20 | | | $ | 3.60 | | | |
Natural gas liquids ($/Bbl)(3) | $ | 34.47 | | | $ | 28.66 | | | |
Combined price, hedged ($/BOE)(3) | $ | 66.21 | | | $ | 39.86 | | | |
| | | | | |
| Average costs ($/BOE): | | | | | |
| Production and ad valorem taxes | $ | 4.59 | | | $ | 3.17 | | | |
| | | | | |
General and administrative - cash component(4) | 0.59 | | | 0.65 | | | |
| Total operating expense - cash | $ | 5.18 | | | $ | 3.82 | | | |
| | | | | |
| General and administrative - non-cash unit compensation expense | $ | 0.11 | | | $ | 0.11 | | | |
| Interest expense, net | $ | 3.29 | | | $ | 3.32 | | | |
| Depletion | $ | 9.86 | | | $ | 10.04 | | | |
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2)Realized price net of all deducts for gathering, transportation and processing.
(3)Hedged prices reflect the impact of cash settlements on our matured commodity derivative transactions on our average sales prices.
(4)Excludes non-cash unit compensation for the respective periods presented.
Comparison of the Years Ended December 31, 2017, 20162022 and2015 2021
Royalty Income
Our royalty income for the years ended December 31, 2017, 2016 and 2015 was $160.2 million, $78.8 million and $74.9 million, respectively. Our royalty income is a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes.
During the year ended December 31, 2017, average prices received and combined volumes sold by our operatorsRoyalty income increased as compared to the year ended December 31, 2016. Although the average prices received$336.4 million during the year ended December 31, 2016 decreased as2022 compared to 2021. As discussed in “—Recent Developments,” strong oil prices in 2022 and to a lesser extent, the continuing recovery in natural gas and natural gas liquids prices, contributed to approximately $243.1 million of the total increase.
The remaining $93.3 million of the total increase in royalty income is attributable to the 20% increase in production volumes during the year ended December 31, 2015, this decrease was partially offset by an 18.8% increase2022 compared to the same period in combined volumes sold by our operators.2021. This production growth stems from new well additions between periods primarily due to the Swallowtail Acquisition.
|
| | | | | | | | | | | | | | | | | | | |
| | 2017 vs. 2016 | | 2016 vs. 2015 |
| | Change in prices | Production volumes(1) | Total net dollar effect of change | | Change in prices | Production volumes(1) | Total net dollar effect of change |
| | (dollars in thousands except change in prices) |
| Effect of changes in price: | | | | | | | |
| Oil | $ | 8.13 |
| 2,899 |
| $ | 23,572 |
| | $ | (4.52 | ) | 1,778 |
| $ | (8,035 | ) |
| Natural gas | 0.54 |
| 3,549 |
| 1,916 |
| | (0.28 | ) | 1,490 |
| (417 | ) |
| Natural gas liquids | 7.18 |
| 533 |
| 3,829 |
| | 1.99 |
| 328 |
| 653 |
|
| Total income due to change in price | | | $ | 29,317 |
| | | | $ | (7,799 | ) |
| | | | | | | | |
| | Change in production volumes(1) | Prior period average prices | Total net dollar effect of change | | Change in production volumes(1) | Prior period average prices | Total net dollar effect of change |
| | (dollars in thousands except average prices) |
| Effect of changes in production volumes: | | | | | | | |
| Oil | 1,121 |
| $ | 40.23 |
| $ | 45,090 |
| | 222 |
| $ | 44.75 |
| $ | 9,955 |
|
| Natural gas | 2,059 |
| 2.08 |
| 4,282 |
| | 362 |
| 2.36 |
| 854 |
|
| Natural gas liquids | 205 |
| 12.84 |
| 2,637 |
| | 89 |
| 10.85 |
| 968 |
|
| Total income due to change in production volumes | | | 52,009 |
| | | | 11,777 |
|
| Total change in income | | | $ | 81,326 |
| | | | $ | 3,978 |
|
| |
(1) | Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas |
Lease Bonus Income
Lease bonus income increased by $11.6$25.0 million to $11.9 million forduring the year ended December 31, 2017 from $0.3 million2022 compared to the same period in 2021 due primarily to lease ratifications with Diamondback during the fourth quarter of 2022 as well as Diamondback leasing certain acreage acquired in the Swallowtail Acquisition during the first quarter of 2022.
Production and Ad Valorem Taxes
The following table presents production and ad valorem taxes for the yearyears ended December 31, 2016. During2022 and 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 |
| Amount
(In thousands) | | Per BOE | | Percentage of Royalty Income | | Amount
(In thousands) | | Per BOE | | Percentage of Royalty Income |
| Production taxes | $ | 42,857 | | | $ | 3.49 | | | 5.1 | % | | $ | 25,966 | | | $ | 2.53 | | | 5.2 | % |
| Ad valorem taxes | 13,515 | | | 1.10 | | | 1.6 | | | 6,592 | | | 0.64 | | | 1.3 | |
| Total production and ad valorem taxes | $ | 56,372 | | | $ | 4.59 | | | 6.7 | % | | $ | 32,558 | | | $ | 3.17 | | | 6.5 | % |
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of royalty income for 2022 remained consistent with 2021. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. The increase in ad valorem taxes is primarily due to accruing a full year of taxes in 2022 for the year ended December 31, 2017, we received $2.8 million which was attributableproperties acquired in the Swallowtail Acquisition, as well as higher valuations assigned to lease bonus payments to extend the termour other oil and natural gas interests period over period driven by higher average commodity prices. Production taxes remained consistent as a percentage of seven leases, reflecting an average bonus of $3,442 per acre, and $9.1 million attributable to lease bonus payments on three new leases, reflecting an average bonus of $14,320 per acre. During the year ended December 31, 2016, we received $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre. We had no lease bonusroyalty income for the year ended December 31, 2015.2022 compared to the same period in 2021. We expect production and ad valorem taxes for 2023 to be approximately 7% to 8% of revenue.
ImpairmentDepletion
The $18.1 million increase in depletion expense for 2022 compared to 2021 was due primarily to an increase in production, partially offset by a decrease in the depletion rate to $9.86 from $10.04, respectively. The rate decrease largely resulted from higher SEC oil prices utilized in the reserve calculations in the 2022 period, lengthening the economic life of Oilthe reserve base and Gas Properties.resulting in higher projected remaining reserve volumes on our wells.
DuringNet Interest Expense
Net interest expense for 2022 and 2021 totaled $40.4 million and $34.0 million, respectively. The increase of $6.4 million was due primarily to an increase of $8.2 million in interest expense under the Operating Company’s revolving credit facility during 2022 compared to 2021, which resulted from an increase in both the weighted average borrowings outstanding and the weighted average interest rate on those borrowings. This increase was partially offset by interest cost savings on the portion of the Notes that were repurchased during 2022.
Derivative Instruments
The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 |
| (In thousands) |
| Gain (loss) on derivative instruments | $ | (18,138) | | | $ | (69,409) | |
Net cash receipts (payments) on derivatives(1) | $ | (31,319) | | | $ | (92,585) | |
| | | |
| | | |
(1)The year ended December 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $6.6 million.
We recorded losses on our derivative instruments for the years ended December 31, 20162022 and 2015,2021 primarily due to market prices being higher than the strike prices on our derivative contracts. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” See Note 10—Derivatives of the notes to the consolidated financial statements included elsewhere in this Annual Report for additional discussion of our open contracts at December 31, 2022.
Provision for (Benefit from) Income Taxes
We recorded impairmentsan income tax benefit of oil and gas properties of $47.5$32.7 million and $3.4expense of $1.5 million respectively, asfor the years ended December 31, 2022 and 2021, respectively. The change in our income tax provision was primarily due to the impact of a resultreduction to the valuation allowance on our deferred tax assets during the third quarter of the significant decline2022, partially offset by an increase in commodity prices. No impairment was recordedcurrent income taxes resulting from higher pre-tax income. The total income tax provision for the year ended December 31, 2017.
General and Administrative Expenses
For2022 differed from amounts computed by applying the years ended December 31, 2017, 2016 and 2015, we incurred general and administrative expenses of $6.3 million, $5.2 million and $5.8 million, respectively. The general and administrative expenses primarily reflect costs associated with us being a publicly traded limited partnership, unit-based compensation, the amounts reimbursedfederal statutory tax rate to our general partner under our partnership agreement and amounts incurred under our advisory services agreement. For the year ended December 31, 2017, the General Partner received reimbursements from us of $2.5 million. For the year ended December 31, 2016, the General Partner did not receive any reimbursements from us. For the year ended December 31, 2015, the General Partner did not receive any reimbursements from us other than the $4,000 outstanding at December 31, 2014.
Net Interest Expense
Net interest expensepre-tax income for the
years ended December 31, 2017, 2016 and 2015 was $3.2 million, $2.5 million and $1.1 million, respectively. The increase of $0.7 million in net interest expense for the year ended December 31, 2017 as compared to 2016 was due to a higher average interest rate and increased average level of outstanding borrowings. The increase of $1.3 million in net interest expense for the year ended December 31, 2016 as compared to 2015 wasperiod primarily due to
net income attributable to the non-controlling interest and the impact of maintaining a
higher average levelpartial valuation allowance on our deferred tax assets. See Note 9—Income Taxes of
outstanding borrowings under our credit agreement.
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of ourthe notes to the consolidated financial statements such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure.included elsewhere in this Annual Report for further details.
We define Adjusted EBITDA as net income (loss) plus net interest expense, non-cash unit-based compensation expense, depletion expense and impairment expense. Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA.
Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods indicated.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in thousands) |
| Net income (loss) | $ | 111,478 |
| | $ | (10,899 | ) | | $ | 24,419 |
|
| Interest expense, net | 3,164 |
| | 2,455 |
| | 1,110 |
|
| Non-cash unit-based compensation expense | 2,395 |
| | 3,815 |
| | 3,929 |
|
| Depletion | 40,519 |
| | 29,820 |
| | 35,436 |
|
| Impairment | — |
| | 47,469 |
| | 3,423 |
|
| Adjusted EBITDA | $ | 157,556 |
| | $ | 72,660 |
| | $ | 68,317 |
|
Liquidity and Capital Resources
Overview of Sources and Uses of Cash
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 and liquidity requirements. Our future ability to grow proved reserves will be highly dependent on the capital resources available to us. Our primary sources of liquidity have been cash flows from operations, proceeds from sales of non-core assets and investments, equity and debt financings, includingofferings and borrowings under ourthe Operating Company’s credit agreement, and ouragreement. Our primary uses of cash have been and are expected to continue to be, to pay distributions to our unitholders, and for replacement and growthrepayments of debt, capital expenditures includingfor the acquisition of our mineral interests and royalty interests in oil and natural gas properties. properties and repurchases of our common units. At December 31, 2022, we had approximately $366.2 million of liquidity consisting of $18.2 million in cash and cash equivalents and $348.0 million available under the Operating Company’s credit agreement.
Our abilityworking capital requirements are supported by our cash and cash equivalents and the Operating Company’s credit agreement. We may draw on the Operating Company’s credit agreement to generatemeet short-term cash is subjectrequirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to a number of factors, some of which are beyond our control, including commodity prices, weather and general economic, financial, competitive, legislative, regulatory and other factors. In 2018,us as discussed above, we believe cash flows fromthat our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and availability underlong-term funding requirements including our credit agreement will provide sufficient liquidity to manage our cash needsacquisitions of mineral and contractualroyalty interests, distributions, debt service obligations and repayment of debt maturities, common unit and senior note repurchases and any amounts that may ultimately be paid in connection with contingencies.
In order to fund expected capital expenditures. We continually monitor market conditions and may consider issuing more equity or taking on debt if we believe conditions to be favorable.
Our partnership agreement does not require us to distribute any of the cash we generate from operations. We believe, however, that it ismitigate volatility in the best interests of our unitholders if we distribute a substantial portion of the cash we generate from operations. The board of directors of our general partner has adopted a policy to distribute an amount equal to the available cash we generate each quarter to our unitholders. Cash distributions are made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter is determined by the board of directors of our general partner following the end of such quarter. Available cash for each quarter generally equals Adjusted EBITDA reduced for cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any.
The following table presents cash distributions approved by the board of directors of our general partner for the periods presented.
|
| | | | | | | | | | | | |
| Declaration Date | | Quarter | | Amount per Common Unit | | Payment Date | | Amount Distributed to Diamondback |
| | | | | | | | | (in thousands) |
| May 1, 2015 | | Q1 2015 | | $ | 0.189 |
| | May 22, 2015 | | $ | 13,385 |
|
| July 31, 2015 | | Q2 2015 | | $ | 0.220 |
| | August 21, 2015 | | $ | 15,499 |
|
| October 30, 2015 | | Q3 2015 | | $ | 0.200 |
| | November 20, 2015 | | $ | 14,091 |
|
| February 12, 2016 | | Q4 2015 | | $ | 0.228 |
| | February 26, 2016 | | 16,063 |
|
| May 2, 2016 | | Q1 2016 | | $ | 0.149 |
| | May 23, 2016 | | $ | 10,497 |
|
| July 21, 2016 | | Q2 2016 | | $ | 0.189 |
| | August 22, 2016 | | $ | 13,693 |
|
| October 25, 2016 | | Q3 2016 | | $ | 0.207 |
| | November 18, 2016 | | $ | 14,997 |
|
| February 3, 2017 | | Q4 2016 | | $ | 0.258 |
| | February 24, 2017 | | $ | 18,692 |
|
| April 28, 2017 | | Q1 2017 | | $ | 0.302 |
| | May 25, 2017 | | $ | 21,880 |
|
| July 28, 2017 | | Q2 2017 | | $ | 0.332 |
| | August 24, 2017 | | $ | 24,286 |
|
| October 16, 2017 | | Q3 2017 | | $ | 0.337 |
| | November 14, 2017 | | $ | 24,652 |
|
| January 26, 2018 | | Q4 2017 | | $ | 0.460 |
| | February 26, 2018 | | * |
|
* The Q4 2017 distribution is payable on February 26, 2018 to unitholders of record at the close of business on February 19, 2018. Based on the common units held by Diamondback on February 6, 2018, the Q4 2017 distribution payable to Diamondback on February 26, 2018 will be approximately $33.6 million.
Our Credit Agreement
On July 8, 2014, we entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, as sole book runner and lead arranger. The credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on our oil and natural gas
reservesprices, we have entered into commodity derivative contracts as discussed further in Item 7A. Quantitative and other factors (the “borrowing base”) of $400.0 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, we may request up to three additional redeterminations ofQualitative Disclosures About Market Risk—Commodity Price Risk.
Continued prolonged volatility in the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $400.0 million, and we had $93.5 million of outstanding borrowings and $306.5 million available for future borrowings under our revolvingcapital, financial and/or credit facility.
The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternate base rate (which is equalmarkets due to the greatest ofCOVID-19 pandemic, the prime rate, the Federal Funds effective rate plus 0.50% 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 annumwar in the caseUkraine, the depressed commodity markets and, or adverse macroeconomic conditions, including persistent inflation, rising interest rates, global supply chain disruptions and increasing concerns over a potential economic downturn or recession, may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although we expect that our sources of funding will be adequate to fund our short-term and long-term liquidity requirements, we cannot assure you that the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case dependingneeded capital will be available 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. We are 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 premiumacceptable terms or penalty (other than customary LIBOR breakage), and is required to be repaid (a) 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), (b) 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 (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of our and our subsidiary’s assets.all.
The 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.
|
| | |
Financial Covenant | | Required Ratio |
Ratio of total debt to EBITDAX | Not greater than 4.0 to 1.0 |
Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
As of December 31, 2017, we were in compliance with all financial covenants under our credit agreement. 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. With certain specified exceptions, the terms and provisions of our credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.
Cash Flows
The following table presents our cash flows for the period indicated.indicated:
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | |
| (In thousands) |
| Cash Flow Data: | | | | | |
| Net cash provided by (used in) operating activities | $ | 699,796 | | | $ | 307,114 | | | |
| Net cash provided by (used in) investing activities | 47,571 | | | (281,176) | | | |
| Net cash provided by (used in) financing activities | (768,636) | | | (5,611) | | | |
| Net increase (decrease) in cash and cash equivalents | $ | (21,269) | | | $ | 20,327 | | | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in thousands) |
| Cash Flow Data: | | | | | |
| Net cash provided by operating activities | $ | 139,219 |
| | $ | 68,627 |
| | $ | 63,832 |
|
| Net cash used in investing activities | (344,079 | ) | | (205,721 | ) | | (43,907 | ) |
| Net cash provided by (used in) financing activities | 219,844 |
| | 145,768 |
| | (34,496 | ) |
| Net increase (decrease) in cash | $ | 14,984 |
| | $ | 8,674 |
| | $ | (14,571 | ) |
Operating Activities
Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volume of oil and natural gas sold by our producers. PricesThe increase in net cash provided by operating activities during the year ended December 31, 2022 compared to the same period in 2021 was primarily driven by higher royalty and lease bonus income in 2022 as well as a reduction in cash paid for these commodities are determinedderivative settlements. These cash inflows from operating activities were partially offset by higher production and ad valorem taxes and cash payments for income taxes as well as changes in our working capital accounts, most notably through an increase in our royalty income accounts receivable due primarily by prevailing market conditions. Regionalto growth in production volumes and worldwide economic activity, weatherhigher average prices received for our production in 2022 compared to 2021. See —Results of Operations” above for further discussion of significant changes in our income and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.expenses.
Investing Activities
The purchaseNet cash provided by investing activities during the year ended December 31, 2022 primarily related to proceeds from the divestitures of oil and natural gas interests accountedincluding our Eagle Ford properties, partially offset by expenditures for the majorityacquisitions of our cash outlays for investing activities. oil and natural gas interests.
Net cash used in investing activities was $344.1 million, $205.7 million and $43.9 million during the years ended December 31, 2017, 2016 and 2015, respectively, related to acquisitions of royalty interests.
Financing Activities
Net cash provided by financing activities was $219.8 million during the year ended December 31, 2017,2021 primarily related to aggregateacquisitions of oil and natural gas interests.
Financing Activities
Consistent with our strategy to return cash flow to unitholders, net proceeds of $380.0 million from our public offerings of common unitscash used in January and July 2017, partially offset by $130.9 million of distributions to our unitholders and $27.0 million of net repayments under our revolving credit agreement during 2017.
Net cash provided by financing activities was $145.8 million during the year ended December 31, 2016,2022, was primarily related to $86.0distributions of $416.9 million of net borrowings under our revolving credit agreement and net proceeds of $125.0 million from our public offering of common units partially offset by $64.8 million of distributions to our unitholders during 2016.and $150.6 million of repurchases of our common units. Additionally, we reduced our debt profile by repaying a net $152.0 million of outstanding borrowings under the Operating Company’s revolving credit facility, and repurchasing $49.0 million of our Notes.
Net cash used in financing activities of $34.5 million during the year ended December 31, 20152021, was primarily related to $68.6net borrowings of $220.0 million under the Operating Company’s revolving credit facility to fund the Swallowtail Acquisition, distributions of distributions$176.6 million to our unitholders during 2015, after giving effect to $34.5and $46.0 million of proceeds fromrepurchases of our common units during the fourth quarter of 2021.
Capital Resources
The Operating Company’s Revolving Credit Facility
At December 31, 2022, the Operating Company’s credit agreement, which matures on June 2, 2025, had an elected commitment amount of $500.0 million, with $152.0 million in outstanding borrowings and $348.0 million of availability.
2022 Debt Transactions
During the year ended December 31, 2022, the Operating Company used a combination of cash on hand and borrowings under the Operating Company’s credit agreement to repurchase a portion of the Notes in the aggregate principal amount of $49.6 million for total cash consideration of $49.0 million. As of December 31, 2022, the Operating Company was in compliance, and expects to be in compliance, with all financial maintenance covenants under its credit agreement.
See Note 6—Debt of the notes to the consolidated financial statements included elsewhere in this Annual Report for additional discussion of our credit facility.outstanding debt at December 31, 2022.
Contractual ObligationsCapital Requirements
The following table summarizes our contractualSenior Notes
Our outstanding Notes obligations and commitmentstotal $430.4 million as of December 31, 2017.2022.There are no principal amounts due until 2027. At December 31, 2022, we have a remaining aggregate interest expense obligation of $115.7 million on the Notes with $23.1 million being due each year from 2023 to 2027. The Notes are not subject to any mandatory redemption or sinking fund requirements. See Note 6—Debt of the notes to the consolidated financial statements included elsewhere in this Annual Report for further information on the Notes. |
| | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| | Total | | 2018 | | 2019-2020 | | 2021-2022 | | Thereafter |
| | (in thousands) |
Credit agreement(1) | $ | 93,500 |
| | $ | — |
| | $ | — |
| | $ | 93,500 |
| | $ | — |
|
Interest and commitment fees under our credit agreement(2) | $ | 5,555 |
| | $ | 1,149 |
| | $ | 2,299 |
| | $ | 2,107 |
| | $ | — |
|
| | $ | 99,055 |
| | $ | 1,149 |
| | $ | 2,299 |
| | $ | 95,607 |
| | $ | — |
|
| |
(1) | Includes the outstanding principal amount under the credit agreement, the table does not include 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) | This table reflects only the minimum amount of interest and commitment fees due, which as of December 31, 2017 includes a commitment fee equal to 0.375% per year of the unused portion of the borrowing base of our credit agreement. The table does not include interest expense as we cannot predict the timing of future borrowings and repayments or interest rates to be charged. See Note 5–Debt to our consolidated financial statements and related notes included elsewhere in this Annual Report. |
Repurchases of Securities
On July 26, 2022, the board of directors of our General Partner approved an increase of the authorization under its common unit repurchase program from $250.0 million to $750.0 million. As of December 31, 2022, $529.4 million remains available for use to repurchase units under the repurchase program. See Note 7—Unitholders' Equity and Distributions of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of the unit repurchase program.
Cash Distributions
We paid total distributions of $416.9 million and $176.6 million on our common units, participating securities under the LTIP, and the Operating Company’s Class B units during 2022 and 2021, respectively.
The distribution for the fourth quarter of 2022 is $0.49 per common unit payable on March 10, 2023 to common unitholders of record at the close of business on March 3, 2023. The distribution consists of a base quarterly distribution of $0.25 per common unit and a variable quarterly distribution of $0.24 per common unit. Based on the common units, Class B units and Operating Company units held by Diamondback on February 21, 2023, the distribution payable to Diamondback for the fourth quarter of 2022 on March 10, 2023 will be approximately $49.3 million. See Note 7—Unitholders' Equity and Distributions of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of our distributions. We expect to continue paying quarterly cash distributions in respect of our common units. Future base and variable distributions are not required and are at the discretion of the board of directors of our General Partner, who may change the distribution policies at any time.
Critical Accounting PoliciesEstimates
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 GAAP. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See the notes to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding these accounting policies.
Use of Estimates
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. Actual results could differ from those estimates.
Accounting estimates are considered to be critical if (i) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (ii) the impact of the estimates and assumptions on financial condition or operating performance is material. We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our 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
We consider the following to suchbe our most critical accounting estimates and assumptions includehave reviewed these critical accounting estimates with the Audit Committee of provedour Board of Directors.
Royalty Income and Revenue Recognition
We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and natural gas reservesliquids sales from third party operators other than Diamondback may not be received for 30 to 90 days after the date production is delivered. To the extent actual volumes and related present value estimates of future net cash flows therefrom, the carrying valueprices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and unit–recorded based compensation.upon the Partnership’s interest. Where available, historical actual data is used to calculate volume estimates for wells operated by third parties. If historical actual data is not available for these wells, engineering estimates are used to calculate expected volumes. As such, estimated volumes utilized in period end royalty income accruals are subject to revision as additional actual data becomes available and such revisions may have a material impact on our results of operations and our royalty income receivables. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis. We record the differences between our estimates and the actual amounts received for royalties from third parties in the month that payment is received from the producer. We have existing internal controls for our royalty income estimation process and related accruals, but actual third party royalty income in future periods could differ materially from estimated amounts. At December 31, 2022, our accrual for third party royalty was approximately $65.1 million. Actual revenues received from third parties were higher by approximately $10.0 million, or 20%, compared to the accrual at December 31, 2021.
Method of Accounting for Oil and Natural Gas PropertiesAccounting and Reserves
We account for oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred inaccounting, which is dependent on the acquisition, exploration and developmentestimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties includingand whether the costsvalue of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. 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.
Depletion ofour evaluated oil and natural gas properties is computedpermanently impaired based on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.
Costs associated with unevaluated properties are excluded from thequarterly full cost pool untilceiling impairment test. Further, we have made a determination asutilize estimated proved reserves to assign fair value to acquired mineral and royalty interests. As such, we consider the existenceestimation 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 asreserves to be 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.critical accounting estimate.
Oil and Natural Gas Reserve Quantities and Standardized Measurenatural gas reserve engineering is a subjective process of Discounted Future Net Cash Flows
Our independent engineers and technical staff prepare our estimatesestimating underground accumulations of oil and natural gas reservesthat 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. Proved oil and natural gas reserve estimates and their associated future net cash flows. The SEC has defined proved reservesflows were prepared by our internal reservoir engineers and audited by Ryder Scott, independent petroleum engineers, as the estimated quantities of oilDecember 31, 2022 and natural gas which geologicalprepared by Ryder Scott as of December 31, 2021 and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.2020. 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. Significant inputs included in the calculation of future net cash flows include anticipated production of proved reserves and other relevant 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.time, and reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. 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 amortizationdepletion of capitalized costs and result in impairment of assets that may be material.
There are numerous uncertainties inherent in estimating quantities Revisions 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 functionprevious quantity estimates accounted for approximately 23% of the qualitychange in the total standardized measure of available dataour reserves from December 31, 2021 to December 31, 2022, and of engineeringwere primarily related to negative revisions due to PUD downgrades during 2022.
Our unevaluated property costs are tracked by lease and geological interpretationprospect. We assess all items classified as unevaluated property (on an individual basis or as a group if properties are individually insignificant) at least annually for possible impairment. This assessment is subjective and judgment. Results of drilling, testing and production subsequent to the dateincludes consideration of the estimate may justify revisioncalculated value for each lease based on the total costs incurred for the lease divided by the number of such estimate. Accordingly, reserve estimates are often differentacres available to develop compared to current market prices for acreage in the related basins. We also monitor information available from the quantitiesthird party operators of oil and natural gas that are ultimately recovered.
Royalty Interest and Revenue Recognition
Royalty interests represent the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue isour acreage for future drilling plans as part of our impairment assessment. At December 31, 2022, our unevaluated properties totaled $1.3 billion. No impairments were recorded when title passes to the purchaser.
Holders of royalty interests have no rights or obligations to explore, develop or operate the property and do not incur any of the costs of exploration, development and operation of the property.
Impairment
The net capitalized costs ofon our 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, impairment and deferred income taxes exceed the discounted future net revenues of proved oil and natural gas reserves, less any related income tax effects, the
excess capitalized costs are charged to expense. In calculating future net revenues, prices are calculated as the average oil and gas prices during the
preceding 12-month period prioryears ended December 31, 2022 and 2021; however, impairment expense of $69.2 million was recorded for the year ended December 31, 2020 as discussed further in Note 5—Oil and Natural Gas Interests of the notes to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period.
Accounting for Unit-Based Compensation
Unit-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. The LTIP and related accounting policies are defined and described more fully in Note 7–Unit-Based Compensation to our audited consolidated financial statements included elsewhere in this Annual Report. Due to an increase in the historical 12-month average trailing SEC prices for oil and natural gas throughout 2022, we are not currently
projecting a full cost ceiling impairment in the first quarter of 2023. Any future impairment could be material to our consolidated financial statements.
Derivative Instruments
In order to reduce uncertainty around commodity prices received for our oil and natural gas operators’ production, we enter into commodity price derivative contracts from time to time. 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 determination ofaccounting for the changes in fair value of an award requires significant estimatesa derivative depends on the intended use of the derivative and subjective judgments regarding,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 appropriate option pricing model,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
We have elected to be treated as a corporation for U.S. federal income tax purposes. 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 (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 after considering all positive and negative evidence available concerning the realizability of our deferred tax assets. Positive evidence may include forecasts of future taxable income, assessment of future business assumptions and any applicable tax planning strategies available to the Partnership. Negative evidence may include losses in recent years, if any, or the projection of losses in future periods. Estimating future taxable income requires numerous judgments and assumptions, including projections of future operating conditions which may be impacted by volatile future prices for our oil, natural gas and natural gas production, the expected lifetiming and quantity of future production volumes, and the impact of our commodity derivative instruments on our income. These assumptions are discussed further in the critical accounting estimates titled “— Royalty Interest and Revenue Recognition” and “— Oil and Natural Gas Accounting and Reserves”. Due to the impact these various assumptions and estimates can have on our estimates of taxable income, an estimate of the awardsensitivity to changes is not practicable.
In 2022, management’s assessment of all available evidence, both positive and forfeiture rate assumptions. Estimatesnegative, supporting realizability of the fair valuePartnership’s deferred tax assets as required by applicable accounting standards, resulted in recognition of unit options granted duringa deferred income tax benefit of $49.7 million for the year endedportion of the Partnership’s deferred tax assets considered more likely than not to be realized. The positive evidence assessed included recent cumulative income due in part to higher commodity prices and an expectation of future taxable income based upon recent actual and forecasted production volumes and prices. The Partnership retained a partial valuation allowance on its deferred tax assets due primarily to potential future volatility in commodity prices and an inherent lack of visibility to certain underlying operator activity for more than relatively short periods of time, which could impact the likelihood of future realizability. As of December 31, 2017, were completed using2022, the Partnership had a Black-Scholes option valuation model, which requires usdeferred tax asset of $148.1 million offset by an allowance of $98.4 million.
The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to make several assumptions.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.
Recent Accounting Pronouncements
Recently Issued Pronouncements
We will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. We have reviewed various contracts that represent our material revenue streams and determined that there will be no impact to our financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, we will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, we will not be required to alter our existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by us. We do not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how we present information regarding our revenue streams as compared to existing GAAP.
In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. We will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equity and bring the fair valuenotes of our investment to $15.2 million or $15.20 per unit for that investment.
In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. We will adopt this updated retrospectively effective January 1, 2018. The adoption of this update will only effect the presentation on the Statement of Cash Flows.
In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. We will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on our financial position, results of operations or liquidity.
Accounting Pronouncements Not Yet Adopted
In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting,
changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of the filing date, we were not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. Therefore, we believe the adoption of this update will not have an impact on our financial position, results of operations or liquidity.
In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 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. This update will be effective forconsolidated financial statements issuedincluded elsewhere in this Annual Report for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings asfull listing of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard will have an impact on our financial statements since we do not have a history of credit losses.significant accounting policies.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2017, 2016 and 2015. Although the impact of inflation has been insignificant in recent years, it continues to be a factor in the U.S. economy and our operators do experience inflationary pressure on the costs of oilfield services and equipment as drilling activity increases in the areas in which our properties are located.
Off-Balance Sheet Arrangements
We currently have no off-balance sheet arrangements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to the oil and natural gas production of our operators. Realized pricing isprices are driven primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to ourfor natural gas production.in the United States. Both crude oil and natural gas realized prices are also impacted by the quality of the product, supply and demand balances in local physical markets and the availability of transportation to demand centers. Pricing for oil and natural gas production has been historically volatile and unpredictable particularly duringand the past year, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control.control, such as the war in the Ukraine, rising interest rates, global supply chain disruptions, a potential economic downturn or recession, the COVID-19 pandemic and actions taken by OPEC members and other exporting nations. We cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.
We historically have used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of our royalty income as discussed in Note 10—Derivatives of the notes to the consolidated financial statements included elsewhere in this Annual Report.
At December 31, 2022, we had a net asset derivative position related to our commodity price derivatives of $9.8 million, related to our contracts. Utilizing actual derivative contractual volumes under our contracts as of December 31, 2022, a 10% increase in forward curves associated with the underlying commodity would have increased the net asset position by $2.8 million to $12.6 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net asset derivative position by $2.5 million to $7.2 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.
Credit Risk
We are subject to risk resulting from the concentration of royalty interest revenuesincome in producing oil and natural gas properties and receivables with a limited number of several significant purchasers. For the year ended December 31, 2017,2022, two purchasers accounted for more than 10% of our income. For the years ended December 31, 2021 and 2020, three and four purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (US) Company, or Shell Trading (47%) and RSP Permian LLC (23%). Forour income, respectively. See Note 2—Summary of Significant Accounting Policies of the year ended December 31, 2016, two purchasers each accountednotes to the consolidated financial statements included elsewhere in this Annual Report for more than 10% of royalty interest revenue: Shell Trading (57%) and RSP Permian LLC (32%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (68%) and RSP Permian LLC (25%).further details. We do not require collateral and do not believe the lossfailure or inability of any singleour significant purchasers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. Volatility in commodity pricing environment and macroeconomic conditions may enhance our purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.credit risk.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under ourthe Operating Company’s credit agreement. The terms of ourthe credit agreement currently provide for interest on borrowings at a floating rate equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”) or (ii) an alternativealternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 3-month LIBOR1-month Adjusted Term SOFR plus 1.0%1.00%) or LIBOR,, in
each case plus the applicable margin. The applicable margin ranges from 0.75%1.00% to 1.75%2.00% per annum in the case of the alternative base rate and from 1.75%2.00% to 2.75%3.00% per annum in the case of LIBOR,Adjusted Term SOFR, in each case depending on the amount of the loans and letters of credit outstanding in relation to the commitment, which is defined ascalculated using the lesserleast of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment. As of December 31, 2017,2022, we had $93.5$152.0 million in outstanding borrowings under our credit agreement with aborrowings. During the year ended December 31, 2022, the weighted average rate of 3.19%. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $0.9 million based on the $93.5 million outstanding in the aggregate under our credit agreement on December 31, 2017.was 4.22%.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears beginning on page F-1 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 the Chief Executive Officer and Chief Financial Officer of our general partner,General Partner, 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 the Chief Executive Officer and Chief Financial Officer of our general partner,General Partner, 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, 2017,2022, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our general partner,General Partner, 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 the evaluation, the Chief Executive Officer and Chief Financial Officer of our general partnerGeneral Partner have concluded that as of December 31, 2017,2022, 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 yearquarter ended December 31, 20172022 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 our general partnerGeneral Partner is responsible for establishing and maintaining adequate internal control over financial reporting of the Partnership. The Partnership’s internal control over financial reporting is a process designed under the supervision of the Chief Executive Officer and Chief Financial Officer of our general partnerGeneral Partner to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Partnership’s financial statements for external purposes in accordance with generally accepted accounting principles.
Management conducted an evaluation of the effectiveness of the Partnership’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 Partnership’s internal control over financial
reporting and determined that the Partnership maintained effective internal control over financial reporting as of December 31, 2017.2022.
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.
As an entity with less than $1 billion in revenue during our last fiscal year, we qualify as an “emerging growth company” as defined inGrant Thornton LLP, the Jumpstart Our Business Startups Act of 2012, orindependent registered public accounting firm that audited the JOBS Act. As an emerging growth company, we may take advantage of specified reduced reporting and other regulatory requirements for up to five years from our IPO that are otherwise applicable generally to public companies. As an emerging growth company, we are taking advantageconsolidated financial statements of the exemption from the auditor attestation requirementPartnership included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Partnership’s internal control over financial reporting at December 31, 2022. The report, which expresses an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting at December 31, 2022, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
General Partner and Unitholders
Viper Energy Partners LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Viper Energy Partners LP (a Delaware limited partnership) and subsidiary (the “Partnership”) as of December 31, 2022, 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 systemopinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, 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 Partnership as of and for the year ended December 31, 2022, and our report dated February 23, 2023 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Partnership’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.reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’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 Partnership 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 23, 2023
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Management of Viper Energy Partners LP
We are managed and operated by the board of directors and the executive officers of our general partner,General Partner, the latter of whom are employed by Diamondback.
Diamondback owns all of the membership interests in our general partner.General Partner. As a result of owning our general partner,General Partner, Diamondback has the right to appoint all members of the board of directors of our general partner,General Partner, including the independent directors. Our common unitholders are not entitled to elect our general partnerGeneral Partner or its directors or otherwise directly participate in our management or operation. Our general partnerGeneral Partner owes certain duties to our common unitholders as well as a fiduciary duty to its owner.
The executive officers of our general partnerGeneral Partner manage the day-to-day affairs of our business. All of the executive officers of our general partnerGeneral Partner also serve as executive officers of Diamondback. The executive officers listed below allocate their time between managing our business and the business of Diamondback.
Executive Officers and Directors of Our General Partner
The following table shows information for the executive officers and directors of our general partnerGeneral Partner as of January 31, 2018.February 1, 2023. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board.board of directors of our General Partner. There are no family relationships among any of our General Partner’s directors or executive officers.
|
| | | | | | | | | | | | | |
Name | Age
| Age | | Position With Our General Partner |
| Travis D. Stice | 56 | 61 | | Chief Executive Officer and Director |
| Kaes Van't Hof | 31 | 36 | | President |
| Teresa L. Dick | 48 | 53 | | Chief Financial Officer, Executive Vice President and Assistant Secretary |
Russell Pantermuehl | 58 | Executive Vice President—Reservoir Engineering | | |
Thomas F. Hawkins | 63 | Senior Vice President—Land | | |
Randall J. HolderMatt Zmigrosky | 64 | 44 | | Executive Vice President, General Counsel and Secretary |
Paul S. Molnar | 61 | Executive Vice President—Exploration and Business Development | | |
| Steven E. West | 57 | Executive 62 | | Chairman of the Board and Director |
| W. Wesley Perry | 61 | 66 | | Director |
| Spencer D. Armour | 63 | 68 | | Director |
Michael L. Hollis | 42 | Director | | |
| James L. Rubin | 33 | 38 | | Director |
Rosalind Redfern Grover | 76 | | | |
| Frank C. Hu | | 61 | | Director |
Travis D. Stice. Mr. Stice has served as Chief Executive Officer and a director of our general partnerGeneral Partner since February 2014. He has served as Diamondback’s Chairman of the Board since February 2022, Chief Executive Officer of Diamondback since January 2012 and as a director since November 2012. Mr. Stice has also served as the Chief Executive Officer and a director of the General Partner of Rattler Midstream LP, referred to herein as Rattler, since July 2018. From May 2019 through August 2022, Rattler was a publicly traded subsidiary of Diamondback until it was acquired by Diamondback through a merger. Prior to histhese positions with usour General Partner, Diamondback and Diamondback,General Partner of Rattler, Mr. Stice served as itsDiamondback’s President and Chief Operating Officer from April 2011 to January 2012. From November 2010 to April 2011, Mr. Stice served as a Production Manager of Apache Corporation, an oil and gas exploration company. Mr. Stice served as a Vice President of Laredo Petroleum Holdings, Inc., an oil and gas exploration and production company, from September 2008 to September 2010 and as a Development Manager of ConocoPhillips/Burlington Resources Mid-Continent Business Unit, an oil and gas exploration company, from April 2006 until August 2008. Prior to that, Mr. Stice held a series of positions of increasing responsibilities at Burlington Resources an oil and gas explorationuntil that company most recently as a General Manager, Engineering, Operations and Business Reporting of its Mid Continent Division from January 2001 until Burlington Resources’ acquisitionwas acquired by ConocoPhillips in March 2006. Mr. Stice started his career with Mobil Oil in 1985. Mr. Stice has over 2638 years of experience in production operations, reservoir engineering, production engineering and unconventional oil and gas exploration and over 1829 years of management experience. Mr. Stice graduated from
Texas A&M University with a Bachelor of Science degree in Petroleum Engineering. He is a registered engineer in the State of Texas and is a 25-year38-year member of the Society of Petroleum Engineers. He also serves on industry boards for the American Petroleum Institute, American Exploration and Production Council, the Domestic Energy Producers Alliance, the Permian Strategic Partnership, the Texas A&M Petroleum Engineering Advisory Board, and the Texas A&M Engineering Advisory Council. Additionally, Mr. Stice is on the board of the Dynamic Catholic Institute and the local community board for the Midland Chamber of Commerce.
We believe Mr. Stice’s expertise and extensive industry and executive management experience, including at Diamondback, make him a valuable asset to the board of directors of our general partner.General Partner.
Kaes Van’t Hof. Mr. Van't Hof has served as President of our general partnerGeneral Partner since March 2017. Mr. Van't Hof joinedHe has served as Diamondback’s President and Chief Financial Officer since February 2022. Prior to his current position with Diamondback, he served as Diamondback’s Chief Financial Officer and Executive Vice President of Business Development from March 2019 to February 2022, as Senior Vice President—Strategy and Corporate Development from January 2017 to February 2019 and as Vice President of Strategy and Corporate Development since joining Diamondback in July 20162016. Mr. Van’t Hof has also served as Vice President-StrategyPresident and Corporate Development and was promoted to Senior Vice President-Strategy and Corporate Development in February 2017.director of the General Partner of Rattler since July 2018. Prior to his positions with usour General Partner, Diamondback and Diamondback,General Partner of Rattler, Mr. Van't Hof served as Chief Executive Officer for Bison Drilling and Field Services from September 2012 to June 2016. From August 2011 to August 2012, Mr. Van't Hof was an analyst for Wexford Capital LP responsible for developing operating models and business plans, including in connection with our initial public offering, and before that worked for the Investment Banking-Financial Institutions Group of Citigroup Global Markets, Inc. from February 2010 to JulyAugust 2011. Mr. Van't Hof was a professional tennis player from May 2008 to January 2010. Mr. Van't Hof received a Bachelor of Science in Accounting and Business Administration from the University of Southern California.
Teresa L. Dick. Ms. Dick has served as Chief Financial Officer, and Executive Vice President and Assistant Secretary of our general partnerGeneral Partner since February 2017 and served as Chief Financial Officer, and Senior Vice President and Assistant Secretary from February 2014 to February 2017. She has also served as Diamondback'sDiamondback’s Executive Vice President and Chief Accounting Officer since March 2019. Ms. Dick served as Diamondback’s Executive Vice President and Chief Financial Officer sincefrom February 2017 to February 2019, as its Assistant Secretary since October 2012, as its Chief Financial Officer and Senior Vice President from November 2009 to February 2017 and as its Corporate Controller from November 2007 until November 2009. Ms. Dick has served as Chief Financial Officer, Executive Vice President and Assistant Secretary of the general partner of Rattler since July 2018. From June 2006 to November 2007, Ms. Dick held a key management position as the Controller/Tax Director at Hiland Partners, a publicly traded midstream energy master limited partnership. Ms. Dick has over 1925 years of accounting experience, including over eight years of public company experience in both audit and tax areas. Since March 2021, Ms. Dick has served as a director of The Bank7 Corp. (Nasdaq: BSVN) and is a member of the Audit and Nominating and Corporate Governance Committees. Ms. Dick received her Bachelor of Business Administration degree in Accounting from the University of Northern Colorado. She is a certified public accountant and a member of the American Institute of CPAs and the Council of Petroleum Accountants Societies.
Russell Pantermuehl.Matt Zmigrosky. Mr. Pantermuehl has served as Executive Vice President-Reservoir Engineering of our general partner since February 2017 and served as Vice President-Reservoir Engineering from February 2014 to February 2017. He has also served as Diamondback's Executive Vice President-Reservoir Engineering since February 2017, and served as Vice President-Reservoir Engineering from August 2011 to February 2017. Prior to his positions with us and Diamondback, Mr. Pantermuehl served as a reservoir engineering supervisor for Concho Resources Inc., an oil and gas exploration company, from March 2010 to August 2011. Mr. Pantermuehl worked for ConocoPhillips Company as a reservoir engineering advisor from January 2005 to March 2010. Mr. Pantermuehl also worked as an independent consultant in the oil and gas industry from March 2000 to December 2004. He received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.
Thomas F. Hawkins. Mr. Hawkins has served as Senior Vice President-Land of our general partner since March 2017. He has also served as Diamondback's Senior Vice President-Land since March 2017. Prior to his positions with us and Diamondback, Mr. Hawkins was an independent consultant for land activities from July 2016 to February 2017. Mr. Hawkins has over 38 years of experience in the oil and gas industry. Mr. Hawkins spent seven years with Oasis Petroleum Inc., an oil and gas company, as its Senior Vice President of Land or in related capacities from March 2009 to June 2016. Until February 2009, Mr. Hawkins spent 31 years with ConocoPhillips and Burlington Resources (which ConocoPhillips acquired in 2006). During that time, Mr. Hawkins held various operations and managerial positions in the land, marketing, planning and the corporate acquisitions and divestitures groups. Mr. Hawkins has worked in several major regions in the continental United States, including the San Juan Basin, the Williston Basin and the Austin Chalk/Wilcox Trends in South Texas. Mr. Hawkins holds a Bachelor of Business Administration in Finance from the University of Texas at El Paso.
Randall J. Holder. Mr. HolderZmigrosky has served as Executive Vice President, General Counsel and Secretary of our general partnerGeneral Partner since February 2017 and served as Vice President, General Counsel and Secretary from2019. Since February 2014 to February 2017. He2023, Mr. Zmigrosky has also served as Diamondback'sExecutive Vice President, Chief Legal and Administrative Officer and Secretary of Diamondback. From February 2019 to February 2023, he served as Diamondback’s Executive Vice President, General Counsel and Secretary since February 2017,Secretary. Before joining us and servedDiamondback, Mr. Zmigrosky was in the private practice of law, most recently as its Vice President, General Counsel and Secretarya partner in the corporate section of Akin Gump Strauss Hauer & Feld LLP from October 2012 to February 2017, and as General Counsel and Vice President from November 2011 to October 2012. Prior to his positions with us and Diamondback, Mr. Holder served as General Counsel and Vice President for Great White Energy Services LLC, an oilfield services company, from November 2008 to November 2011. He served as Executive Vice President and General Counsel for R.L. Hudson and Company, a supplier of molded rubber and plastic components, from February 2007 to October 2008. He was in private practice of law and a member of Holder Betz LLC from February 2005 to February 2007. Mr. Holder served as Vice President and Assistant General Counsel for Dollar Thrifty Automotive Group, a vehicle rental company, from January 2003 to February 2005 and as Vice President and General Counsel for Thrifty Rent-A-Car System, Inc., a vehicle rental company, from September 1996 to December 2002. He also served as Vice President and General Counsel for Pentastar Transportation Group, Inc. from November 1992 to September 1996, which was
wholly-owned by Chrysler Corporation. Mr. Holder started his legal career with Tenneco Oil Company2019, where he served asworked extensively with Diamondback and its subsidiaries. Mr. Zmigrosky received a Division Attorney providing legal services to the company's mid-continent division for ten years. He receivedBachelor of Science in Management degree in finance from Tulane University and a Juris Doctorate degree from Oklahoma City University.Southern Methodist University Dedman School of Law.
Paul S. Molnar. Mr. Molnar has served as our Executive Vice President-Exploration and Business Development since January 2017 and served as our Vice President-Geoscience from February 2014 to January 2017. Mr. Molnar joined Diamondback in August 2011 as Vice President-Geoscience and was promoted to Executive Vice President-Exploration and Business Development effective January 1, 2017. Prior to joining us and Diamondback, Mr. Molnar served as a Senior District Geologist for Samson Investment Company, an oil and gas exploration company, from March 2011 to August 2011. Mr. Molnar worked as an asset supervisor and geosciences supervisor for ConocoPhillips Company from April 2006 to February 2011. Mr. Molnar also worked as a geologic advisor for Burlington Resources, an oil and gas exploration company, from December 1996 to March 2006. Mr. Molnar has over 31 years of industry experience. Mr. Molnar received a Bachelor of Science degree in Geoscience from the State University of New York, College at Buffalo and a Master of Science degree in Geology from the State University of New York, University at Buffalo.
Steven E. West.Mr. West has served as Chairman of the Board and as a director of our General Partner since February 2014. Mr. West served as a director and Executive Chairman of our general partner since February 2014.the Board of the General Partner of Rattler from May 2019 to August 2022. Mr. West has also served as a director of Diamondback since December 2011 and as its Chairman of the Board sincefrom October 2012.2012 to February 2022. He served as Diamondback's Chief Executive Officer from January 1, 2009 to December 31, 2011. From January 2011 until December 2016, Mr. West was a partner at Wexford Capital LP, focusing on Wexford'sWexford’s private equity energy investments. From August 2006 until December 2010, Mr. West served as senior portfolio advisor at Wexford. From August 2003 until August 2006, he was the chief financial officer of Sunterra Corporation, a former Wexford portfolio company. From December 1993 until July 2003, Mr. West held senior financial positions at Coast Asset Management and IndyMac Bank. Prior to that, he worked at First Nationwide Bank, Lehman Brothers and Peat Marwick Mitchell & Co., the predecessor of KPMG LLP. Mr. West holdsearned a Bachelor of Science degree in Accounting from California State University, Chico.
We believe that Mr. West’s background in finance, accounting and private equity energy investments, as well as his executive management skills developed as part of his career with Wexford, its portfolio companies and other financial institutions qualify him to serve on the board of directors of our general partner.General Partner. In particular, we believe Mr. West’s strengths in the following core competencies provide value to our board of directors: Corporate Governance; Finance/Capital Markets; Financial Reporting/Accounting Experience; Industry Background; Executive Experience; Executive Compensation; and Risk Management.
W. Wesley Perry. Mr. Perry has been a member of the board of directors of our general partnerGeneral Partner since June 2014. Mr. Perry has served as a director of Genie Energy Ltd., an independent retail energy provider, since October 2011, currently serves as the chair of its audit committee and a member of its compensation, nominating, corporate governance and technology committees and has served as the chairman of the board of directors of Genie Energy International Corporation since September 2009. Mr. Perry also serves as manager of PBEX, LLC, an oil and gas exploration and development company, a position he has held since July 2012. Mr. Perry has served as manager of S.E.S. Investments, Ltd., an oil and gas investment company, since 1985. He has served as Chief Executive Officer of E.G.L. Resources, Inc., an oil and gas production company, sincefrom July 2008 until December 2019 and served as its President from 2003 to July 2008. Mr. Perry was a director of UTG, Inc., an insurance holding company, from 2001 to 2013 and served on its Audit Committee. Mr. Perry served on the Midland City Council from 2002 to 2008 and as Mayor of Midland from 2008 through 2014. He is the PresidentChairman of the Milagros Foundation and a trustee of the Abell-Hangar Foundation. He has a Bachelor of Science degree in Engineering from the University of Oklahoma.
We believe that Mr. Perry’s extensive experience in the oil and gas industry and his strong financial background qualify him to serve on the board of directors of our general partner.General Partner.
Spencer D. Armour.Mr. Armour has been a member of the board of directors of our general partnerGeneral Partner since July 2017.Mr. Armour has over 30 years of executive and entrepreneurial experience in the energy services industry. Mr. Armour currently serveshas served as a partner of Geneses Investments since February 2019. He served as President of PT Petroleum LLC in Midland, Texas.Texas from March 2013 until January 2019. He was the Vice President of Corporate Development for Basic Energy Services, Inc. from 2007 to 2008, which acquired Sledge Drilling Corp., a company Mr. Armour co-founded and served as Chief Executive Officer for from 2005 to 2006. From 1998 through 2005, he served as Executive Vice President of Patterson-UTI Energy, Inc., which acquired Lone Star Mud, Inc., a company Mr. Armour founded and served as President of from 1986 to 1997. Mr. Armour has served as a director of ProPetro Holding Corp. since February 2013.2013 and as a director of CES Energy since December 2018. Mr. Armour also served on the Patterson-UTI Board of Directors from 1999 through 2001. Mr. Armour received a Bachelor of Science in Economics from the University of Houston and was appointed to the University of Houston System Board of Regents in 2011 by former Texas Governor Rick Perry.
We believe that Mr. Armour’s extensive experience in the oil and gas industry qualify him to serve on the board of directors of our general partner.General Partner.
Michael L. Hollis. Mr. Hollis has been a member of the board of directors of our general partner since June 2014. He has served as Chief Operating Officer of Diamondback since July 2015 and before that served as Vice President-Drilling of
Diamondback since September 2011. Prior to his positions with Diamondback, Mr. Hollis served in various roles, most recently as drilling manager at Chesapeake Energy Corporation, an oil and gas exploration company, from June 2006 to September 2011. He worked for ConocoPhillips Company as a senior drilling engineer from January 2002 to June 2006 and as a process engineer from 2001 to 2003. Mr. Hollis also worked as a production engineer for Burlington Resources from 1998 to 2001 as well as from June 2003 to January 2004. Mr. Hollis received his Bachelor of Science degree in Chemical Engineering from Louisiana State University.
We believe that Mr. Hollis’ extensive experience in the oil and gas industry, including at Diamondback, qualifies him to serve on the board of directors of our general partner.
James L. Rubin.Mr. Rubin has been a member of the board of directors of our general partnerGeneral Partner since June 2014. He hasMr. Rubin is currently the Head of Commodity Equities at BTG Pactual Asset Management US. From 2012 to 2022, Mr. Rubin served as a partner, at Wexford since 2012 and currently serves as Portfolio Manager and Co-Head of Equities and as a member of Wexford’sWexford Capital’s hedge fund investment committee. From 2006 to 2012, he served as an analyst and later as Vice President, focusing on Wexford’s public and private energy investments. investments. Mr. Rubin graduated cum laude from Yale University with a Bachelor of Arts degree with honors in political science and economics.
We believe that Mr. Rubin’s strong financial background qualifies him to serve on the board of directors of our general partner.General Partner.
Rosalind Redfern Grover. Ms. GroverFrank C. Hu. Mr. Hu has been a director of our general partner since April 2022. Mr. Hu most recently served as an investment analyst and Vice President of Capital World Investors, an investment group in the Capital Group Companies, Inc., from 2003 to 2017. He previously served as a manager of project finance in the corporate treasury department at Unocal Corporation from 2002 to 2003, and as a global energy practice consultant at McKinsey & Company from 2000 to 2002. Prior to joining McKinsey, Mr. Hu served in various roles at Atlantic Richfield Company (ARCO) from 1989 to 2000, including as Vice President of Downstream Operations and Business Development from 1998 to 2000. Mr. Hu has served as a member of the board of directors of our general partnerEQT Corporation (NYSE: EQT) since December 2014. Ms. Grover servedOctober 2021, where he also serves on the audit committee, special hedging transaction committee and public policy and corporate responsibility committee. Mr. Hu also currently serves as Chairmanan advisory board member for the Geology & Planetary Science Division at the California Institute of the Board of Flag-Redfern Oil Company until the company was sold to Kerr-McGee Corporation in 1988. She has served as the President of Redfern Enterprises, Inc., an independent oil and gas producer, since 1989 and as the Chief Executive Officer of Redfern & Grover Resources, LLC, an independent oil and gas producer, since 2014. Ms. Grover holds Bachelors and Masters degrees from the University of Arizona.Technology.
We believe that Ms. Grover’s extensiveMr. Hu’s strong executive management experience, robust experience in the finance and oil and gas industry, including with oilindustries and gas partnerships,diverse background qualifies herhim to serve on the board of directors of our general partner.General Partner.
Director Independence and Diversity
The board of directors of our general partnerGeneral Partner has sevensix directors, threefive of whom are independent as defined under the independence standards established by Nasdaq and the Exchange Act. Steven E. West, W. Wesley Perry, James L. Rubin, Spencer D. Armour and Rosalind Redfern GroverFrank C. Hu serve as the independent members of the board of directors of our general partner.General Partner. Although a majority of the board of directors of our General Partner is independent, Nasdaq does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partnerGeneral Partner, disclose details regarding board diversity or to establish a compensation committee or a nominating and corporate governance committee. However, our general partnerGeneral Partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by Nasdaq and the Exchange Act.
The board of directors of our General Partner has established an independent audit committee and a conflicts committee, discussed in more detail below, and has diverse representatives on its board, including a female director.
Board Leadership Structure and Role in Risk Oversight
Leadership of our general partner’sGeneral Partner’s board of directors is vested in the Executive Chairman.chairman of the board. Steven E. West serves as the Executive Chairmanchairman of the board of directors of our general partnerGeneral Partner and as Chairmana director of Diamondback. Mr. West was also the chairman of the board of Diamondback.Diamondback from October 2012 to February 2022, when he was succeeded in that role by Mr. Stice. Our general partner’sGeneral Partner’s board of directors has determined that the combinedMr. West’s roles of Executive Chairmanchairman of the board of directors of our general partnerGeneral Partner and Chairman of the boarda director of Diamondback allows the board of directors to take advantage of the leadership skills of Mr. West and that Mr. West’s in-depth knowledge of, and experience in, our business, history, structure and organization facilitates timely communications between the board of directors of Diamondback and the board of directors of our general partner.General Partner.
As a partnership engaged in the oil and natural gas industry, we face a number of risks, including risks associated with supply of and demand for oil and natural gas, volatility of oil and natural gas prices, exploring for, developing, producing and delivering oil and natural gas, declining production, environmental and other government regulations and taxes, extreme weather conditions that can affect oil and natural gas operations over a wide area, adequacy of our insurance coverage, political instability or armed conflict in oil and natural gas producing regions and the overall economic environment. Management is responsible for the day-to-day management of risks we face as a partnership, while the board of directors of our general partner,General Partner, as a whole and through its committees, has responsibility for the oversight of risk management. In its risk oversight role, the board of directors of our general partnerGeneral Partner has the responsibility to satisfy itself that the risk management processes designed and implemented by management are adequate and functioning as designed.
The board of directors of our general partnerGeneral Partner believes that full and open communication between management and the board is essential for effective risk management and oversight. The Executive Chairmanchairman of the board of directors of our general
partnerGeneral Partner meets regularly with the Chief Executive Officer and the Chief Financial Officer to discuss strategy and risks facing the partnership. Executive officers may attend the board meetings of our general partnerGeneral Partner and are available to address any questions or concerns raised by the board on risk management-related and any other matters. Other members of our management team periodically attend the board meetings or are otherwise available to confer with the board to the extent their expertise is required to address risk management matters. Periodically, the board of directors of our general partnerGeneral Partner receives presentations from senior management on strategic matters involving our operations. During such meetings, the board also discusses strategies, key challenges, and risks and opportunities for the partnership with senior management.
While the board of directors of our general partnerGeneral Partner is ultimately responsible for risk oversight at the partnership, its two committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. The audit committee assists the board in fulfilling its oversight responsibilities with respect to risk management in the areas of financial reporting, internal controls and compliance with legal and regulatory requirements, and discusses policies with respect to risk assessment and risk management. The conflicts committee assists the board in fulfilling its oversight responsibilities with respect to specific matters that the board believes may involve conflicts of interest.
Meetings of the Board of Directors
During 2017,2022, the board of directors of our general partnerGeneral Partner met threefive times. Each director attended at least 86%80% of thethe total meetings of the board and the committees of the board on which he or she served that occurred during 2017.2022.
Communications with Directors
Unitholders or interested parties may communicate directly with the board of directors of our general partner,General Partner, any committee of the board, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: c/o Secretary, Viper Energy Partners LP, 500 West Texas, Suite 1200,100, Midland, Texas. Communications are distributed to the board of directors, committee of the board of directors, or director as appropriate, depending on the facts and circumstances outlined in the communication. Commercial solicitations or communications will not be forwarded.
Committees of the Board of Directors
The board of directors of our general partnerGeneral Partner has an audit committee and a conflicts committee. We do not have a compensation committee or a nominating and corporate governance committee. Rather, the board of directors of our general partnerGeneral Partner has authority over compensation matters and nominating and corporate governance matters.
Audit Committee
The audit committee assists the board of directors of our General Partner in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the audit committee and our management, as necessary. The audit committee met four times during 2017. The audit committee has adopted a charter, which is available on our website under the “corporate governance” section at http://ir.viperenergy.com.
W. Wesley Perry, Spencer D. Armour and Rosalind Redfern GroverFrank C. Hu currently serve on the audit committee, and Mr. Perry serves as the chairman. The board orof directors of our general partnerGeneral Partner has determined that each of W. Wesley Perry, Spencer D. Armour and Rosalind Redfern GroverFrank C. Hu meet the independence and experience standards established by the Nasdaq and the Exchange Act and that each of Mr. Perry and Mr. Hu is considered an “audit committee financial expert” as defined under SEC rules.
Conflicts Committee
Our conflicts committee reviews specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is in our best interest. The members of the conflicts committee may not be officers or employees of our general partnerGeneral Partner or directors, officers or employees of its affiliates, including Diamondback, and must meet the independence standards established by Nasdaq and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership
agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partnerGeneral Partner of any duties it may owe us or our unitholders. W. Wesley Perry, Spencer D. Armour and Rosalind Redfern GroverFrank C. Hu are the members of the conflicts committee, which was formed in January 2015.committee.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act, to file reports of beneficial ownership and reports of changes in beneficial ownership of such securities with the SEC. Directors, officers and greater than 10% unitholders are required by SEC regulations to furnish to us copies of all Section 16(a) forms they file with the SEC.
Based solely on a review of the copies of reports on Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from the executive officers and directors of our general partner, we believe that during the year ended December 31, 2017 the officers and directors of our general partner and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a).
Corporate Governance
The board of directors of our general partnerGeneral Partner has adopted a Code of Business Conduct and Ethics, or Code of Ethics, that applies to all employees, including executive officers, and directors.directors of our General Partner. Amendments to or waivers from the Code of Ethics will be disclosed on our website. We have also made the Code of Ethics available on our website under the “Corporate Governance” section at http://ir.viperenergy.com.
Reimbursement of Expenses of our General Partner
Our partnership agreement requires us to reimburse our general partnerGeneral Partner and its affiliates, including Diamondback, for all expenses they incur and payments they make on our behalf in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partnerGeneral Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partnerGeneral Partner by its affiliates. Our partnership agreement provides that our general partnerGeneral Partner will determine the expenses that are allocable to us.
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
As is commonly the case for publicly traded limited partnerships, we have no officers. Our general partnerGeneral Partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and executive officers make decisions on our behalf. Our general partner’sGeneral Partner’s executive officers are employed and compensated by Diamondback or a subsidiary of Diamondback. All of the executive officers that are responsible for managing our day-to-day affairs are also current executive officers of Diamondback.
All of the executive officers of our general partnerGeneral Partner have responsibilities to both us and Diamondback and allocate their time between managing our business and managing the businessbusinesses of Diamondback. Since all of these executive officers are employed by Diamondback or one of its subsidiaries, the responsibility and authority for compensation-related decisions for them resides with Diamondback’s compensation committee. Diamondback has the ultimate decision-making authority with respect to the total compensation of the executive officers that are employed by Diamondback including, subject to the terms of the partnership agreement, the portion of that compensation that is allocated to us pursuant to Diamondback’s allocation methodology. Any such compensation decisions are not subject to any approvals by the board of directors of our general partnerGeneral Partner or any committees thereof. However, all determinations with respect to awards that are made to executive officers, key employees and non-employee directors under the LTIP are made by the board of directors of our general partner.General Partner. Please see the description of the LTIP below under the heading “Long-Term Incentive Plan.”
The executive officers of our general partner,General Partner, as well as the employees of Diamondback who provide services to us, may participate in employee benefit plans and arrangements sponsored by Diamondback, including plans that may be established in the future. Certain of our general partner’sGeneral Partner’s executive officers and employees and certain employees of Diamondback who provide services to us currently hold grants under Diamondback’s equity incentive plans.plan. Except with respect to any awards that may be granted under the LTIP, the executive officers of our general partnerGeneral Partner do not receive separate amounts of compensation in relation to the services they provide to us. In accordance with the terms of our partnership agreement, we reimburse Diamondback for
compensation related expenses attributable to the portion of the executive’s time dedicated to providing services to us. Although we bear an allocated portion of Diamondback’s costs of providing compensation and benefits to employees who serve as executive officers of our general partner,General Partner, we have no control over such costs and did not establish and do not direct the compensation policies or practices of Diamondback. Except with respect to awards granted under the LTIP, compensation paid or awarded by us in 20172022 consisted only of the portion of compensation paid by Diamondback that is allocated to us and our general partnerGeneral Partner pursuant to Diamondback’s allocation methodology and subject to the terms of the partnership agreement.
A full discussion of the compensation programs for Diamondback’s executive officers and the policies and philosophy of the compensation committee of Diamondback’s board of directors will be set forth in Diamondback’s 20182023 proxy statement under the heading “Compensation Discussion and Analysis.” Specifically, compensation paid directly by us through our LTIP or indirectly by us through reimbursement pursuant to our partnership agreement will be included in the amounts set forth in certain of the tables set forthincluded in Diamondback’s 20182023 proxy statement, with awards outstanding pursuant to our LTIP separately identified.
Long-Term Incentive Plan
In order to incentivize our management and directors to continue to grow our business, the board of directors of our general partnerGeneral Partner adopted the LTIP for employees, officers, consultants and directors of our general partnerGeneral Partner and any of its affiliates, including Diamondback, who perform services for us.
The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. The 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 (collectively, “awards”). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long-term performance. Any awards that are made under the LTIP will be approved by the board of directors of our general partnerGeneral Partner or a committee thereof that may be established for such purpose. We will be responsible for the cost of awards granted under the LTIP.
During 2022, our General Partner made grants under the LTIP of (a) phantom units to the non-employee directors of our general partnerGeneral Partner (see “Director Compensation” below for information regarding those awards) and (b) at. No grants under the time of our IPO, an aggregate of 2,500,000 unit optionsLTIP were made to the executive officers of our general partner. Each unit option entitled the recipient to purchase one of our common units. In accordance with the LTIP, the exercise price of the unit options granted could not be less than the market value of our common units on the date of grant. The unit options had an exercise price of $26.00 per unit, which was the price to the publicGeneral Partner in our IPO. A third of the unit options vested each year on the anniversary of their grant. All of the unit options automatically expired unexercised on December 31, 2017.2022.
Administration
The LTIP is administered by the board of directors of our general partnerGeneral Partner pursuant to its terms and all applicable state, federal, or other rules or laws. The board of directors of our general partnerGeneral Partner has the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP.
Change in Control
Upon a “change in control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the committee deems appropriate to reflect the change in control.
Termination of Employment or Service
The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors of our General Partner will be determined by the committeeplan administrator in the terms of the relevant award agreement.
Compensation Report
Neither we nor the board of directors of our general partnerGeneral Partner has a compensation committee. The board of directors of our general partnerGeneral Partner has reviewed and discussed the Compensation Discussion and Analysis set forth above. Based on this review and discussion, the board of directors of our general partnerGeneral Partner has approved the Compensation Discussion and Analysis for inclusion in this Annual Report.
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| The Board of Directors of Viper Energy Partners GP LLC |
| Travis D. Stice |
| Steven E. West |
| W. Wesley Perry |
| Spencer D. Armour |
Michael L. Hollis |
| James L. Rubin |
Rosalind Redfern Grover |
| Frank C. Hu |
Director Compensation
TheAny executive officersofficer or employeesemployee of our general partnerGeneral Partner or of Diamondback who also serveserves as directorsa director of our general partner doGeneral Partner does not receive additional compensation for theirhis or her service as a director of our general partner.General Partner. Directors of our general partnerGeneral Partner who are not executive officers or employees of our general partnerGeneral Partner or of Diamondback receive compensation as “non-employee directors” as set by our general partner’sGeneral Partner’s board of directors.
Prior to July 1, 2017, eachEach non-employee director receivedreceives a compensation package that consistedconsists of an annual cash retainer of $47,500$60,000 plus an additional annual payment of $15,000 for the chairperson and $10,000 for each other member of the audit committee and $10,000 for the chairperson and $5,000 for each other member of each other committee. Our directors also received a fee of $1,000 for attending each in-person meeting of the board of directors or its committees and $500 for attending each telephone meeting. Effective July 1, 2017, the board of directors approved a change that increased the annual cash retainer to $60,000 and eliminated all meeting fees.
In addition, effective July 1, 2017, each non-employee director receives an equity award of phantom units under the LTIP granted annually at the close of business on July 10th of each year or, if not a business day, the first business day thereafter; provided however, that the grant date for 2017 was July 1, 2017.thereafter. The number of phantom units awarded is calculated by dividing $100,000 by the average closing price of our common units for the five trading days immediately proceedingpreceding the date of grant. The awards vest on the first anniversary of the grategrant date. Our directors are also reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees.
Each member of the board of directors of our general partnerGeneral Partner is indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law.
The following table sets forth the aggregate dollar amount of all fees paidearned to each of the non-employee directors of our general partnerGeneral Partner during 20172022 for their services on the board:
| | | | | | | | | | | | | | | | | | | | |
| Name | | Fees Earned or Paid in cash(a) | | Unit Awards(b) | | Total |
Spencer D. Armour(c)(d) | | $ | 75,000 | | | $ | 100,254 | | | $ | 175,254 | |
Rosalind Redfern Grover(c)(e) | | $ | 75,000 | | | $ | 100,254 | | | $ | 175,254 | |
Frank C. Hu(d) | | $ | 43,350 | | | $ | 100,254 | | | $ | 143,604 | |
W. Wesley Perry(c)(d) | | $ | 85,000 | | | $ | 100,254 | | | $ | 185,254 | |
James L. Rubin(c)(d) | | $ | 60,000 | | | $ | 100,254 | | | $ | 160,254 | |
Steven E. West(c)(d) | | $ | 60,000 | | | $ | 100,254 | | | $ | 160,254 | |
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| | | | | | | | | |
| Name | Fees Earned or Paid in cash (a) | Unit Awards (b) | Total |
| Spencer D. Armour (e) | $ | 72,875 |
| $ | 107,627 |
| $ | 180,502 |
|
| Rosalind Redfern Grover (c)(d)(e) | 75,375 |
| 107,627 |
| 183,002 |
|
| W. Wesley Perry (c)(d)(e) | 85,375 |
| 107,627 |
| 193,002 |
|
| James L. Rubin (c)(d)(e) | 58,375 |
| 107,627 |
| 166,002 |
|
| Steven E. West (c)(d)(e) | 58,875 |
| 107,627 |
| 166,502 |
|
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(a) | This column reflects the value of a director’s annual retainer, as well as the additional payments for committee membership, committee chairmanship and meeting attendance. |
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(b) | The amount in this column represents the aggregate grant date fair value of phantom units granted in the fiscal year calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, “Compensation - Stock Compensation.” |
(b)The amount in this column represents the aggregate grant date fair value of phantom units granted in the fiscal year calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, “Compensation - Stock Compensation.”
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(c) | Each of Ms. Grover and Messrs. Perry, Rubin and West received a grant of 4,938 phantom units on August 27, 2015, of which 1,646 vested and settled on the date of grant, 1,646 vested and settled on June 17, 2016 and 1,646 vested and settled on June 17, 2017, pursuant to the LTIP, with each unit having a grant date fair value of $15.48. Each phantom unit is(c)Each of Ms. Grover and Messrs. Armour, Perry, Rubin and West received a grant of 5,513 phantom units on July 12, 2021, which vested and settled on July 12, 2022, pursuant to the LTIP, with each unit having a grant date fair value of $18.29. Each phantom unit was the economic equivalent of one of our common units. |
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(d) | Each of Ms. Grover and Messrs. Perry, Rubin and West received a grant of 5,424 phantom units on August 24, 2016, of which 1,808 vested and settled on the date of grant and 1,808 vested and settled on June 17, 2017, pursuant to the LTIP, with each unit having a grant date fair value of $16.57. Each of Ms. Grover’s and Messrs. Perry’s, Rubin’s and West’s remaining 1,808 phantom units will vest and settle on June 17, 2018. Each phantom unit is the economic equivalent of one of our common units. |
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(e) | Each of Ms. Grover and Messrs. Armour, Perry, Rubin and West received a grant of 6,414 phantom units on July 25, 2017, which will vest and settle on July 1, 2018, pursuant to the LTIP, with each unit having a grant date fair value of $16.78. Each phantom unit is the economic equivalent of one of our common units. |
Messrs. Stice and Hollis are both directors of our general partner, but common units.
(d)Each of Messrs. Armour, Hu, Perry, Rubin and West received a grant of 3,907 phantom units on July 11, 2022, which will vest and settle on July 11, 2023, pursuant to the LTIP, with each unit having a grant date fair value of $25.66. Each phantom unit is the economic equivalent of one of our common units.
(e)Ms. Grover received a grant of 3,907 phantom units on July 11, 2022, with each unit having a grant date fair value of $25.66. Ms. Grover retired from the board effective December 31, 2022. Prior to her retirement, Ms. Grover also served on the board’s audit committee and conflicts committee. In connection with Ms. Grover’s retirement, the vesting provisions of her phantom units were accelerated and subsequently became vested in January 2023. Each phantom unit was the economic equivalent of one of our common units.
Mr. Stice is a director of our General Partner, but is also an executive officer of our general partnerGeneral Partner and both Messrs.Mr. Stice and Hollis are employeesis an employee of Diamondback E&P LLC. Each of Messrs.Mr. Stice and Hollis has received awards pursuant to the LTIP for his service as an executive officer or employee, respectively, and unrelated to his service as directors.director. These awards are reflected in the tables contained in Diamondback’s 20182023 proxy statement under the heading “Compensation Discussion and Analysis.”
Compensation Committee Interlocks and Insider Participation
As previously noted, our general partner’sGeneral Partner’s board of directors is not required to maintain, and does not maintain, a separate compensation committee. Mr. Hollis, a director of our general partner, is also an executive officer of Diamondback. Mr. Stice, a director and executive officer of our general partner,General Partner, is also a director and executive officer of Diamondback. However, all compensation decisions with respect to Messrs.Mr. Stice and Hollis are made by Diamondback and Messrs.Mr. Stice and Hollis dodoes not receive any compensation directly from us or our general partnerGeneral Partner except for awards under our LTIP. As described in “–“—Compensation Discussion and Analysis,” decisions regarding the compensation of our general partner’sGeneral Partner’s executive officers are made by Diamondback. Please read “Items“Items 1 and 2. Business and Properties–Our Relationship with Diamondback”Diamondback” and “Item“Item 13. Certain Relationships and Related Transactions, and Director Independence”Independence” for more information about relationships among us, our general partnerGeneral Partner and Diamondback.
Compensation Policies and Practices as They Relate to Risk Management
We do not have any employees. We are managed and operated by the directors and officers of our general partnerGeneral Partner and employees of Diamondback perform services on our behalf. Please read “–“—Compensation Discussion and Analysis” and “Items“Items 1 and 2. Business and Properties–Our Relationship with Diamondback”Diamondback” for more information about this arrangement. For an analysis of any risks arising from Diamondback’s compensation policies and practices, please read Diamondback’s 20182023 proxy statement. We have made awards of unit options subject to time-based vesting under our LTIP, which we believe drive a long-term perspective and which we believe make it less likely that executive officers will take unreasonable risks because the unit options retain value even in a depressed market.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
Holdings of Officers and Directors
The following table presents information regarding the beneficial ownership of our common units as of January 25, 2018February 1, 2023 by:
•our general partner;General Partner;
•each of our general partner’sGeneral Partner’s directors and executive officers; and
each unitholder known by us to beneficially hold 5% or more of our common units; and
•all of our general partner’sGeneral Partner’s directors and executive officers as a group.
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| Name of Beneficial Owner | | Common Units Beneficially Owned(1) | | Percentage of Common Units Beneficially Owned | | |
| Diamondback Energy, Inc. | | 731,500 | | | 1.0% | | |
| Viper Energy Partners GP LLC | | — | | | — | | |
Travis D. Stice(2) | | 106,169 | | | * | | |
| Kaes Van't Hof | | 35,362 | | | * | | |
| Teresa L. Dick | | 11,540 | | | * | | |
| | | | | | |
| Thomas F. Hawkins | | — | | | — | | |
| Matt Zmigrosky | | 4,253 | | | * | | |
Steven E. West(3) | | 18,290 | | | * | | |
W. Wesley Perry(3) | | 64,245 | | | * | | |
Spencer D. Armour(3) | | 28,217 | | | * | | |
James L. Rubin(4) | | — | | | — | | |
| | | | | | |
Frank C. Hu(3) | | — | | | * | | |
| All directors and executive officers as a group (10 persons) | | 268,076 | | | * | | |
* Less than 1%
(1)Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, (i) common units subject to options held by that person that are exercisable as of February 1, 2023 and (ii) common units subject to options or phantom units held by that person that are exercisable or vesting within 60 days of February 1, 2023 are all deemed to be beneficially owned. These common units, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of common units beneficially owned is based on 72,858,184 common units outstanding as of February 1, 2023. Unless otherwise indicated, all amounts exclude common units issuable upon the exercise of outstanding options and vesting of phantom units that are not exercisable and/or vested as of February 1, 2023 or within 60 days of February 1, 2023. Unless otherwise noted, the address for each beneficial owner listed below is 500 West Texas Avenue, Suite 100, Midland, Texas 79701. Except as noted, each unitholder in the above table is believed to have sole voting and sole investment power with respect to the units beneficially held.
(2)All of these units are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its General Partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager.
(3)Excludes 3,907 phantom units that are scheduled to vest on July 11, 2023.
(4)Excludes 45,245 common units (representing vested phantom units previously granted to Mr. Rubin) and 3,907 phantom units that are scheduled to vest on July 11, 2023, all of which have been assigned by Mr. Rubin to Wexford under the terms of his previous employment with Wexford.
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| Name of Beneficial Owner | Common Units Beneficially Owned(1) | Percentage of Common Units Beneficially Owned |
Diamondback Energy, Inc.(2) | 73,150,000 |
| 64% |
| Viper Energy Partners GP LLC | — |
| — |
Travis D. Stice(3) | 68,311 |
| * |
Kaes Van't Hof(4) | 16,026 |
| * |
Teresa L. Dick(5) | 11,540 |
| * |
Russell Pantermuehl(5) | 48,487 |
| * |
| Thomas F. Hawkins | — |
| — |
Randall J. Holder(5) | 14,622 |
| * |
Paul S. Molnar(5) | 18,487 |
| * |
Steven E. West (6) | 48,265 |
| — |
W. Wesley Perry (7) | 34,220 |
| * |
Spencer D. Armour(8) | — |
| * |
Michael L. Hollis (9) | 78,461 |
| * |
James L. Rubin (10) | — |
| — |
Rosalind Redfern Grover (7) | 8,554 |
| * |
| All directors and executive officers as a group (13 persons) | 346,973 |
| * |
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(1) | Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, (i) common units subject to options held by that person that are exercisable as of January 25, 2018 and (ii) common units subject to options or phantom units held by that person that are exercisable or vesting within 60 days of January 25, 2018 are all deemed to be beneficially owned. These common units, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of common units beneficially owned is based on 113,882,045 common units outstanding as of January 25, 2018. Unless otherwise indicated, all amounts exclude common units issuable upon the exercise of outstanding options and vesting of phantom units that are not exercisable and/or vested as of January 25, 2018 or within 60 days of January 25, 2018. Unless otherwise noted, the address for each beneficial owner listed below is 500 West Texas Avenue, Suite 1200, Midland, Texas 79701. |
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(2) | Diamondback Energy, Inc. is a publicly traded company. The directors of Diamondback are Travis D. Stice, Steven E. West, Michael P. Cross, David L. Houston and Mark L. Plaumann. |
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(3) | All of these units or options, as applicable, are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its general partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager. Excludes 1,250,000 unit options that expired as of December 31, 2017. |
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(4) | Includes (i) 7,600 unit options granted to Mr. Van’t Hof, which vested on January 1, 2018, and will be automatically exercisable upon the earlier to occur of December 31, 2018 and the occurrence of a change in control and (ii) 5,346 phantom units, which will vest on February 16, 2018. Excludes 10,692 phantom units, which will vest in two equal installments beginning on February 16, 2019. |
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(5) | Excludes 125,000, 250,000, 125,000 and 125,000 unit options held by Ms. Dick, Mr. Pantermuehl, Mr. Holder and Mr. Molnar, respectively, all of which expired as of December 31, 2017. |
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(6) | Excludes 1,808 unvested phantom units that will vest on June 17, 2018 and 6,414 unvested phantom units that will vest on July 1, 2018. Also excludes 11,766 common units (representing vested phantom units previously granted to Mr. West), all of which have been assigned by Mr. West to Wexford under the terms of his previous employment with Wexford. Mr. West retired from Wexford as of December 31, 2016. |
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(7) | Excludes 1,808 unvested phantom units that will vest on June 17, 2018 and 6,414 unvested phantom units that will vest on July 1, 2018. |
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(8) | Excludes 6,414 unvested phantom units that will vest on July 1, 2018. |
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(9) | All of the units or options, as applicable, are held by MBH Investments, Ltd., which is managed by MBH Financial, LLC, its general partner. Mr. Hollis, his spouse and the Hollis 2014 Irrevocable Trust hold 100% of the membership interests in MBH Financial, LLC, of which Mr. Hollis is the manager. Excludes 250,000 unit options that expired as of December 31, 2017. |
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(10) | Excludes 15,220 common units (representing vested phantom units previously granted to such Mr. Rubin), 1,808 unvested phantom units that will vest on June 17, 2018 and 6,414 unvested phantom units that will vest on July 1, 2018, all of which have been assigned by Mr. Rubin to Wexford under the terms of his employment with Wexford. |
The following table sets forth, as of January 25, 2018,February 1, 2023, the number of shares of common stock of Diamondback beneficially owned by each of the directors and executive officers of our general partnerGeneral Partner and all directors and executive officers of our general partnerGeneral Partner as a group.
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| | Shares of Diamondback Common Stock Beneficially Owned(1) |
| Name of Beneficial Owner | | Amount and Nature of Beneficial Ownership | | Percentage of
Class |
Travis D. Stice(2) | 189,932 |
418,717 | | * |
Kaes Van't Hof(3) | 2,528 |
93,576 | | * |
Teresa L. Dick(4) | 18,810 |
58,321 | | * |
Russell PantermuehlThomas F. Hawkins(5)
| 55,066 |
14,952 | | * |
Thomas F. HawkinsMatt Zmigrosky(6)
| 2,600 |
20,539 | | * |
Randall J. Holder(7)
| 4,955 |
| * |
Paul S. Molnar(8)
| 28,663 |
| * |
Steven E. West(9)(7) | 3,379 |
10,299 | | | * |
| W. Wesley Perry | — |
— | | | — |
| Spencer D. Armour | — |
— | | | — |
Michael L. Hollis(10)
| 56,470 |
| * |
| James L. Rubin | — |
— | | | — |
Rosalind Redfern GroverFrank C. Hu | — |
— | | — |
All directors and executive officers as a group (13(10 persons) | 362,403 |
616,404 | | * |
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(1) | Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, (i) shares of common stock subject to options held by that person that are exercisable as of January 25, 2018 and (ii) shares of common stock subject to options or restricted stock units held by that person that are exercisable or vesting within 60 days of January 25, 2018, are all deemed to be beneficially owned. These shares, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of shares beneficially owned is based on 98,167,289 shares of common stock outstanding as of January 25, 2018. Unless otherwise indicated, all amounts exclude shares issuable upon the exercise of outstanding options and vesting of restricted stock units that are not exercisable and/or vested as of January 25, 2018 or within 60 days of January 25, 2018. |
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(2) | All of these shares are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its general partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager. Excludes 7,410 restricted stock units, which will vest on February 16, 2019. Also excludes (i) 180,338* Less than 1% (1)Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, (i) shares of common stock subject to options held by that person that are exercisable as of February 1, 2023 and (ii) shares of common stock subject to options or restricted stock units held by that person that are exercisable or vesting within 60 days of February 1, 2023, are all deemed to be beneficially owned. These shares, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of shares beneficially owned is based on 72,858,184 shares of common stock outstanding as of February 1, 2023. Unless otherwise indicated, all amounts exclude shares issuable upon the exercise of outstanding options and vesting of restricted stock units that are not exercisable and/or vested as of February 1, 2023 or within 60 days of February 1, 2023. Except as noted, each stockholder in the above table is believed to have sole voting and sole investment power with respect to the shares of common stock beneficially held. (2)All of these shares are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its general partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager. Includes 20,727 restricted stock units, that are scheduled to vest on March 1, 2023. Excludes 5,166 restricted stock units that are scheduled to vest in two equal annual installments beginning on May 28, 2023 and 9,227 restricted stock units that are scheduled to vest on March 1, 2024. Also excludes (i) 66,714 performance-based restricted stock units awarded to Mr. Stice on January 19, 2016, which vested on December 31, 2017(representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2017 by Diamondback’s compensation committee, and (ii) 45,084 performance-based restricted stock units awarded to Mr. Stice on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2018. Also excludes (i) 11,115 performance-based restricted stock units awarded to Mr. Stice on February 16, 2017, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2018, and (ii) 22,230 performance-based restricted stock |
units awarded to Mr. Stice on February 16, 2017,March 1, 2020, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2022, (ii) 51,748 performance-based restricted stock units awarded to Mr. Stice on March 1, 2021, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2023 and (iii) 41,524 performance-based restricted stock units awarded to Mr. Stice on March 1, 2022, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2024.
(3)Includes 9,882 restricted stock units, that are scheduled to vest on March 1, 2023. Excludes (i) 51,658 restricted stock units that are scheduled to vest in two equal annual installments beginning on May 28, 2023, (ii) 3,845 restricted stock units, that are scheduled to vest on March 1, 2024 and (iii) 8,790 restricted stock units, that are scheduled to vest in five equal annual installments beginning on March 1, 2025. Also excludes (i) 13,183 performance-based restricted stock units awarded to Mr. Van’t Hof on March 1, 2019 (representing 100% vesting of the originally reported amount) based upon final determination upon certification of certain stockholders return performance conditions relative to Diamondback’s peer group during the three-year performance period ended on December 31, 2021, that are scheduled to vest in five equal installments beginning on March 1, 2025, (ii) 31,133 performance-based restricted stock units awarded to Mr. Van’t Hof on March 1, 2020, that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2022, (iii) 27,168 performance-based restricted stock units awarded to Mr. Van’t Hof on March 1, 2021, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2023 and (iv) 17,302 performance-based restricted stock units awarded to Mr. Van’t Hof on March 1, 2022, which are subject to the satisfaction of certain stockholder return performance
conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2024.
(4)Includes 5,501 restricted stock units, that are scheduled to vest on March 1, 2023. Excludes 2,583 restricted stock units that are scheduled to vest in two equal annual installments beginning on May 28, 2023 and 2,051 restricted stock units that are scheduled to vest on March 1, 2024. Also excludes (i) 17,790 performance-based restricted stock units awarded to Ms. Dick on March 1, 2020, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2019.2022, (ii) 15,524 performance-based restricted stock units awarded to Ms. Dick on March 1, 2021, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2023 and (iii) 9,228 performance-based restricted stock units awarded to Ms. Dick on March 1, 2022, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2024.
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(3) | Excludes 567 restricted stock units, which will vest on September 1, 2018 and 1,300 restricted stock units, which will vest on February 16, 2019. |
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(4) | Excludes 1,950 restricted stock units, which will vest on February 16, 2019. Also excludes (i) 12,022 performance-based restricted stock units awarded to Ms. Dick on January 19, 2016, which vested on December 31, 2017 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2017 by Diamondback’s compensation committee, and (ii) 3,006 performance-based restricted stock units awarded to Ms. Dick on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2018. Also excludes (i) 2,925 performance-based restricted stock units awarded to Ms. Dick on February 16, 2017, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2018, and (ii) 5,850 performance-based restricted stock units awarded to Ms. Dick on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2019. |
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(5) | Excludes 3,900 restricted stock units, which will vest on February 16, 2019. Also excludes (i) 48,090 performance-based restricted stock units awarded to Mr. Pantermuehl on January 19, 2016, which vested on December 31, 2017 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2017 by Diamondback’s compensation committee, and (ii) 12,022 performance-based restricted stock units awarded to Mr. Pantermuehl on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2018. Also excludes 5,850 performance-based restricted stock units awarded to Mr. Pantermuehl on February 16, 2017, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2018, and (ii) 11,700 performance-based restricted stock units awarded to Mr. Pantermuehl on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2019. |
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(6) | Excludes 1,300 restricted stock units, which will vest on February 16, 2019. |
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(7) | Excludes 1,950 restricted stock units, which will vest on February 16, 2019. Also excludes 12,022 performance-based restricted stock units awarded to Mr. Holder on January 19, 2016, which vested on December 31, 2017 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2017 by Diamondback’s compensation committee, and (ii) 3,006 performance-based restricted stock units awarded to Mr. Holder on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2018. Also excludes (i) 2,925 performance-based restricted stock units awarded to Mr. Holder on February 16, 2017, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2018, and (ii) 5,850 performance-based restricted stock units awarded to Mr. Holder on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2019. |
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(8) | Excludes 3,900 restricted stock units, which will vest on February 16, 2019. Also excludes 12,022 performance-based restricted stock units awarded to Mr.Molnar on January 19, 2016, which vested on December 31, 2017 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2017 by Diamondback’s compensation committee, and (ii) 6,011 performance-based restricted stock units awarded to Mr. Molnar on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2018. Also excludes (i) 5,850 performance-based restricted stock units awarded to Mr. Molnar on February 16, 2017, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2018, and (ii)11,700 performance-based restricted stock units awarded to Mr. Molnar on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2019. |
(5)Includes 3,442 restricted stock units that are scheduled to vest on March 1, 2023. Excludes 2,583 restricted stock units that are scheduled to vest in two equal annual installments beginning on May 28, 2023 and 1,199 restricted stock units that are scheduled to vest on March 1, 2024. Also excludes (i) 11,564 performance-based restricted stock units awarded to Mr. Hawkins on March 1, 2020 that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2022, (ii) 10,091 performance-based restricted stock units awarded to Mr. Hawkins on March 1, 2021, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2023 and (iii) 5,398 performance-based restricted stock units awarded to Mr. Hawkins on March 1, 2022, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2024.
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(9) | Excludes 453 restricted stock units, which will vest on July 1, 2018, and 2,055 shares of Diamondback common stock, which will vest on the earlier of the one-year anniversary of the date of grant and the date of the 2018 annual meeting of stockholders of Diamondback. |
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(10) | All of these shares are held by MBH Investments, Ltd., which is managed by MBH Financial, LLC, its general partner. Mr. Hollis, his spouse and the Hollis 2014 Irrevocable Trust hold 100% of the membership interests in MBH Financial, LLC, of which Mr. Hollis is the manager. Excludes 4,550 restricted stock units, which will vest on February 16, 2019. Also excludes 60,112 performance-based restricted stock units awarded to Mr. Hollis on January 19, 2016, which vested on December 31, 2017 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance periods ending on December 31, 2017 by Diamondback’s compensation committee, and (ii) 15,028 performance-based restricted stock units awarded to Mr. Hollis on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2018. Also excludes (i) 6,825 performance-based restricted stock units awarded to Mr. Hollis on February 16, 2017, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2018, and (ii) 13,650 performance-based restricted stock units awarded to Mr. Hollis on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2019. |
(6)Includes 4,811 restricted stock units, that are scheduled to vest on March 1, 2023. Excludes 1,034 restricted stock units that are scheduled to vest in two equal annual installments beginning on May 28, 2023 and 2,050 restricted stock units that are scheduled to vest on March 1, 2024. Also excludes (i) 14,232 performance-based restricted stock units awarded to Mr. Zmigrosky on March 1, 2020, that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2022, (ii) 12,420 performance-based restricted stock units awarded to Mr. Zmigrosky on March 1, 2021, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2023 and (iii) 9,228 performance-based restricted stock units awarded to Mr. Zmigrosky on March 1, 2022, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2024.
(7)Excludes 1,274 restricted stock units that are scheduled to vest on the earlier of the one-year anniversary of the date of grant and the date of the 2023 annual meeting of stockholders of Diamondback.
Holdings of Major Stockholders
The following table sets forth certain information regarding the beneficial ownership of our common units and Class B units as of February 1, 2023 by each unitholder known by us to beneficially own 5% or more of our common units or Class B units.
MAJOR UNITHOLDER TABLE
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| | Common Units | | Class B Units |
| Name and Address of Beneficial Owner | | Amount and Nature of Beneficial Ownership(1) | | Percentage of Class Beneficially Owned | | Amount and Nature of Beneficial Ownership(1) | | Percentage of Class Beneficially Owned |
Diamondback Energy, Inc.(2) 500 West Texas Avenue, Suite 100 Midland, Texas 79701 | | 731,500 | | 1.0 | % | | 90,709,946 | | | 100 | % |
Wellington Management Group LLP(3) c/o Wellington Management Company LLP 280 Congress Street Boston, MA 02210 | | 11,024,380 | | 15.1 | % | | — | | | — | |
Blackstone, Inc.(4) 345 Park Avenue New York, NY 10154 | | 9,482,228 | | 13.0 | % | | — | | | — | |
Santa Elena Minerals, LP(5) 400 W. Illinois, Suite 1300 Midland, TX 79701 | | 5,152,124 | | 7.1 | % | | — | | | — | |
(1)Beneficial ownership is determined in accordance with SEC rules. The percentage of common units beneficially owned is based on 72,858,184 common units outstanding as of February 1, 2023. Except as noted, each unitholder in the above table is believed to have sole voting and sole investment power with respect to the common units and Class B units beneficially held.
(2)Diamondback Energy, Inc. is a publicly traded company and holds 731,500 common units and 90,709,946 Class B units, with the same aggregate number of units of the Operating Company (each, an “OpCo unit”) that are exchangeable from time to time, in its discretion, for common units (that is, one OpCo unit and one Class B unit, together, are exchangeable for one common unit), and, as a result, Diamondback may be deemed to have the beneficial ownership of such common units. Diamondback has sole voting and dispositive power with respect to the common units and Class B units it holds. The directors of Diamondback are Travis D. Stice, Steven E. West, Vincent K. Brooks, Michael P. Cross, David L. Houston, Stephanie K. Mains, Mark L. Plaumann, Melanie M. Trent, Rebecca A. Klein and Frank D. Tsuru. Travis D. Stice is the sole director of Diamondback E&P.
(3)Based solely on Schedule 13G/A jointly filed with the SEC on February 6, 2023 by Wellington Management Group LLP (“Wellington Management”), Wellington Group Holdings LLP (“Wellington Holdings”), Wellington Investment Advisors Holdings LLP (“Wellington Advisors”) and Wellington Management Company LLP (“Wellington Company”). These units are owned of record by clients of Wellington Company, Wellington Management Canada LLC, Wellington Management Singapore Pte Ltd, Wellington Management Hong Kong Ltd, Wellington Management International Ltd, Wellington Management Japan Pte Ltd and Wellington Management Australia Pty Ltd (collectively, the “Wellington Investment Advisers”). Wellington Advisors controls directly, or indirectly through Wellington Management Global Holdings Ltd., the Wellington Investment Advisers. Wellington Advisors is owned by Wellington Holdings, which is in turn owned by Wellington Management. The clients of the Wellington Investment Advisers have the right to receive, or the power to direct the receipt of, dividends from, or the proceeds from the sale of, such securities. No such client is known to have such right or power with respect to more than five percent of this class of securities. Each of Wellington Management, Wellington Holdings and Wellington Advisors reported shared voting power over 9,995,433 common units and shared dispositive power over 11,024,380 common units. Wellington Company reported shared voting power over 9,878,636 common units and shared dispositive power over 10,602,260 common units.
(4)Based on Schedule 13D/A, filed with the SEC on November 8, 2022, and Form 4, filed with the SEC on January 30, 2023. Represents common units held directly by BX SWT ML Holdco LLC. BX Guidon Topco LLC is the sole member of BX SWT Holdco LLC. The controlling membership interests of BX Guidon Topco LLC are held by Blackstone Management Associates VI L.L.C. and Blackstone Energy Management Associates II L.L.C. BMA VI L.L.C. is the sole member of Blackstone Management Associates VI L.L.C. Blackstone EMA II L.L.C. is the sole member of Blackstone Energy Management Associates II L.L.C. Blackstone Holdings III L.P. is the managing member of each of BMA VI L.L.C. and Blackstone EMA II L.L.C. Blackstone Holdings III GP L.P. is the general partner of Blackstone Holdings III L.P. Blackstone Holdings III GP Management L.L.C. is the general partner of Blackstone Holdings III GP L.P.
Blackstone Inc. is the sole member of Blackstone Holdings III GP Management L.L.C. The sole holder of the Series II preferred stock of Blackstone Inc. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. Each of the above entities or persons may be deemed to beneficially own common units beneficially owned by BX Topco or indirectly controlled by such entity or person. Each of the above entities or persons disclaims beneficial ownership of such securities in excess of their respective pecuniary interest therein.
(5)Based on Viper’s records.
Securities Authorized For Issuance Under Equity Compensation Plans
The following table summarizes information about our equity compensation plans as of December 31, 2017:2022:
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| Plan Category | | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted-average exercise price of outstanding options, warrants and rights | | Number of securities remaining available for future issuance under equity compensation plans |
Equity compensation plans not approved by security holders(1) | | | | | | |
| Long Term Incentive Plan | | 113,494 | | | $ | — | | | 8,535,945 | |
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| Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights(2) | Number of securities remaining available for future issuance under equity compensation plans |
Equity compensation plans not approved by security holders(1) | | | |
| Long Term Incentive Plan | 113,039 |
| $ | 18.48 |
| 8,957,317 |
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(1) | Our general partner adopted the LTIP in connection with the IPO in June 2014. |
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(2) | Reflects the weighted average exercise price for each of the 7,600 outstanding unit options. |
Changes in Control
Our general partnerGeneral Partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partnerGeneral Partner to transfer its membership interests in our general partnerGeneral Partner to a third party. After any such transfer, the new member or members of our general partnerGeneral Partner would then be in a position to replace the board of directors and executive officers of our general partnerGeneral Partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner.General Partner. This effectively permits a “change of control” without the vote or consent of the unitholders.
Treatment of Equity Awards Granted under the LTIP Upon Termination, Resignation and Death or Disability of Certain Executive Officers of our General Partner and Change of Control
No executive officers of our General Partner held unvested equity awards under the LTIP as of December 31, 2022.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Agreements and Transactions with Affiliates
We have entered into certain agreements and transactions with Diamondback and its affiliates, as described in more detail below.
Payments to our General Partner and its Affiliates
Under the terms of our partnership agreement, we are required to reimburse the general partnerour General Partner for all direct and indirect expenses incurred or paid on our behalf and all other expenses allocable to us or otherwise incurred by the general partnerour General Partner in connection with operating our business. The partnership agreement does not set a limit on the amount of expenses for which the general partnerour General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partnerGeneral Partner by its affiliates. Our general partnerGeneral Partner is entitled to determine the expenses that are allocable to us. For the year ended December 31, 2017, the2022, our General Partner received $2.5$3.7 million in reimbursements from the Partnership.
Distributions paid to Diamondback
Diamondback is entitled to receive its pro rata portion of the distributions we make on our common units and the Operating Company makes in respect of our commonthe OpCo units. Holders of the Partnership’s Class B units are not entitled to receive cash distributions except to the extent of the cash preferred distributions equal to 8% per annum payable quarterly on the $1.0 million capital contribution made to us by Diamondback pursuant to the recapitalization agreement in connection with the issuance of the Class B units in the recapitalization transaction. During the year ended December 31, 2017,2022, Diamondback received such distributions from us and the Operating Company in the aggregate amount of $89.5$234.1 million.
Registration Rights Agreement
On June 23, 2014, in connection with the IPO, we entered into a registration rights agreement with Diamondback. Pursuant to thethis registration rights agreement, we filed a registration statement on Form S-3 registering, under the Securities Act, the common units issued to Diamondback for resale. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates and, in certain circumstances, to third parties.
Advisory Services Agreement
On June 23, 2014, in connection with the closing of the IPO,In May 2018, we and Diamondback entered into an advisory servicesamended and restated registration rights agreement, dated as of May 9, 2018. The amended and restated registration rights agreement amended the definition of “registrable securities” to include common units acquired or that may be acquired by Diamondback in accordance with our exchange agreement with WexfordDiamondback. In addition, whenever a holder has requested that any registrable securities be registered under the amended and restated registration rights agreement or has initiated an underwritten offering, the amended and restated registration rights agreement requires such holder, if applicable, to cause such registrable securities to be exchanged into common units in accordance with the terms of the exchange agreement before or substantially concurrently with the sale of such registrable securities.
In July 2018, we filed a registration statement on Form S-3ASR under which, Wexford agreedwe registered for resale by Diamondback (i) common units issuable to provide us and our general partner with general financial and strategic advisory services related to our business in return for an annual feeDiamondback upon exercise of $0.5 million, plus reimbursement of reasonable out-of-pocket expenses. This agreement had a term of two years commencing on the completion of the IPO, and continues for additional one-year periods unless terminated in writing by either party at least ten days priorits exchange right pursuant to the expirationexchange agreement and Diamondback’s tender to us of the then current term. The agreement may be terminated at any time by either party upon 30 days’ prior written notice. In the event we terminate the agreement, we will be obligated to pay all amounts due through the remaining term of the agreement. The services provided by Wexford under the advisory services agreement do not extend to our day-to-day business or operations. In addition, under this agreement, we agreed to pay Wexford to-be-negotiated market-based fees approved by the conflicts committee of the board of directorsan equivalent number of our general partner, if,outstanding Class B units and to the extent, we request such services from Wexfordoutstanding OpCo Units, in connection with acquisitionseach case then held by Diamondback and divestitures, financings or other transactions in which we may be involved. We agreed to indemnify Wexford and its affiliates from their losses arising out of or in connection with the agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. In the event we are dissatisfied with the services provided(ii) common units then held by Wexford, our only remedy against Wexford is to terminate the agreement. For the years ended December 31, 2017 and 2016, we did not pay any amounts under the advisory services agreement.
Diamondback.
Tax Sharing Agreement
On June 23, 2014, inIn connection with the closing of the IPO, we entered into a tax sharing agreement with Diamondback, pursuant todated June 23, 2014, in which we are requiredagreed to reimburse Diamondback for our share of state and local income and other taxes borne by Diamondback as a result offor which our results beingare included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on the closing date of the IPO.June 23, 2014. The amount of any such reimbursement is limited to the tax that we would have paid had we not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe less or no tax. However,In such a situation, we would neverthelessagreed to reimburse Diamondback for the tax we would have owed had the tax attributes not been available or used for our benefit, even though Diamondback had no cash tax expense for that period. For the year ended December 31, 2022, we recognized $0.9 million of state income tax expense payable under the tax sharing agreement.
Lease Bonus Payments
During the year ended December 31, 2017,2022, Diamondback paid us $23.4 million in lease bonus payments for seven new leases.
Surface Use
Diamondback periodically pays us for surface use charges and right of way easements related to properties that Diamondback leases from us. During the year ended December 31, 2022, Diamondback paid the Partnership $0.6 million for such purposes.
Transaction with Significant Unitholder
On January 13, 2022, as part of our common unit repurchase program, we did not reimbursepurchased 1.5 million common units with an aggregate purchase price of approximately $37.3 million in a privately negotiated transaction with an affiliate of Blackstone, Inc., or Blackstone. As of February 1, 2023, Blackstone owned approximately 13.0% of Viper’s outstanding common units, which were acquired in the Swallowtail Acquisition. Additionally, an affiliate of Blackstone beneficially owned approximately 5.8% of the outstanding common stock of Diamondback under the tax sharing agreement.at February 1, 2023.
Procedures for Review, Approval and Ratification of Transactions with Related Persons
The board of directors of our general partnerGeneral Partner has adopted policies for the review, approval and ratification of transactions with related persons. The board has adopted a written code of business conduct and ethics, under which a director is expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partnerGeneral Partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.
If a conflict or potential conflict of interest arises between our general partnerGeneral Partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partnerGeneral Partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.
Any executive officer is required to avoid conflicts of interest unless approved by the board of directors of our general partner.General Partner.
The code of business conduct and ethics described above was initially adopted in connection with the closing of the IPO, and asIPO. As a result, the transactions described above that were effective at the time of the IPO were not reviewed according to such procedures.
Director Independence
ITEM 14. PRINCIPAL ACCOUNTINGACCOUNTANT FEES AND SERVICES
The audit committee of the board of directors of our general partnerGeneral Partner selected Grant Thornton LLP, an independent registered public accounting firm, to audit our consolidated financial statements for the years ended December 31, 2017, 20162022 and 2015.2021. The audit committee’s charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below with respect to our annual reports for the years ended December 31, 2017, 20162022 and 20152021 were approved by the audit committee.
The following table summarizes the aggregate Grant Thornton LLP fees that were allocated to us for independent auditing, tax and related services:
| | | | | | | | | | | | | |
| Year Ended December 31, | | |
| 2022 | | 2021 | | |
| (In thousands) |
Audit fees(1) | $ | 386 | | | $ | 331 | | | |
Audit-related fees(2) | — | | | 84 | | | |
Tax fees(3) | — | | | — | | | |
All other fees(4) | — | | | — | | | |
| Total | $ | 386 | | | $ | 415 | | | |
(1)Audit fees represent aggregate fees for audit services, which relate to the fiscal year consolidated audit, quarterly reviews, registration statements and comfort letters.
(2)Audit-related fees for the year ended December 31, 2021 represent fees for an acquired business audit required pursuant to Regulation S-X, Rule 3-05.
(3)Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning.
(4)All other fees represent amounts billed in each of the years presented for services not classifiable under the other categories listed in the table above.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in thousands) |
Audit fees(1) | $ | 138 |
| | $ | 116 |
| | $ | 97 |
|
Audit-related fees(2) | — |
| | — |
| | — |
|
Tax fees(3) | — |
| | — |
| | — |
|
All other fees(4) | — |
| | — |
| | — |
|
| Total | $ | 138 |
| | $ | 116 |
| | $ | 97 |
|
| |
(1) | Audit fees represent amounts billed for each of the periods presented for professional services rendered in connection with those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. |
| |
(2) | Audit-related fees represent amounts billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews. |
| |
(3) | Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning. |
| |
(4) | All other fees represent amounts billed in each of the years presented for services not classifiable under the other categories listed in the table above. |
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|
| | | | | | | |
| (a) | Documents included in this report: |
| 1. Financial Statements | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| 2. Financial Statement Schedules |
| Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Partnership’s consolidated financial statements and related notes. | |
| | | | | | | | |
|
| Exhibit Number | | Description |
2.1*# | | |
| 2.1# | | Purchase and Sale Agreement dated August 6, 2021 by and among Swallowtail Royalties LLC, Swallowtail Royalties II LLC (collectively, as of November 21, 2017, amongseller), Viper Energy Partners LLC DGK ORRI Company, L.P.,(as buyer) and Viper Energy Partners LP (as parent, and collectively with Viper Energy Partners LLC, as seller, and Royalty Resources L.P., as seller’s parent guarantor.buyer parties) (incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on August 12, 2021). |
| 3.1 | | |
| 3.2 | | |
| 3.3 | | |
| 3.4 | | |
| 3.5 | | |
4.13.6 | | |
| 4.1 | | |
| 4.2 | | |
10.14.3 | | Senior Secured Revolving CreditRegistration Rights Agreement, dated as of July 8, 2014,October 1, 2021, by and among Viper Energy Partners LP, as borrower, Wells Fargo Bank, National Association, as the administrative agent, sole book runnerSwallowtail Royalties LLC and lead arranger, and certain lenders from time to time party thereto.Swallowtail Royalties II LLC (incorporated by reference to Exhibit 10.14.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on July 14, 2014)October 7, 2021). |
10.24.4 | | First Amendment,Indenture, dated as of August 15, 2014,October 16, 2019, among Viper Energy Partners LP, as issuer, Viper Energy Partners LLC, as guarantor and Wells Fargo Bank, National Association, as trustee (including the form of Viper Energy Partners LP’s 5.375% Senior Notes due 2027) (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on October 17, 2019). |
| | | | | | | | |
|
| Exhibit Number | | Description |
| 10.1 | | Amended and Restated Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Form 10-Q (File No. 001-36505) filed on August 10, 2015). |
10.3 | | Second Amendment, dated as of May 22, 2015, to Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto (incorporated by reference to Exhibit 10.2 of the Partnership’s Form 10-Q (File No. 001-36505) filed on August 10, 2015). |
10.4 | | Third Amendment, dated as of June 21, 2016, to the Credit Agreement, dated as of July 8, 2014,20, 2018, by and among, Viper Energy Partners LP,LLC, as borrower, Viper Energy Partners LLC,LP, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 27, 2016)July 26, 2018). |
10.5 | | Fourth Amendment, dated as of October 28, 2016, to the Credit Agreement, dated as of July 8, 2014, by and among Viper Energy Partners LP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on November 3, 2016). |
10.6 | | Fifth Amendment, dated as of November 28, 2017, to the Credit Agreement, dated as of July 8, 2014, by and among Viper Energy Partners LP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on December 4, 2017). |
|
| 10.2+ | | |
3. Exhibits |
10.7 | | |
10.8+ | | |
10.910.3 | | |
10.1 | | |
10.1110.4 | | |
10.12+10.5+ | | |
10.13+10.6+ | | |
| 10.7 | | |
| 10.8 | | |
| 10.9 | | |
| 10.10 | | |
| 10.11 | | Second Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of September 24, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lender party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on September 30, 2019). |
| 10.12 | | Third Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of October 8, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lender party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on October 10, 2019). |
| 10.13 | | Fourth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of November 29, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on December 5, 2019). |
| 10.14 | | Fifth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 11, 2020, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2020). |
| 10.15 | | Sixth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of November 6, 2020, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on November 6, 2014)12, 2020). |
21.1*10.16 | | Seventh Amendment to Amended and Restated Senior Secured Revolving Credit Agreement and Second Amendment to Guaranty and Collateral Agreement, dated as of June 2, 2021, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on June 8, 2021). |
| | | | | | | | |
|
| Exhibit Number | | Description |
| 10.17 | | Eighth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement and Second Amendment to Guaranty and Collateral Agreement, dated as of November 15, 2021, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on November 18, 2021). |
| 10.18* | | Ninth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement and Second Amendment to Guaranty and Collateral Agreement, dated as of November 18, 2022, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto. |
| 10.19 | | |
| 21.1* | | |
| 23.1* | | |
| 23.2* | | |
| 31.1* | | |
| 31.2* | | |
| 32.1++ | | |
| 99.1* | | |
101.INS*101 | | XBRL Instance Document.The following financial information from the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2022, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Changes in Unitholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to Consolidated Financial Statements. |
101.SCH*104 | | Cover Page Interactive Data File (formatted as Inline XBRL Taxonomy Extension Schema Document. |
101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase. |
101.DEF* | | XBRL Taxonomy Extension Definition Linkbase Document. |
101.LAB* | | XBRL Taxonomy Extension Labels Linkbase Document. |
101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase Document.and contained in Exhibit 101). |
|
| | | | |
| * | Filed herewith. |
# | 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. |
| + | Management contract, compensatory plan or arrangement. |
| ++ | The certifications attached as Exhibit 32.1 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. |
| # | Schedules (or similar attachments) have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided 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 Annual Report to be signed on its behalf by the undersigned thereunto duly authorized.
| | | | | | | | | | | |
| | VIPER ENERGY PARTNERS LP |
| Date: | February 23, 2023 | |
| | By: | VIPER ENERGY PARTNERS GP LLC |
| | | its General Partner |
| | | |
| | VIPER ENERGY PARTNERS LP |
Date:By: | February 7, 2018 | |
| | By: | VIPER ENERGY PARTNERS GP LLC |
| | | its general partner |
| | | |
| | By: | /s/ Travis D. Stice |
| | Name: | Travis D. Stice |
| | Title: | Chief Executive Officer |
Pursuant to the requirements of the Securities and Exchange Act of 1934, this Annual 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/ Travis D. Stice | | Chief Executive Officer and Director | | February 23, 2023 |
| Travis D. Stice | | (Principal Executive Officer) | | |
| | | | |
Signature | | Title | | Date |
| | | |
/s/ Travis D. Stice | | Chief Executive Officer and Director | | February 7, 2018 |
Travis D. Stice | | (Principal Executive Officer) | | |
| | | | |
| /s/ Teresa L. Dick | | Chief Financial Officer | | February 7, 201823, 2023 |
| Teresa L. Dick | | (Principal Financial and Accounting Officer) | | |
| | | | |
| /s/ Steven E. West | | Chairman of the Board and Director | | February 7, 201823, 2023 |
| Steven E. West | | | | |
| | | | |
| /s/ W. Wesley Perry | | Director | | February 7, 201823, 2023 |
| W. Wesley Perry | | | | |
| | | | |
| /s/ Spencer D. Armour | | Director | | February 7, 201823, 2023 |
| Spencer D. Armour | | | | |
| | | | |
/s/ Michael L. Hollis | | Director | | February 7, 2018 |
Michael L. Hollis | | | | |
| | | | |
| /s/ James L. Rubin | | Director | | February 7, 201823, 2023 |
| James L. Rubin | | | | |
| | | | |
/s/ Rosalind Redfern GroverFrank C. Hu | | Director | | February 7, 201823, 2023 |
Rosalind Redfern GroverFrank C. Hu | | | | |
| | | | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
PartnersGeneral Partner and Unitholders
Viper Energy Partners LP
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Viper Energy Partners LP (a Delaware limited partnership) and subsidiary (collectively, the(the “Partnership”) as of December 31, 20172022 and 2016,2021, the related consolidated statements of operations, unitholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017,2022, 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 Partnership as of December 31, 20172022 and 2016,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2022, 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 Partnership’s internal control over financial reporting as of December 31, 2022, 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 23, 2023 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)PCAOB and are required to be independent with respect to the Partnership 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. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.
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 supportingregarding 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 matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate
Estimation of proved reserves as it relates to the calculation and recognition of depletion expense
As described further in Note 2 to the financial statements, the Partnership 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. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the timing and volumetric amounts of production and corresponding decline rate of producing properties associated with the operator’s development plan. We identified the estimation of proved reserves of oil and gas properties as it relates to the calculation and recognition of depletion expense as a critical audit matter.
The principal considerations for our determination that the estimation of proved reserves is a critical audit matter are that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future revenues of the Partnership’s proved reserves could have a significant impact on the measurement of depletion 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 management’s estimation of proved reserves for the purpose of estimating depletion expense. Specifically, these controls related to the use of historical information in the estimation of proved reserves derived from the Partnership’s accounting records, the controls on information provided to the reservoir engineering specialists and the management review controls on the final proved reserve report.
•We evaluated the level of knowledge, skill, and ability of the Partnership’s reservoir engineering specialists, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Partnership’s proved reserve volumes, and read the reserve report prepared by the Partnership’s specialists.
•Identified inputs and assumptions that were significant to the period end determination of proved reserve volumes and tested management’s process of determining the significant inputs and assumptions, as follows:
◦Compared the estimated pricing and pricing differentials used in the reserve report to actual realized prices related to revenue transactions recorded in the current year;
◦Vouched, on a sample basis, the net revenue interests used in the reserve report to underlying land and division order records;
◦Obtained evidence supporting the amount of development of proved undeveloped properties reflected in the reserve report and compared future development plans to historical conversion rates to evaluate the likelihood of development related to the proved undeveloped properties;
◦Evaluated the estimated ultimate recovery of proved undeveloped properties by comparing forecasted amounts on a sample of individual wells to the estimated ultimate recovery of comparable proved developed producing properties; and
◦Applied analytical procedures on inputs to the reserve report by comparing to historical actual results and to the prior year reserve report.
Estimation of future taxable income of the Partnership as it relates to the partial release of the deferred tax asset valuation allowance
As described further in Note 2 to the financial statements, the Partnership recognized discrete income tax benefits related to a partial release of its beginning-of-the-year valuation allowance, based on a change in judgment about the realizability of its deferred tax assets in future years. Management’s assessment of all available evidence, both positive and negative, supporting the realizability of the Partnership’s deferred tax assets, as required by applicable accounting standards, resulted in the recognition of a tax benefit for the portion of the Partnership’s deferred tax assets considered more likely than not to be realized. We identified the estimation of future taxable income of the Partnership as it relates to the realizability of the deferred tax asset and the partial release of the deferred tax asset valuation allowance as a critical audit matter.
The principal consideration for our determination that the estimation of future taxable income as it relates to the realizability of the deferred tax asset and the partial release of the deferred tax asset valuation allowance is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the future taxable income could have a significant impact on the measurement of the deferred tax asset and the partial release of the deferred tax asset valuation allowance. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of future taxable income as it relates to the realizability of the deferred tax asset and the partial release of the deferred tax asset valuation allowance included the following, among others.
•We tested the design and operating effectiveness of key controls relating to the income tax provision which includes the periodic evaluation of the valuation allowance, and as applicable, the measurement of any full or partial release of the valuation allowance. Specifically, these controls related to the preparation and review of the tax provision, including the estimation of future taxable income required as part of the evaluation and measurement of the release of the valuation allowance.
•Identified inputs and assumptions that were significant to the determination of future taxable income and tested management’s process for determining the assumptions, including understanding and testing management’s development plan of oil and gas properties. Specifically, our audit procedures involved testing management’s assumptions as follows:
◦Tested whether the tax basis of depletable properties was in excess of the book basis of those properties and whether the book income before depletion would be greater than tax depletion for the forecasted periods;
◦Evaluated whether income is forecasted to be recognized in a period no earlier than when the Partnership’s tax depletion deductions are forecasted and evaluated whether the time period in which these deductions would be generated were reasonable;
◦Evaluated the inputs to the tax depletion calculation, including the initial tax depletable basis of the leaseholds, initial tax basis in the undeveloped leaseholds, estimated transfers of undeveloped to developed properties, production, and reserves volumes used in computing the unit of production ratio;
◦Clerically tested the mathematical calculation of the tax depletion;
◦Evaluated the Partnership’s forecasts of future production volumes including the amount of proved undeveloped properties and future reserves to be developed by comparing forecasted future production to historical actual production, historical conversion rates and actual volume decline curves, and by comparing the forecast utilized to the SEC reserve report and evaluating any differences;
◦Compared the estimated realized pricing used in the future taxable income forecast to quoted future market pricing for observable periods;
◦Compared the net revenue interests used in the forecast of producing reserves and related future taxable income to the Partnership’s interim and year-end reserve reports; and
◦Evaluated the production tax, ad valorem tax, interest expense, and general and administrative expense included in the estimates of future taxable income forecast by comparing to historical actuals.
/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2013.
Oklahoma City, Oklahoma
February 7, 2018
23, 2023
Viper Energy Partners LP
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| (In thousands, except unit amounts) |
| Assets | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 18,179 | | | $ | 39,448 | |
| | | |
| Royalty income receivable (net of allowance for credit losses) | 81,657 | | | 68,568 | |
| Royalty income receivable—related party | 6,260 | | | 2,144 | |
| Derivative instruments | 9,328 | | | — | |
| Other current assets | 3,196 | | | 989 | |
| Total current assets | 118,620 | | | 111,149 | |
| Property: | | | |
| Oil and natural gas interests, full cost method of accounting ($1,297,221 and $1,640,172 excluded from depletion at December 31, 2022 and December 31, 2021, respectively) | 3,464,819 | | | 3,513,590 | |
| Land | 5,688 | | | 5,688 | |
| Accumulated depletion and impairment | (720,234) | | | (599,163) | |
| Property, net | 2,750,273 | | | 2,920,115 | |
| | | |
| Derivative instruments | 442 | | | — | |
| Deferred income taxes (net of allowances) | 49,656 | | | — | |
| Other assets | 1,382 | | | 2,757 | |
| Total assets | $ | 2,920,373 | | | $ | 3,034,021 | |
| Liabilities and Unitholders’ Equity | | | |
| Current liabilities: | | | |
| Accounts payable | $ | 1,129 | | | $ | 69 | |
| Accounts payable—related party | 306 | | | — | |
| Accrued liabilities | 19,600 | | | 20,509 | |
| Derivative instruments | — | | | 3,417 | |
| Income taxes payable | 911 | | | 471 | |
| Total current liabilities | 21,946 | | | 24,466 | |
| Long-term debt, net | 576,895 | | | 776,727 | |
| | | |
| Derivative instruments | 7 | | | — | |
| Total liabilities | 598,848 | | | 801,193 | |
| Commitments and contingencies (Note 12) | | | |
| | | |
| Unitholders’ equity: | | | |
| | | |
| General Partner | 649 | | | 729 | |
| Common units (73,229,645 units issued and outstanding as of December 31, 2022 and 78,546,403 units issued and outstanding as of December 31, 2021) | 689,178 | | | 813,161 | |
| Class B units (90,709,946 units issued and outstanding December 31, 2022 and December 31, 2021) | 832 | | | 931 | |
| Total Viper Energy Partners LP unitholders’ equity | 690,659 | | | 814,821 | |
| Non-controlling interest | 1,630,866 | | | 1,418,007 | |
| Total equity | 2,321,525 | | | 2,232,828 | |
| Total liabilities and unitholders’ equity | $ | 2,920,373 | | | $ | 3,034,021 | |
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | | | |
| | (In thousands, except unit amounts) |
| Assets | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 24,197 |
| | $ | 9,213 |
|
| Restricted cash | — |
| | 500 |
|
| Royalty income receivable | 25,754 |
| | 10,043 |
|
| Royalty income receivable—related party | 5,142 |
| | 3,470 |
|
| Other current assets | 355 |
| | 187 |
|
| Total current assets | 55,448 |
| | 23,413 |
|
| Property and equipment: | | | |
| Oil and natural gas interests, full cost method of accounting ($514,724 and $252,232 excluded from depletion at December 31, 2017 and 2016, respectively) | 1,103,897 |
| | 760,818 |
|
| Accumulated depletion and impairment | (189,466 | ) | | (148,948 | ) |
| Oil and natural gas interests, net | 914,431 |
| | 611,870 |
|
| Funds held in escrow | 6,304 |
| | — |
|
| Other assets | 36,854 |
| | 35,266 |
|
| Total assets | $ | 1,013,037 |
| | $ | 670,549 |
|
| Liabilities and Unitholders’ Equity | | | |
| Current liabilities: | | | |
| Accounts payable | $ | 2,960 |
| | $ | 1,780 |
|
| Other accrued liabilities | 2,669 |
| | 371 |
|
| Total current liabilities | 5,629 |
| | 2,151 |
|
| Long-term debt | 93,500 |
| | 120,500 |
|
| Total liabilities | 99,129 |
| | 122,651 |
|
| Commitments and contingencies (Note 10) |
| |
|
| Unitholders’ equity: | | | |
| Common units (113,882,045 units issued and outstanding as of December 31, 2017 and 87,800,356 units issued and outstanding as of December 31, 2016 ) | 913,908 |
| | 547,898 |
|
| Total unitholders’ equity | 913,908 |
| | 547,898 |
|
| Total liabilities and unitholders’ equity | $ | 1,013,037 |
| | $ | 670,549 |
|
See accompanying notes to consolidated financial statements.
Viper Energy Partners LP
Consolidated Statements of Operations
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands, except per unit amounts) |
| Operating income: | | | | | |
| Royalty income | $ | 837,976 | | | $ | 501,534 | | | $ | 246,981 | |
| Lease bonus income | 27,791 | | | 2,763 | | | 2,585 | |
| | | | | |
| Other operating income | 700 | | | 620 | | | 1,060 | |
| Total operating income | 866,467 | | | 504,917 | | | 250,626 | |
| Costs and expenses: | | | | | |
| Production and ad valorem taxes | 56,372 | | | 32,558 | | | 19,844 | |
| | | | | |
| Depletion | 121,071 | | | 102,987 | | | 100,501 | |
| Impairment | — | | | — | | | 69,202 | |
| General and administrative expenses | 8,542 | | | 7,800 | | | 8,165 | |
| | | | | |
| Total costs and expenses | 185,985 | | | 143,345 | | | 197,712 | |
| Income (loss) from operations | 680,482 | | | 361,572 | | | 52,914 | |
| Other income (expense): | | | | | |
| Interest expense, net | (40,409) | | | (34,044) | | | (33,000) | |
| | | | | |
| Gain (loss) on derivative instruments, net | (18,138) | | | (69,409) | | | (63,591) | |
| Gain (loss) on revaluation of investment | — | | | — | | | (8,556) | |
| Other income, net | 416 | | | 79 | | | 1,286 | |
| Total other expense, net | (58,131) | | | (103,374) | | | (103,861) | |
| Income (loss) before income taxes | 622,351 | | | 258,198 | | | (50,947) | |
| Provision for (benefit from) income taxes | (32,653) | | | 1,521 | | | 142,466 | |
| Net income (loss) | 655,004 | | | 256,677 | | | (193,413) | |
| Net income (loss) attributable to non-controlling interest | 503,331 | | | 198,738 | | | (1,109) | |
| Net income (loss) attributable to Viper Energy Partners LP | $ | 151,673 | | | $ | 57,939 | | | $ | (192,304) | |
| | | | | |
| Net income (loss) attributable to common limited partner units: | | | | | |
| Basic | $ | 2.00 | | | $ | 0.85 | | | $ | (2.84) | |
| Diluted | $ | 2.00 | | | $ | 0.85 | | | $ | (2.84) | |
| Weighted average number of common limited partner units outstanding: | | | | | |
| Basic | 75,612 | | | 68,319 | | | 67,686 | |
| Diluted | 75,679 | | 68,391 | | 67,686 |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands, except per unit amounts) |
| Operating income: | | | | | |
| Royalty income | $ | 160,163 |
| | $ | 78,837 |
| | $ | 74,859 |
|
| Lease bonus | 11,870 |
| | 309 |
| | — |
|
| Total operating income | 172,033 |
| | 79,146 |
| | 74,859 |
|
| Costs and expenses: | | | | | |
| Production and ad valorem taxes | 10,608 |
| | 5,544 |
| | 5,531 |
|
| Gathering and transportation | 789 |
| | 415 |
| | 259 |
|
| Depletion | 40,519 |
| | 29,820 |
| | 35,436 |
|
| Impairment | — |
| | 47,469 |
| | 3,423 |
|
| General and administrative expenses | 6,296 |
| | 5,209 |
| | 5,835 |
|
| Total costs and expenses | 58,212 |
| | 88,457 |
| | 50,484 |
|
| Income (loss) from operations | 113,821 |
| | (9,311 | ) | | 24,375 |
|
| Other income (expense): | | | | | |
| Interest expense, net | (3,164 | ) | | (2,455 | ) | | (1,110 | ) |
| Other income, net | 821 |
| | 867 |
| | 1,154 |
|
| Total other income (expense), net | (2,343 | ) | | (1,588 | ) | | 44 |
|
| Net income (loss) | $ | 111,478 |
| | $ | (10,899 | ) | | $ | 24,419 |
|
| | | | | | |
| Net income (loss) attributable to common limited partners per unit: | | | | | |
| Basic and Diluted | $ | 1.07 |
| | $ | (0.13 | ) | | $ | 0.31 |
|
| Weighted average number of limited partner units outstanding: | | | | | |
| Basic | 104,318 | | 83,081 | | 79,717 |
| Diluted | 104,383 | | 83,081 | | 79,727 |
See accompanying notes to consolidated financial statements.
Viper Energy Partners LP
Statement of Consolidated Unitholders’ Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Limited Partners | | General Partner | | Non-Controlling Interest | | |
| Common | | | | Class B | | | | Amount | | Amount | | |
| Units | | Amount | | Units | | Amount | | | | Total |
| (In thousands) |
| Balance at December 31, 2019 | 67,806 | | | $ | 929,116 | | | 90,710 | | | $ | 1,130 | | | $ | 889 | | | $ | 1,254,285 | | | $ | 2,185,420 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Unit-based compensation | — | | | 1,272 | | | — | | | — | | | — | | | — | | | 1,272 | |
| Vesting of restricted stock units | 56 | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | |
| Distribution equivalent rights payments | — | | | (44) | | | | | — | | | — | | | — | | | (44) | |
| Distributions to public | — | | | (45,630) | | | — | | | — | | | — | | | — | | | (45,630) | |
| Distributions to Diamondback | — | | | (498) | | | — | | | (99) | | | — | | | (61,685) | | | (62,282) | |
| Distributions to General Partner | — | | | — | | | — | | | — | | | (80) | | | — | | | (80) | |
| Change in ownership of consolidated subsidiaries, net | — | | | (34,087) | | | — | | | — | | | — | | | 34,087 | | | — | |
| Cash paid for tax withholding on vested common units | — | | | (384) | | | | | — | | | — | | | — | | | (384) | |
| Repurchased units as part of unit buyback | (2,045) | | | (24,026) | | | | | — | | | — | | | — | | | (24,026) | |
| Net income (loss) | — | | | (192,304) | | | — | | | — | | | — | | | (1,109) | | | (193,413) | |
| Balance at December 31, 2020 | 65,817 | | | 633,415 | | | 90,710 | | | 1,031 | | | 809 | | | 1,225,578 | | | 1,860,833 | |
| Unit-based compensation | — | | | 1,172 | | | — | | | — | | | — | | | — | | | 1,172 | |
| Common units issued for acquisition | 15,250 | | | 336,872 | | | — | | | — | | | — | | | — | | | 336,872 | |
| Vesting of restricted stock units | 92 | | | — | | | — | | | — | | | — | | | — | | | — | |
| Distribution equivalent rights payments | — | | | (193) | | | — | | | — | | | — | | | — | | | (193) | |
| Distributions to public | — | | | (75,749) | | | — | | | — | | | — | | | — | | | (75,749) | |
| Distributions to Diamondback | — | | | (803) | | | — | | | (100) | | | — | | | (99,782) | | | (100,685) | |
| Distributions to General Partner | — | | | — | | | — | | | — | | | (80) | | | — | | | (80) | |
| Change in ownership of consolidated subsidiaries, net | — | | | (93,473) | | | — | | | — | | | — | | | 93,473 | | | — | |
| Cash paid for tax withholding on vested common units | — | | | (20) | | | — | | | — | | | — | | | — | | | (20) | |
| Repurchased units as part of unit buyback | (2,613) | | | (45,999) | | | — | | | — | | | — | | | — | | | (45,999) | |
| Net income (loss) | — | | | 57,939 | | | — | | | — | | | — | | | 198,738 | | | 256,677 | |
| Balance at December 31, 2021 | 78,546 | | | 813,161 | | | 90,710 | | | 931 | | | 729 | | | 1,418,007 | | | 2,232,828 | |
| Unit-based compensation | — | | | 1,304 | | | — | | | — | | | — | | | — | | | 1,304 | |
| | | | | | | | | | | | | |
| Vesting of restricted stock units | 79 | | | — | | | — | | | — | | | — | | | — | | | — | |
| Distribution equivalent rights payments | — | | | (365) | | | — | | | — | | | — | | | — | | | (365) | |
| Distributions to public | — | | | (182,470) | | | — | | | — | | | — | | | — | | | (182,470) | |
| Distributions to Diamondback | — | | | (1,785) | | | — | | | (99) | | | — | | | (232,219) | | | (234,103) | |
| Distributions to General Partner | — | | | — | | | — | | | — | | | (80) | | | — | | | (80) | |
| Change in ownership of consolidated subsidiaries, net | — | | | 58,253 | | | — | | | — | | | — | | | (58,253) | | | — | |
| | | | | | | | | | | | | |
| Repurchased units as part of unit buyback | (5,395) | | | (150,593) | | | — | | | — | | | — | | | — | | | (150,593) | |
| Net income (loss) | — | | | 151,673 | | | — | | | — | | | — | | | 503,331 | | | 655,004 | |
| Balance at December 31, 2022 | 73,230 | | | $ | 689,178 | | | 90,710 | | | $ | 832 | | | $ | 649 | | | $ | 1,630,866 | | | $ | 2,321,525 | |
|
| | | | | | |
| | Limited Partners |
| | Common Units | | Amount |
| | (In thousands) |
| Balance at December 31, 2014 | 79,709 |
| | $ | 535,351 |
|
| Unit-based compensation | 17 |
| | 3,929 |
|
| Distribution to public | | | (7,968 | ) |
| Distribution to Diamondback | | | (60,587 | ) |
| Net income | | | 24,419 |
|
| Balance at December 31, 2015 | 79,726 |
| | $ | 495,144 |
|
| Net proceeds from the issuance of common units - public | 6,050 |
| | 93,462 |
|
| Net proceeds from the issuance of common units - Diamondback | 2,000 |
| | 31,200 |
|
| Unit-based compensation | 24 |
| | 3,815 |
|
| Distributions to public | | | (9,574 | ) |
| Distributions to Diamondback | | | (55,250 | ) |
| Net loss | | | (10,899 | ) |
| Balance at December 31, 2016 | 87,800 |
| | $ | 547,898 |
|
| Net proceeds from the issuance of common units - public | 25,175 |
| | 369,896 |
|
| Net proceeds from the issuance of common units - Diamondback | 700 |
| | 10,067 |
|
| Common units issued for acquisition | 175 |
| | 3,050 |
|
| Unit-based compensation | 32 |
| | 2,395 |
|
| Distributions to public |
| | (41,367 | ) |
| Distributions to Diamondback |
| | (89,509 | ) |
| Net income |
| | 111,478 |
|
| Balance at December 31, 2017 | 113,882 |
| | $ | 913,908 |
|
See accompanying notes to consolidated financial statements.
Viper Energy Partners LP
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands) |
| Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | 655,004 | | | $ | 256,677 | | | $ | (193,413) | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Provision for (benefit from) deferred income taxes | (49,656) | | | — | | | 142,466 | |
| Depletion | 121,071 | | | 102,987 | | | 100,501 | |
| Impairment | — | | | — | | | 69,202 | |
| (Gain) loss on derivative instruments, net | 18,138 | | | 69,409 | | | 63,591 | |
| Net cash receipts (payments) on derivatives | (31,319) | | | (92,585) | | | (36,998) | |
| | | | | |
| (Gain) loss on revaluation of investment | — | | | — | | | 8,556 | |
| | | | | |
| | | | | |
| Other | 5,070 | | | 4,710 | | | 3,589 | |
| Changes in operating assets and liabilities: | | | | | |
| | | | | |
| Royalty income receivable | (13,089) | | | (36,358) | | | 25,879 | |
| Royalty income receivable—related party | (4,116) | | | (146) | | | 8,578 | |
| Accounts payable and accrued liabilities | 151 | | | 2,744 | | | 5,023 | |
| Accounts payable—related party | 306 | | | — | | | (150) | |
| | | | | |
| | | | | |
| | | | | |
| Other | (1,764) | | | (324) | | | (268) | |
| Net cash provided by (used in) operating activities | 699,796 | | | 307,114 | | | 196,556 | |
| Cash flows from investing activities: | | | | | |
| | | | | |
| Acquisitions of oil and natural gas interests | (62,931) | | | (281,176) | | | (65,678) | |
| | | | | |
| | | | | |
| Proceeds from sale of oil and natural gas interests | 111,702 | | | — | | | 38,594 | |
| | | | | |
| Other | (1,200) | | | — | | | 10,801 | |
| Net cash provided by (used in) investing activities | 47,571 | | | (281,176) | | | (16,283) | |
| Cash flows from financing activities: | | | | | |
| Proceeds from borrowings under credit facility | 272,000 | | | 330,000 | | | 104,000 | |
| Repayment on credit facility | (424,000) | | | (110,000) | | | (116,500) | |
| | | | | |
| | | | | |
| Repayment of senior notes | (48,963) | | | — | | | (19,697) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Repurchased units as part of unit buyback | (150,593) | | | (45,999) | | | (24,026) | |
| Distributions to public | (182,835) | | | (75,942) | | | (45,674) | |
| Distributions to Diamondback | (234,103) | | | (100,685) | | | (62,282) | |
| Other | (142) | | | (2,985) | | | (575) | |
| Net cash provided by (used in) financing activities | (768,636) | | | (5,611) | | | (164,754) | |
| Net increase (decrease) in cash and cash equivalents | (21,269) | | | 20,327 | | | 15,519 | |
| Cash, cash equivalents and restricted cash at beginning of period | 39,448 | | | 19,121 | | | 3,602 | |
| Cash, cash equivalents and restricted cash at end of period | $ | 18,179 | | | $ | 39,448 | | | $ | 19,121 | |
| | | | | |
| Supplemental disclosure of cash flow information: | | | | | |
| Interest paid | $ | 36,868 | | | $ | 30,784 | | | $ | 33,121 | |
| Cash paid (received) for income taxes | $ | 16,990 | | | $ | 1,050 | | | $ | — | |
| Supplemental disclosure of non—cash transactions: | | | | | |
| | | | | |
| Common units issued for acquisition | $ | — | | | $ | 336,872 | | | $ | — | |
| | | | | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | 111,478 |
| | $ | (10,899 | ) | | $ | 24,419 |
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Depletion | 40,519 |
| | 29,820 |
| | 35,436 |
|
| Impairment | — |
| | 47,469 |
| | 3,423 |
|
| Amortization of debt issuance costs | 589 |
| | 401 |
| | 314 |
|
| Non-cash unit-based compensation | 2,395 |
| | 3,815 |
| | 3,929 |
|
| Changes in operating assets and liabilities: | | | | | |
| Restricted cash | 500 |
| | — |
| | — |
|
| Royalty income receivable | (15,711 | ) | | (4,144 | ) | | (1,130 | ) |
| Royalty income receivable—related party | (1,672 | ) | | — |
| | — |
|
| Accounts payable—related party | — |
| | (4 | ) | | 4 |
|
| Accounts payable and other accrued liabilities | 1,298 |
| | 1,945 |
| | (1,968 | ) |
| Other current assets | (177 | ) | | 224 |
| | (595 | ) |
| Net cash provided by operating activities | 139,219 |
| | 68,627 |
| | 63,832 |
|
| Cash flows from investing activities: | | | | | |
| Acquisition of mineral interests | (344,079 | ) | | (205,721 | ) | | (43,907 | ) |
| Net cash used in investing activities | (344,079 | ) | | (205,721 | ) | | (43,907 | ) |
| Cash flows from financing activities: | | | | | |
| Proceeds from borrowings under credit facility | 278,500 |
| | 164,000 |
| | 34,500 |
|
| Repayment on credit facility | (305,500 | ) | | (78,000 | ) | | — |
|
| Debt issuance costs | (2,259 | ) | | (442 | ) | | (441 | ) |
| Proceeds from public offerings | 380,412 |
| | 125,580 |
| | — |
|
| Public offering costs | (433 | ) | | (546 | ) | | — |
|
| Distributions to partners | (130,876 | ) | | (64,824 | ) | | (68,555 | ) |
| Net cash provided by (used in) financing activities | 219,844 |
| | 145,768 |
| | (34,496 | ) |
| Net increase (decrease) in cash | 14,984 |
| | 8,674 |
| | (14,571 | ) |
| Cash and cash equivalents at beginning of period | 9,213 |
| | 539 |
| | 15,110 |
|
| Cash and cash equivalents at end of period | $ | 24,197 |
| | $ | 9,213 |
| | $ | 539 |
|
| Supplemental disclosure of cash flow information: | | | | | |
| Interest paid | $ | 2,589 |
| | $ | 1,953 |
| | $ | 745 |
|
See accompanying notes to consolidated financial statements.
Viper Energy Partners LP
Notes to Consolidated Financial Statements
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership the common units of which are listedfocused on the Nasdaq Global Select Market under the symbol “VNOM”. The Partnership was formed by Diamondback Energy, Inc. (“Diamondback”), on February 27, 2014 to, among other things, own, acquireowning and exploitacquiring mineral interests and royalty interests in oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas propertiesprimarily in the Permian Basin. Unless the context requires otherwise, references to the “Partnership” are intended to mean the business and operations of Viper Energy Partners LP and its consolidated subsidiary, Viper Energy Partners LLC (the “Predecessor”).
As of December 31, 2017, a wholly-owned subsidiary of Diamondback,2022, Viper Energy Partners GP LLC (the “General Partner”), held a 100% non-economic general partner interest in the Partnership and Diamondback had an approximate 64%Energy, Inc. (“Diamondback”) beneficially owned approximately 56% of the Partnership’s total limited partner interest in the Partnership.units outstanding. Diamondback owns and controls the General Partner.
Basis of Presentation
The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). All material intercompany balances and transactions are eliminated in consolidation.
Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, unitholders’ equity, results of operations or cash flows.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
Certain amounts included in or affecting the Partnership’s 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 financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities atas of the date of the financial statements.
Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry given the challenges resulting from volatility in oil and natural gas prices. For instance, the effects of COVID-19, the war in Ukraine and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets continued to contribute to economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those involving financial forecasts.
The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in theeach particular circumstances.circumstance. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’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, but are not limited to, 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,interests, estimates of third party operated royalty income related to expected sales volumes and prices, the recoverability of costs of unevaluated properties, the fair value determination of assets and unit–based compensation.liabilities, including those acquired by the Partnership, fair value estimates of commodity derivatives and estimates of income taxes, including deferred tax valuation allowances.
Cash and Cash Equivalents
Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Partnership has not experienced any significant losses from such investments.
Restricted Cash
In 2014, the Predecessor entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The Predecessor subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. The parties reached a settlement of this matter in April 2017 and the funds were distributed in accordance with the terms of the settlement. Pending such distribution, these funds were classified as restricted cash.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
Royalty IncomeAccounts Receivable
Royalty incomeAccounts receivable consist of receivables from oil and natural gas sales delivered to purchasers. Those purchaserssales. The operators remit payment for production directly to the operator of the properties and the operator, in turn, remits payment to us. Some of the Partnership’s oil and natural gas properties are contractually operated by Diamondback.Partnership. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work which is required to be completed by the operator before payments are released.
Royalty incomeAccounts receivable are stated at amounts due from operators,purchasers, net of an allowance for doubtful accounts whenexpected losses as estimated by the Partnership believeswhen collection is deemed doubtful. Royalty incomeAccounts receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines anyits allowance by consideringutilizing the loss-rate method, which considers a number of factors, including the length of time royalty income receivable are past due, the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to us,the Partnership, the condition of the general economy and the industry as a whole. The Partnership writes off specific royalty incomeaccounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. expected losses. At December 31, 2022 and December 31, 2021, the Partnership’s allowance for expected losses was immaterial.
Derivative Instruments
The Partnership determined that an allowance was unnecessaryis required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at both December 31, 2017fair 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 2016.
Fair Value of Financial Instruments
Our financialresulting designation. The Partnership has not designated its derivative instruments consist ofas hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and cash equivalents, receivables, payablesnon-cash change in fair value on derivative instruments for each period in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”
Revenue from Contracts with Customers
Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a credit agreement. royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.
Royalty income from oil, natural gas and natural gas liquids sales
The carryingPartnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.
Transaction price allocated to remaining performance obligations
The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of our royalty income contracts.
Contract balances
Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
Prior-period performance obligations
The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, 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 Partnership is required to estimate the amount of cashroyalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and cash equivalents, receivablesthe actual amounts received for royalties in the month that payment is received from the producer. Any identified differences between its revenue estimates and payables approximates fair valueactual revenue received historically have not been significant. The Partnership 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 short-term nature of the instruments.royalties related to expected sales volumes and prices for those properties are estimated and recorded.
Oil and Natural Gas Properties
The Partnership 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 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 not directly associated with exploration and development activities were charged to expense as they were 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. At December 31, 20172022 and 2016,2021, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties.
Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $10.07, $12.67$9.86, $10.04 and $17.88$10.34 for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively. Depletion for oil and natural gas properties was $40.5$121.1 million, $29.8$103.0 million and $35.4$100.5 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively.
Under the full cost method of accounting, the Partnership 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.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 writedownwrite-down is required. During the years ended December 31, 2016See Note 5—Oil and 2015, the Partnership recorded impairments on provedNatural Gas Interests for additional discussion of our oil and natural gas properties of $47.5 million and $3.4 million, respectively. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017.properties.
Costs associated with unevaluated properties are excluded from the full cost pool until the Partnership has made a determination as to the existence of proved reserves. The Partnership assesses all items classified as unevaluated property on an annual basisat least annually for possible impairment. The Partnership 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 of the operator to drill; remaining lease term;term with the current operator; 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
Viper Energy Partners LP
Notes to Financial Statements - (Continued)
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.
Debt Issuance Costs
Other assets include capitalized costs related to the credit facility of $4.4 million, $2.2$9.7 million and $1.7$9.6 million, net ofand accumulated amortization of $1.4 million, $0.8those costs over the term of the credit agreement of $9.5 million and $0.4$6.8 million as of December 31, 2017, 20162022, and 2015,2021, respectively.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
Long-term debt includes insignificant capitalized costs related to the Partnership’s 5.375% senior notes due 2027 (the “Notes”). The costs are associated with the Partnership’s credit agreement andNotes are being netted against the Notes balances and amortized over the term of the credit agreement.Notes using the effective interest method. See Note 6—Debt for further details.
Royalty InterestRelated Party Transactions
During the year ended December 31, 2022, Diamondback, either directly or through its consolidated subsidiaries, paid the Partnership $23.4 million of lease bonus income primarily related to lease ratification and Revenue Recognitioncertain leases acquired in the Swallowtail Acquisition. During the year ended December 31, 2021, Diamondback, either directly or through its consolidated subsidiaries, paid the Partnership $1.3 million of lease bonus income related to two new leases.
Royalty interest representsAccrued Liabilities
The Company’s accrued liabilities are financial instruments for which the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when title passes to the purchaser.carrying value approximates fair value.
Royalty interest has no rights or obligations to explore, develop or operate the property and does not incur anyAccrued liabilities consist of the costs of exploration, developmentfollowing at December 31, 2022, and operation of the property.2021:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| (In thousands) |
| Interest payable | $ | 3,972 | | | $ | 4,430 | |
| Ad valorem taxes payable | 12,492 | | | 6,201 | |
| Derivatives instruments payable | 1,684 | | | 8,879 | |
| Other | 1,452 | | | 999 | |
| Total accrued liabilities | $ | 19,600 | | | $ | 20,509 | |
Concentrations
The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty interest revenuesincome in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2017,2022, two purchasers each accounted for more than 10% of royalty income: Shell Trading (US) Company (14%) and Vitol Midstream Pipeline LLC (14%). For the year ended December 31, 2021, three purchasers each accounted for more than 10% of royalty income: Trafigura Trading LLC (17%), Shell Trading (US) Company (16%) and Vitol Midstream Pipeline LLC (12%). For the year ended December 31, 2020, four purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (23%), Vitol Midstream Pipeline LLC (14%), Shell Trading (US) Company (“Shell Trading”) (47%(13%) and RSP Permian LLC (23%). For the year ended December 31, 2016, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (57%) and RSP Permian LLC (32%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (68%) and RSP Permian LLC (25%Concho Resources (11%). The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact the Partnership’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
Investments
The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over partnership operating and financial policies. This interest was acquired during the year ended December 31, 2014 and is accounted for under the cost method. Under the cost method, investments are carried at cost and are adjusted only for other than temporary declines in fair value, certain distributions and additional investments. As of December 31, 2017, the book value of this investment was $33.9 million, which is included in other assets in the accompanying consolidated balance sheets.
Earnings Per Unit
Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.
Unit–Based Compensation
Unit–based compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. See Note 7—Unit–Based Compensation.
Income Taxes
The Partnership is organized as a pass-through entityuses the asset and liability method of accounting for income taxes, under which deferred tax purposes. Asassets 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 result,change in tax rates on deferred tax assets and liabilities is recognized in income in the Partnership’s partners are responsibleperiod the rate change is enacted. A valuation allowance is provided for federal income taxes on their share ofdeferred tax assets when it is more likely than not the Partnership’s taxable income.deferred tax assets will not be realized.
The Partnership is subjectcontinuing its practice of recognizing interest and penalties related to the Texas margin tax. Diamondback does not expect any Texas marginincome tax to be due formatters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2017, 20162022, 2021 and 2015, so2020, there was no amount has been providedinterest or penalties associated with uncertain tax positions recognized in the accompanyingPartnership’s consolidated financial statements. See Note 9—Income Taxes for further details.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
Non-controlling Interest
New Accounting Pronouncements
Recently Issued Pronouncements
In May 2014,Non-controlling interest in the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes mostaccompanying consolidated financial statements represents Diamondback’s ownership in the net assets of the existing revenue recognition requirementsOperating Company. When Diamondback’s relative ownership interest in GAAPthe Operating Company changes, adjustments to non-controlling interest and requires (i) an entity to recognize revenue when it transfers promised goods or services to customerscommon unitholder equity, tax effected, will occur. Because these changes in an amount that reflects the consideration to whichPartnership’s ownership interest in the entity expects to be entitled toOperating Company did not result in exchange for those goods or services and (ii) requires expanded disclosures regardinga change of control, the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers.
The Partnership will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Partnership has reviewed various contracts that represent its material revenue streams and determined that there will be no impact to its financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, the Partnership will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, the Partnership will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Partnership. The Partnership does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams as compared to existing GAAP.
In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for thosetransactions were accounted for
as equity transactions under
ASC Topic 810, “Consolidation.” This guidance requires that any differences between the
equity method or those that result in consolidationcarrying value of the
investee) to be measured at fair value with changesPartnership’s basis in
fair value recognized in net income. The Partnership will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equitythe Operating Company and
will bring the fair value of
its investmentthe consideration received are recognized directly in equity and attributed to
$15.2 million or $15.20 per unitthe controlling interest. See Note 7—Unitholders' Equity and Distributions for that investment.further discussion of changes in ownership interest.
Recent Accounting Pronouncements
Recently Adopted Pronouncements
In November 2016,December 2022, the Financial Accounting Standards BoardFASB issued Accounting Standards Update 2016-18, “StatementASU 2022-06, "Reference Rate Reform (Topic 848) – Deferral of Cash Flows - Restricted Cash”.the Sunset Date of Topic 848.” This update affects entities that have restricted cash or restricted cash equivalents.extended the use of the optional expedient through December 31, 2024. The Partnership will adoptCompany adopted this update retrospectively effective January 1, 2018.December 31, 2022. The adoption of this update will only effect the presentation on the Statement of Cash Flows.
In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Partnership will adopt this update prospectively effective January 1, 2018. The adoption of this update willdid not have ana material impact on its financial position, results of operations or liquidity.
Accounting Pronouncements Not Yet Adopted
In February 2016,The Partnership considers the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update appliesapplicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable, previously disclosed, or not material upon adoption.
3. REVENUE FROM CONTRACTS WITH CUSTOMERS
Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognizedeductions for gathering and transportation. Virtually all of the pricing provisions in the statement of financial positionPartnership’s contracts are tied to a liability to make lease payments (the lease liability)market index.
For the years ended December 31, 2022, 2021 and a right-of-use asset representing its right to use2020, any revenues recognized in the underlying assetcurrent reporting period for performance obligations satisfied in prior reporting periods was not material.
The following table disaggregates the lease term. While there were no major changes toPartnership’s total royalty income by product type:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands) |
| Oil income | $ | 667,281 | | | $ | 397,513 | | | $ | 217,859 | |
| Natural gas income | 83,149 | | | 49,197 | | | 9,024 | |
| Natural gas liquids income | 87,546 | | | 54,824 | | | 20,098 | |
| Total royalty income | $ | 837,976 | | | $ | 501,534 | | | $ | 246,981 | |
4. ACQUISITIONS AND DIVESTITURES
2022 Activity
Acquisitions
During the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning afteryear ended December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of the filing date,31, 2022, in individually insignificant transactions, the Partnership was notacquired from unrelated third-party sellers mineral and royalty interests representing 375 net royalty acres in the lessor or lesseePermian Basin for an aggregate net purchase price of any leases other than mineral leases which were excluded fromapproximately $65.9 million, including certain customary closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the scope of this Accounting Standards Update. Therefore, the Partnership believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.
In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 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 sheetOperating Company’s revolving credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have
facility.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
Divestitures
In the contractual rightfirst quarter of 2022, the Partnership divested 325 net royalty acres of third party operated acreage located entirely in Upton and Reagan counties in the Midland Basin for an aggregate net sales price of $29.3 million, including customary closing adjustments.
In the third quarter of 2022, the Partnership divested 93 net royalty acres of third party operated acreage located entirely in Loving county in the Delaware Basin for an aggregate net sales price of $29.9 million, including customary closing adjustments.
In the fourth quarter of 2022, the Partnership divested its entire position in the Eagle Ford Shale consisting of 681 net royalty acres of third party operated acreage for an aggregate net sales price of $53.8 million, including certain customary closing adjustments.
2021 Acquisitions
Swallowtail Acquisition
On October 1, 2021, the Partnership and the Operating Company acquired certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC (the “Swallowtail entities”) pursuant to receive cash. This update will bea definitive purchase and sale agreement for approximately 15.25 million common units and approximately $225.3 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent 2,313 net royalty acres primarily in the Northern Midland Basin, of which 62% are operated by Diamondback. The Swallowtail Acquisition had an effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applieddate of August 1, 2021. The cash portion of this transaction was funded through a cumulative-effect adjustment to retained earnings ascombination of cash on hand and approximately of $190.0 million borrowings under the beginningOperating Company’s revolving credit facility.
Other 2021 Acquisitions
Additionally during the year ended December 31, 2021, the Partnership acquired, from unrelated third party sellers, mineral and royalty interests representing 1,277 gross (392 net royalty) acres in the Permian Basin for an aggregate purchase price of the first reporting period in which the guidance is effective.approximately $55.1 million, after post-closing adjustments. The Partnership does not believefunded these acquisitions with cash on hand and borrowings under the adoption of this standard will have an impact on its financial statements since it does not have a history ofOperating Company’s revolving credit losses.facility.
3. ACQUISITIONS
2017 Activity
During the year ended December 31, 2017,2020, the Partnership acquired, from unrelated third party sellers, mineral and royalty interests underlying 3,157representing 4,948 gross (417 net royaltyroyalty) acres in the Permian Basin for an aggregate purchase price of approximately $343.1$64.2 million, and, as of December 31, 2017, had mineral interests underlying 9,570 net royalty acres.after post-closing adjustments. The Partnership funded these acquisitions primarily with borrowings under its revolving credit facility, with a portion of the net proceeds from its Januarycash on hand and July 2017 offerings of common units and with the issuance of 174,513 common units to a seller in a private placement in May 2017.
2016 Activity
During the year ended December 31, 2016, the Partnership acquired mineral interests underlying 2,142 net royalty acres in 63 transactions for an aggregate of approximately $205.7 million. The Partnership funded these acquisitions primarily with borrowings under its revolving credit facility and a portion of the net proceeds from its August 2016 offering of common units.
2015 Activity
During the year ended December 31, 2015, the Partnership acquired an approximate average 1.5% overriding royalty interest in certain acreage primarily located in Howard County, Texas from Diamondback for $31.1 million. This acquisition was primarily funded with borrowings under the Partnership’sOperating Company’s revolving credit agreement discussed in Note 5.facility.
4.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
5. OIL AND NATURAL GAS INTERESTS
Oil and natural gas interests include the following:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| (In thousands) |
| Oil and natural gas interests: | | | |
| Subject to depletion | $ | 2,167,598 | | | $ | 1,873,418 | |
| Not subject to depletion | 1,297,221 | | | 1,640,172 | |
| Gross oil and natural gas interests | 3,464,819 | | | 3,513,590 | |
| Accumulated depletion and impairment | (720,234) | | | (599,163) | |
| Oil and natural gas interests, net | 2,744,585 | | | 2,914,427 | |
| Land | 5,688 | | | 5,688 | |
| Property, net of accumulated depletion and impairment | $ | 2,750,273 | | | $ | 2,920,115 | |
| | | |
| Balance of costs not subject to depletion: | | | |
| Incurred in 2022 | $ | 37,456 | | | |
| Incurred in 2021 | 478,747 | | | |
| Incurred in 2020 | 55,041 | | | |
| Prior | 725,977 | | | |
| Total not subject to depletion | $ | 1,297,221 | | | |
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (in thousands) |
| Oil and natural gas interests: | | | |
| Subject to depletion | $ | 589,173 |
| | $ | 508,586 |
|
| Not subject to depletion | 514,724 |
| | 252,232 |
|
| Gross oil and natural gas interests | 1,103,897 |
| | 760,818 |
|
| Accumulated depletion and impairment | (189,466 | ) | | (148,948 | ) |
| Oil and natural gas interests, net | $ | 914,431 |
| | $ | 611,870 |
|
| | | | |
| Balance of costs not subject to depletion: | | | |
| Incurred in 2017 | $ | 284,471 |
| | |
| Incurred in 2016 | 158,156 |
| | |
| Incurred in 2015 | 30,896 |
| | |
| Incurred in 2014 | 41,201 |
| | |
| Total not subject to depletion | $ | 514,724 |
| | |
As of December 31, 2022 and December 31, 2021, the Partnership had mineral and royalty interests representing 26,315 and 27,027 net royalty acres, respectively.
Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able tocan be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within threeeight to fiveten years.
Viper Energy Partners LP
Notes to Financial Statements - (Continued)
Under the full cost method of accounting,quarterly ceiling tests, the Partnership iswas not required to perform a ceiling test each quarter. The test determines a limit, or ceiling,record an impairment on the book value of theour proved oil and gas interests. Net capitalized costs are limited to the lower of unamortized cost 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 or financial derivatives, if any, that hedge the Partnership’s oil and natural gas revenue, (b)interests for the cost of interests not being amortized, if any,years ended December 31, 2022 and (c) the lower of cost or market value of unproved interests included in the cost being amortized. If the net book value exceeds the ceiling,2021, respectively. The Partnership recorded an impairment or non-cash write down is required.
Asexpense of $69.2 million as a result of the decline in commodity prices the Partnership recorded non-cash impairments for the years ended December 31, 2016 and 2015 of $47.5 million and $3.4 million, respectively, which are included in accumulated depletion and impairment. There was no impairment recorded for the year ended December 31, 2017. For 2016 and 2015, the impairment charges affected the Partnership’s reported net loss but did not reduce its cash flow.2020. In addition to commodity prices, the Partnership’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods.If the trailing 12-month commodity prices were to fall as compared to the commodity prices used in prior quarters, the Partnership will have write-downs in subsequent quarters, which may be material.
5.6. DEBT
Credit Agreement-Wells Fargo BankLong-term debt consisted of the following as of the dates indicated:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| (In thousands) |
| 5.375% senior unsecured notes due 2027 | $ | 430,350 | | | $ | 479,938 | |
| Revolving credit facility | 152,000 | | | 304,000 | |
| Unamortized debt issuance costs | (1,306) | | | (1,757) | |
| Unamortized discount | (4,149) | | | (5,454) | |
| Total long-term debt | $ | 576,895 | | | $ | 776,727 | |
On July 8, 2014,
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
Repurchases of Notes
During the year ended December 31, 2022, the Partnership entered intorepurchased an aggregate $49.6 million principal amount of the outstanding Notes for total cash consideration of $49.0 million, which resulted in an immaterial loss on extinguishment of debt after including accrued interest and the write-off of related unamortized costs. The Partnership funded the debt repurchases through a securedcombination of cash on hand and borrowings under the Operating Company’s revolving credit agreement with Wells Fargo,facility.
The Operating Company’s Revolving Credit Facility
The Operating Company, as administrative agent,borrower, and Wells Fargo Securities,the Partnership, as sole book runner and lead arranger. Theparent guarantor, maintain a credit agreement, as amended, which provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base of $580.0 million. As of December 31, 2022, the Operating Company had elected a commitment amount of $500.0 million, with $152.0 million of outstanding borrowings and $348.0 million available for future borrowings under the Operating Company’s revolving credit facility. For the years ended December 31, 2022, 2021 and 2020, the weighted average interest rate on borrowings under the Operating Company’s revolving credit facility was 4.22%, 2.35%, and 2.20%, respectively.
On November 18, 2022, the Operating Company entered into the ninth amendment to the existing credit agreement, which, among other things, (i) maintained the maximum amount of the revolving credit facility at $2.0 billion, (ii) reaffirmed the borrowing base of $580.0 million based on itsthe Operating Company’s oil and natural gas reserves and other factors, (the “borrowing base”) of $400.0 million, subject(iii) maintained the Operating Company’s ability to scheduled semi-annual and other electiveelect a commitment amount that is less than its borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annuallyas determined by the lenders, and (iv) replaced the London interbank offered rate benchmark with effective dates of May 1st and November 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $400.0 million, and the Partnership had $93.5 million of outstanding borrowings and $306.5 million available for future borrowings under its revolving credit facility.secured overnight financing rate (“SOFR”).
The outstanding borrowings under the credit agreement bear interest at a rate elected by the PartnershipOperating Company that is equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”) or (ii) an alternativealternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 3-month LIBOR1-month Adjusted Term SOFR plus 1.0%1.00%) or LIBOR,, in each case plus the applicable margin. The applicable margin ranges from 0.75%1.00% to 1.75%2.00% per annum in the case of the alternative base rate and from 1.75%2.00% to 2.75%3.00% per annum in the case of LIBOR,Adjusted Term SOFR, in each case depending on the amount of the loans and letters of credit outstanding in relation to the commitment, which is defined ascalculated using the lesserleast of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. The PartnershipOperating Company 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 ofcommitment. The 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 (a) 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), (b) 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 (c) at the maturity date of November 1, 2022. The loan is secured by substantially all the assets of ourthe Partnership and our subsidiary’s assets.the Operating Company. The Partnership applied the optional expedient in ASU 2020-04, “Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting” for this contract modification, which did not have an impact on its financial position, results of operations or liquidity.
The 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, excess cash and entering into certain swap agreements and require the maintenance of the financial ratios described below.
|
| | | | | | | |
| Financial Covenant | | Required Ratio |
| Ratio of total net debt to EBITDAX, as defined in the credit agreement | Not greater than 4.0 to 1.0 |
| Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
| Ratio of secured debt to EBITDAX, as defined in the credit agreement | Not greater than 2.5 to 1.0 |
As of December 31, 2022, the Operating Company was in compliance with all financial maintenance covenants under its credit agreement.
7. UNITHOLDERS’ EQUITY AND DISTRIBUTIONS
The covenant prohibiting additional indebtedness allowsPartnership has General Partner and limited partner units. At December 31, 2022, the Partnership had a total of 73,229,645 common units issued and outstanding and 90,709,946 Class B units issued and outstanding, of which 731,500 common units and 90,709,946 Class B units were beneficially owned by Diamondback, representing approximately 56% of the Partnership’s total units outstanding. Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 55% non-controlling ownership interest in the Operating Company. The Operating Company units and the Partnership’s Class B units beneficially owned by Diamondback are exchangeable from time to time for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notesPartnership’s common units (that is, one Operating Company unit 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 toone Partnership Class B unit, together, will be repaid.exchangeable for one Partnership common unit).
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
Common Unit Repurchase Program
The board of directors of the Partnership’s General Partner has approved a common unit repurchase program to acquire up to $750.0 million of the Partnership’s outstanding common units over an indefinite period of time. The Partnership intends to purchase common units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of the Partnership’s General Partner at any time.During the years ended December 31, 2022, 2021 and 2020, the Partnership repurchased approximately $150.6 million, $46.0 million, and $24.0 million of common units under the repurchase program, respectively. As of December 31, 2017,2022, $529.4 million remains available for use under the Partnership wasrepurchase program.
Changes in compliance with allOwnership of Consolidated Subsidiaries
Non-controlling interest in the accompanying consolidated financial covenants under its credit agreement. The lenders may accelerate allstatements represents Diamondback’s ownership in the net assets of the indebtedness under our revolving credit facility uponOperating Company. Diamondback’s relative ownership interest in 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 andOperating Company can change of control. With certain specified exceptions, the terms and provisions ofdue to the Partnership’s credit agreement generally may be amended with the consentpublic offerings, issuance of the lenders holding a majorityunits for acquisitions, issuance of the outstanding loans or commitments to lend.
6. RELATED PARTY TRANSACTIONS
Acquisition
During the year ended December 31, 2015, the Partnership acquired an approximate average 1.5% overriding royalty interest in certain acreage primarily located in Howard County, Texas from Diamondback for $31.1 million. This acquisition was primarily funded with borrowings under the Partnership’s credit agreement discussed in Note 5.
Partnership Agreement
In connection with the closingunit-based compensation, repurchases of the IPO, the General Partnercommon units and Diamondback entered into the first amended and restated agreement of limited partnership dated June 23, 2014 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred ordistribution equivalent rights paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partnerunits. These changes in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on the Partnership’s behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For the year ended December 31, 2017, the General Partner received from the Partnership reimbursements of $2.5 million. For the year ended December 31, 2016, the General Partner did not receive any reimbursements from the Partnership. For the year ended December 31, 2015, the General Partner did not receive any reimbursements from the Partnership other than the $4,000 outstanding at December 31, 2014.
Advisory Services Agreement
In connection with the closing of the IPO, the Partnership and General Partner entered into an advisory services agreement with Wexford Capital LP (“Wexford”) dated as of June 23, 2014 (the “Advisory Services Agreement”), under which Wexford agreed to provide the Partnershipownership percentage and the General Partner with general financialdisproportionate allocation of net income (loss) to Diamondback discussed belowresult in adjustments to non-controlling interest and strategic advisory services relatedcommon unitholder equity, tax effected, but do not impact earnings.
The following table summarizes the changes in common unitholder equity due to changes in ownership interest during the Partnership’s business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. period:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands) |
| Net income (loss) attributable to the Partnership | $ | 151,673 | | | $ | 57,939 | | | $ | (192,304) | |
| | | | | |
| Change in ownership of consolidated subsidiaries | 58,253 | | | (93,473) | | | (34,087) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest | $ | 209,926 | | | $ | (35,534) | | | $ | (226,391) | |
Cash Distributions
The Advisory Services Agreement had an initial term of two years commencing on June 23, 2014, and continues for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Partnership terminates the Advisory Services Agreement, the Partnership is obligated to pay all amounts due through the remaining term. In addition, the Partnership agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of the General Partner if,has established a distribution policy, as amended, whereby the Operating Company distributes all or a portion of its available cash on a quarterly basis to its unitholders (including Diamondback and to the extent, the Partnership requests services from Wexford in connection with acquisitions and divestitures, financings or other transactions in which the Partnership may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Partnership’s day-to-day business or operations.Partnership). The Partnership has agreed to indemnify Wexford and its affiliates from their losses arising out ofin turn distributes all or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. For the years ended December 31, 2017 and 2016, the Partnership did not pay any amounts under the Advisory Services Agreement. For the year ended December 31, 2015, the Partnership paid $0.5 million under the Advisory Services Agreement.
Tax Sharing
In connection with the closinga portion of the IPO,available cash it receives from the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuantOperating Company to whichits common unitholders. The Partnership’s available cash and the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax
Viper Energy Partners LP
Notes to Financial Statements - (Continued)
attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period.
Lease Bonus
During the year ended December 31, 2017, Diamondback paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre. During the year ended December 31, 2016, Diamondback paid the Partnership $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.
7. UNIT–BASED COMPENSATION
In connection with the IPO, the board of directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“LTIP”), effective June 17, 2014,Operating Company for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The 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. A total of 9,070,356 common units has been reserved for issuance pursuant to the LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIPeach quarter is administereddetermined by the board of directors of the General Partner or a committee thereof.
Forfollowing the years ended December 31, 2017, 2016 and 2015, the Partnership incurred $2.4 million, $3.8 million and $3.9 million, respectively, of unit–based compensation.
Unit Options
In accordance with the LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the LTIP will consist of new common units of the Partnership. On June 17, 2014, the Partnership granted 2,500,000 unit options to the executive officers of the General Partner. The unit options vested approximately 33% ratably on each of the first three anniversaries of the date of grant. All outstanding unit options were amended effective November 29, 2016 to provide that vested unit options became exercisable upon the earlier to occur of (i) the “Exercise Window Period” beginning on the third anniversary of the date of grant and ending on December 31, 2017, or (ii) the “Change of Control Exercise Period” beginning ten days before and ending on the date a change of control occurs (the earlier occurringend of such events,quarter. The cash available for distribution by the “Exercise Period”). At any time withinOperating Company, a non-GAAP measure, generally equals the Exercise Period, if a participant attempted to exercise a vested unit option and the fair market value per unit as of such date was less than the exercise price per option unit, the vested unit option would not be exercisable. As of December 31, 2017, all vested unit options automatically terminated and became null and void.
The fair value of the unit options on the date of grant is expensed overPartnership’s consolidated Adjusted EBITDA for the applicable vesting period. The Partnership estimates the fair values of unit options granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant the Partnership did not have a history of market prices, thus the expected volatility was determined using the historical volatilityquarter, less cash needed for a peer group of companies. The expected term of options granted was determined based on theincome taxes payable, debt service, contractual term of the awards. The risk-free interest rate is based on the U.S. treasury yield curve rateobligations, fixed charges and reserves for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership.
|
| | | |
| | 2014 |
| Grant-date fair value | $ | 4.24 |
|
| Expected volatility | 36.0 | % |
| Expected dividend yield | 5.9 | % |
| Expected term (in years) | 3.0 |
|
| Risk-free rate | 0.99 | % |
Viper Energy Partners LP
Notes to Financial Statements - (Continued)
The following table presents the unit option activity under the LTIP for the year ended December 31, 2017:
|
| | | | | | | | | | | | |
| | | | Weighted Average | | |
| | Unit
Options | | Exercise
Price | | Remaining
Term | | Intrinsic
Value |
| | | | | | (in years) | | (in thousands) |
| Outstanding at December 31, 2016 | 2,424,266 |
| | $ | 26.00 |
| | | | |
| Expired/Forfeited | (2,416,666 | ) | | $ | 26.00 |
| | | | |
| Outstanding at December 31, 2017 | 7,600 |
| | $ | 18.49 |
| | 0.00 | | $ | — |
|
| Vested and Expected to Vest at December 31, 2017 | 7,600 |
| | $ | 18.49 |
| | 0.00 | | $ | — |
|
Phantom Units
Under the LTIP,future operating or capital needs that the board of directors of the General Partner is authorized to issue phantom units to eligible employees.deems necessary or appropriate, lease bonus income, distribution equivalent rights payments and preferred distributions, if any. The Partnership estimatesPartnership’s cash available for distribution for each quarter generally equals the fair value of phantom units as the closing pricePartnership’s proportional share of the Partnership’s common units oncash distributed by the grant date ofOperating Company for the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient to one common unit ofquarter, less cash needed by the Partnership for each phantom unit.
The following table presents the phantom unit activity underpayment of income taxes, if any, and the LTIP forpreferred distribution. Further, in July 2022, the year ended December 31, 2017:
|
| | | | | | |
| | Phantom
Units | | Weighted Average
Grant-Date
Fair Value |
| Unvested at December 31, 2016 | 21,048 |
| | $ | 16.23 |
|
| Granted | 116,567 |
| | $ | 17.09 |
|
| Vested | (32,176 | ) | | $ | 16.49 |
|
| Unvested at December 31, 2017 | 105,439 |
| | $ | 17.10 |
|
The aggregate fair value of phantom units that vested during the year ended December 31, 2017 was $0.5 million. As of December 31, 2017, the unrecognized compensation cost related to unvested phantom units was $1.3 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.
8. PARTNERS’ CAPITAL AND PARTNERSHIP DISTRIBUTIONS
The Partnership has general partner and common unit partnership interests. The general partner interest is a non-economic interest and is not entitled to any cash distributions.
At December 31, 2017, the Partnership had a total of 113,882,045 common units issued and outstanding, of which 73,150,000 common units were owned by Diamondback, representing approximately 64% of the total Partnership units outstanding.
The following table summarizes changes in the number of the Partnership’s common units:
|
| | |
| Common Units |
Balance at December 31, 2016 | 87,800,356 |
|
Common units issued in public offerings | 25,875,000 |
|
Common units vested and issued under the LTIP | 32,176 |
|
Common units issued for acquisition | 174,513 |
|
Balance at December 31, 2017 | 113,882,045 |
|
The board of directors of the General Partner has adoptedapproved a distribution policy, effective with the Partnership’s distribution payable for the third quarter of 2022, consisting of a base and variable distribution, that takes into account capital returned to unitholders via our common unit repurchase program. The board of directors updated the distribution policy in November 2022, providing that lease bonus payments and other similar, one-time, non-recurring payments will be excluded from the calculation of the Partnership’s and the Operating Company’s available cash.
The percentage of cash available for distribution pursuant to the distribution policy discussed above may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet while also expanding the return of capital program through the Partnership’s common unit repurchase program. The Partnership is not required to distribute all available cash generatedpay distributions to its common unitholders on a quarterly basis, beginning withor other basis.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
The following table presents information regarding cash distributions paid during the quarter ending September 30, 2014. years ended December 31, 2022, 2021 and 2020 (in thousands, except for per share amounts):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Period | | Amount per Operating Company Unit | | Operating Company Distributions to Diamondback | | Amount per Common Unit | | Common Unitholders(1) | | Declaration Date | | Unitholder Record Date | | Payment Date | | |
| | Q4 2019 | | $ | 0.45 | | | $ | 40,819 | | | $ | 0.45 | | | $ | 30,543 | | | February 7, 2020 | | February 21, 2020 | | February 28, 2020 | | |
| | Q1 2020 | | $ | 0.10 | | | $ | 9,074 | | | $ | 0.10 | | | $ | 6,790 | | | April 30, 2020 | | May 14, 2020 | | May 21, 2020 | | |
| | Q2 2020 | | $ | 0.03 | | | $ | 2,720 | | | $ | 0.03 | | | $ | 2,034 | | | July 29, 2020 | | August 13, 2020 | | August 20, 2020 | | |
| | Q3 2020 | | $ | 0.10 | | | $ | 9,072 | | | $ | 0.10 | | | $ | 6,805 | | | October 28, 2020 | | November 12, 2020 | | November 19, 2020 | | |
| | Q4 2020 | | $ | 0.14 | | | $ | 12,699 | | | $ | 0.14 | | | $ | 9,162 | | | February 19, 2021 | | March 4, 2021 | | March 11, 2021 | | |
| | Q1 2021 | | $ | 0.25 | | | $ | 22,678 | | | $ | 0.25 | | | $ | 16,230 | | | April 27, 2021 | | May 13, 2021 | | May 20, 2021 | | |
| | Q2 2021 | | $ | 0.33 | | | $ | 29,936 | | | $ | 0.33 | | | $ | 21,235 | | | July 28, 2021 | | August 12, 2021 | | August 19, 2021 | | |
| | Q3 2021 | | $ | 0.38 | | | $ | 34,469 | | | $ | 0.38 | | | $ | 30,118 | | | October 27, 2021 | | November 11, 2021 | | November 18, 2021 | | |
| | Q4 2021 | | $ | 0.47 | | | $ | 42,634 | | | $ | 0.47 | | | $ | 36,238 | | | February 16, 2022 | | March 4, 2022 | | March 11, 2022 | | |
| | Q1 2022 | | $ | 0.70 | | | $ | 63,497 | | | $ | 0.67 | | | $ | 51,680 | | | April 27, 2022 | | May 12, 2022 | | May 19, 2022 | | |
| | Q2 2022 | | $ | 0.87 | | | $ | 78,918 | | | $ | 0.81 | | | $ | 60,626 | | | July 26, 2022 | | August 16, 2022 | | August 23, 2022 | | |
| | Q3 2022 | | $ | 0.52 | | | $ | 47,170 | | | $ | 0.49 | | | $ | 36,076 | | | November 3, 2022 | | November 17, 2022 | | November 25, 2022 | | |
| | | | | | | | | | | | | | | | | | |
(1)Includes amounts paid to Diamondback for the 731,500 common units beneficially owned by Diamondback and distribution equivalent rights payments.
Cash distributions arewill be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter is determined by the board
Allocation of directors of our general partner following the end of such quarter. Available cash for each quarter generally equals Adjusted EBITDA reduced for cash needed for debt service and other contractual obligations and fixedNet Income
Viper Energy Partners LP
Notes to Financial Statements - (Continued)
charges and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any.
The following table presents cash distributions approved by the board of directorsPartnership, as managing member of the General Partner forOperating Company, had an agreement, as amended on December 28, 2021, whereby special allocations of the periods presented.Operating Company’s income and gains over losses and deductions (but before depletion) were made to Diamondback through December 31, 2022. These special income allocations reduced the taxable income allocated to the Partnership’s common unitholders during the reporting periods.
|
| | | | | | | | | | | | |
| Declaration Date | | Quarter | | Amount per Common Unit | | Payment Date | | Amount Distributed to Diamondback |
| | | | | | | | | (in thousands) |
| February 5, 2015 | | Q4 2014 | | $ | 0.250 |
| | February 27, 2015 | | $ | 17,612 |
|
| May 1, 2015 | | Q1 2015 | | $ | 0.189 |
| | May 22, 2015 | | $ | 13,385 |
|
| July 31, 2015 | | Q2 2015 | | $ | 0.220 |
| | August 21, 2015 | | $ | 15,499 |
|
| October 30, 2015 | | Q3 2015 | | $ | 0.200 |
| | November 20, 2015 | | $ | 14,091 |
|
| February 12, 2016 | | Q4 2015 | | $ | 0.228 |
| | February 26, 2016 | | $ | 16,063 |
|
| May 2, 2016 | | Q1 2016 | | $ | 0.149 |
| | May 23, 2016 | | $ | 10,497 |
|
| July 21, 2016 | | Q2 2016 | | $ | 0.189 |
| | August 22, 2016 | | $ | 13,693 |
|
| October 25, 2016 | | Q3 2016 | | $ | 0.207 |
| | November 18, 2016 | | $ | 14,997 |
|
| February 3, 2017 | | Q4 2016 | | $ | 0.258 |
| | February 24, 2017 | | $ | 18,692 |
|
| April 28, 2017 | | Q1 2017 | | $ | 0.302 |
| | May 25, 2017 | | $ | 21,880 |
|
| July 28, 2017 | | Q2 2017 | | $ | 0.332 |
| | August 24, 2017 | | $ | 24,286 |
|
| October 16, 2017 | | Q3 2017 | | $ | 0.337 |
| | November 14, 2017 | | $ | 24,652 |
|
9.8. EARNINGS PER COMMON UNIT
The net income (loss) per common unit on the consolidated statements of operations is based on the net income (loss) ofattributable to the PartnershipPartnership’s common units for the years ended December 31, 2017, 20162022, 2021 and 2015, since this is the amount of net income that is attributable to the Partnership’s common units.
2020. The Partnership’s net income (loss) is allocated wholly to the common units, as the General Partner does not have an economic interest. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note
8—Partners’ Capital7—Unitholders' Equity and Partnership Distributions.Distributions.
Basic and diluted earnings per common unit is calculated using the two-class method. The two class method is an earnings allocation proportional to the respective ownership among holders of common units and participating securities. Basic net income (loss) per common unit is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested common units granted under the LTIP.
|
| | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands, except per unit amounts) |
| Net income (loss) attributable to the period | 111,478 |
| | (10,899 | ) | | 24,419 |
|
| Weighted average common units outstanding | | | | | |
| Basic weighted average common units outstanding | 104,318 |
| | 83,081 |
| | 79,717 |
|
| Effect of dilutive securities: | | | | | |
| Potential common units issuable | 65 |
| | — |
| | 10 |
|
| Diluted weighted average common units outstanding | 104,383 |
| | 83,081 |
| | 79,727 |
|
| Net income (loss) per common unit, basic | $1.07 | | $(0.13) | | $0.31 |
| Net income (loss) per common unit, diluted | $1.07 | | $(0.13) | | $0.31 |
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands, except per unit amounts) |
| Net income (loss) attributable to the period | $ | 151,673 | | | $ | 57,939 | | | $ | (192,304) | |
Less: net income (loss) allocated to participating securities(1) | 365 | | | 193 | | | 44 | |
| Net income (loss) attributable to common unitholders | $ | 151,308 | | | $ | 57,746 | | | $ | (192,348) | |
| Weighted average common units outstanding: | | | | | |
| Basic weighted average common units outstanding | 75,612 | | | 68,319 | | | 67,686 | |
| Effect of dilutive securities: | | | | | |
Potential common units issuable(2) | 67 | | | 72 | | | — | |
| Diluted weighted average common units outstanding | 75,679 | | | 68,391 | | | 67,686 | |
| Net income (loss) per common unit, basic | $ | 2.00 | | | $ | 0.85 | | | $ | (2.84) | |
| Net income (loss) per common unit, diluted | $ | 2.00 | | | $ | 0.85 | | | $ | (2.84) | |
(1) Restricted stock units with non-forfeitable distribution equivalent rights granted to employees are considered participating securities.
(2) For the yearsyear ended December 31, 2017, 2016 and 2015, there2022, no significant potential common units were 39,788excluded from the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive. For the year ended December 31, 2021, 10,160 potential common units 1,567,155were excluded from the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive. For the year ended December 31, 2020, no potential common units and 1,697,142 units, respectively, that were not included in the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive as a result of recording a net loss attributable to the common unitholders for the period.
9. INCOME TAXES
The Partnership’s total income tax benefit and expense for the years ended December 31, 2022 and 2021, respectively, differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of a reduction to its valuation allowance in 2022 and maintaining a valuation allowance on the Partnership’s deferred tax assets in 2021. For the year ended December 31, 2020, total income tax expense differed from amounts computed by applying the United States federal statutory rate to pre-tax loss for the period primarily due to net loss attributable to the non-controlling interest and the impact of recording a valuation allowance on the Partnership’s deferred tax assets.
The components of the provision for income taxes and effective tax rates for the years ended December 31, 2022, 2021 and 2020 are as follows:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands) |
| Current income tax provision (benefit): | | | | | |
| Federal | $ | 15,929 | | | $ | 1,218 | | | $ | — | |
| State | 1,074 | | | 303 | | | — | |
| Total current income tax provision (benefit) | 17,003 | | | 1,521 | | | — | |
| Deferred income tax provision (benefit): | | | | | |
| Federal | (49,656) | | | — | | | 142,466 | |
| State | — | | | — | | | — | |
| Total deferred income tax provision (benefit) | (49,656) | | | — | | | 142,466 | |
| Total provision (benefit) from income taxes | $ | (32,653) | | | $ | 1,521 | | | $ | 142,466 | |
| | | | | |
| Effective tax rates | (5.2) | % | | 0.6 | % | | (279.6) | % |
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands) |
| Income tax expense (benefit) at the federal statutory rate (21%) | $ | 130,694 | | | $ | 54,221 | | | $ | (10,699) | |
| | | | | |
| Impact of nontaxable noncontrolling interest | (105,699) | | | (41,735) | | | 233 | |
| | | | | |
| State income tax expense (benefit), net of federal tax effect | 846 | | | 262 | | | — | |
| | | | | |
| | | | | |
| Change in valuation allowance | (58,443) | | | (11,175) | | | 152,898 | |
| Other, net | (51) | | | (52) | | | 34 | |
| Provision for (benefit from) income taxes | $ | (32,653) | | | $ | 1,521 | | | $ | 142,466 | |
The components of the Partnership’s deferred tax assets and liabilities as of December 31, 2022 and 2021 are as follows:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 |
| (In thousands) |
| Deferred tax assets: | | | |
| Net operating loss and capital loss carryforwards | $ | 70 | | | $ | 6,014 | |
| Investment in the Operating Company | 148,003 | | | 163,065 | |
| | | |
| | | |
| Total deferred tax assets | 148,073 | | | 169,079 | |
| Valuation allowance | (98,417) | | | (169,079) | |
| Net deferred tax assets | 49,656 | | | — | |
| | | |
| | | |
| | | |
| | | |
| Net deferred tax assets (liabilities) | $ | 49,656 | | | $ | — | |
At December 31, 2022, the Partnership has net deferred tax assets of approximately $49.7 million, including federal capital loss carryforwards expiring in 2026-2027 of approximately $0.1 million, and immaterial state operating loss carryforwards. Deferred taxes are provided on the difference between the Partnership’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in the Operating Company.
During the year ended December 31, 2022, the Partnership recognized discrete income tax benefit of $49.7 million related to a partial release of its beginning-of-the-year valuation allowance, based on a change in judgment about the realizability of its deferred tax assets in future years.
At December 31, 2021, the Partnership had a full valuation allowance against its deferred tax assets, based on its assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets.
The Partnership principally operates in the state of Texas. For the years ended December 31, 2022 and 2021, the Partnership recognized $1.1 million and $0.3 million, respectively, in state income tax expense primarily for its share of Texas margin tax attributable to the Partnership’s results which are included in a combined tax return filed by Diamondback. At December 31, 2022, the Partnership did not have any significant uncertain tax positions requiring recognition in the financial statements. The Partnership’s 2018 through 2022 tax years remain open to examination by tax authorities.
The CHIPS and Science Act of 2022 (“CHIPS”) was enacted on August 9, 2022, and the Inflation Reduction Act of 2022 (“IRA”) was enacted on August 16, 2022, which imposes a 15% corporate alternative minimum tax on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated financial statements) as well as an excise tax of 1% on the fair market value of certain public company stock/unit repurchases for tax years beginning after December 31, 2022, and included several other provisions applicable to U.S. income taxes for corporations.The Partnership considered the impact of this legislation in the period of enactment and concluded there was not a material impact to the Partnership’s current or deferred income tax balances.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
10. DERIVATIVES
During 2022, the Partnership used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. At December 31, 2022, the Partnership has puts and fixed price basis swap contracts outstanding.
The Partnership’s put contracts for oil are based upon reported settlement prices based on New York Mercantile Exchange West Texas Intermediate (“Cushing WTI”). The Partnership’s fixed price basis swaps for oil are for the spread between the Cushing WTI crude oil price and the Midland WTI crude oil price. The Partnership’s fixed price basis swaps for natural gas are for 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 the Cushing WTI oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership 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 Partnership, which creates credit risk. The Partnership’s counterparties are all participants in the amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Partnership is not required to post any collateral. The Partnership’s counterparties have been determined to have an acceptable credit risk; therefore, the Partnership does not require collateral from its counterparties.
As of December 31, 2022, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Swaps | | Collars | | Puts |
| Settlement Month | Settlement Year | Type of Contract | Bbls/Mcf Per Day | Index | Weighted Average Differential | Weighted Average Fixed Price | | Weighted Average Floor Price | Weighted Average Ceiling Price | | Strike Price |
| OIL | | | | | | | | | | | |
| Jan. - Mar. | 2023 | Puts(1) | 12,000 | WTI Cushing | $— | $— | | $— | $— | | $54.50 |
| Apr. - Jun. | 2023 | Puts(2) | 8,000 | WTI Cushing | $— | $— | | $— | $— | | $55.00 |
| Jan. - Dec. | 2023 | Basis Swaps | 4,000 | Argus WTI Midland | $1.05 | $— | | $— | $— | | $— |
| | | | | | | | | | | |
| NATURAL GAS | | | | | | | | | | | |
| Jan. - Dec. | 2023 | Basis Swaps | 30,000 | Waha Hub | $(1.33) | $— | | $— | $— | | $— |
| Jan. - Dec. | 2024 | Basis Swaps | 20,000 | Waha Hub | $(1.23) | $— | | $— | $— | | $— |
(1) Includes a deferred premium at a weighted average price of $1.82/Bbl.
(2) Includes a deferred premium at a weighted average price of $1.79/Bbl.
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 11—Fair Value Measurements for further details.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
Gains and Losses on Derivative Instruments
The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations and the net cash receipts (payments) on derivatives for the periods presented:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands) | | |
| Gain (loss) on derivative instruments | $ | (18,138) | | | $ | (69,409) | | | $ | (63,591) | |
Net cash receipts (payments) on derivatives(1) | $ | (31,319) | | | $ | (92,585) | | | $ | (36,998) | |
| | | | | |
| | | | | |
(1)The year ended December 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $6.6 million.
11. 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 last unobservable, that may be used to measure fair value. The Partnership’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 Partnership 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.
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 Partnership’s derivative instruments. The fair values of the Partnership’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.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
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 but could potentially dilute basic earnings per unit in future periods.the Partnership’s consolidated balance sheets as of December 31, 2022 and December 31, 2021. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.
| | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2022 |
| Level 1 | Level 2 | Level 3 | Total Gross Fair Value | Gross Amounts Offset in Balance Sheet | Net Fair Value Presented in Balance Sheet |
| (In thousands) |
| Assets: | | | | | | |
| Current: | | | | | | |
| Derivative instruments | $ | — | | $ | 13,296 | | $ | — | | $ | 13,296 | | $ | (3,968) | | $ | 9,328 | |
| Non-current: | | | | | | |
| | | | | | |
| Derivative instruments | $ | — | | $ | 1,911 | | $ | — | | $ | 1,911 | | $ | (1,469) | | $ | 442 | |
| Liabilities: | | | | | | |
| Current: | | | | | | |
| Derivative instruments | $ | — | | $ | 3,968 | | $ | — | | $ | 3,968 | | $ | (3,968) | | $ | — | |
| Non-current: | | | | | | |
| Derivative instruments | $ | — | | $ | 1,476 | | $ | — | | $ | 1,476 | | $ | (1,469) | | $ | 7 | |
10.
| | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2021 |
| Level 1 | Level 2 | Level 3 | Total Gross Fair Value | Gross Amounts Offset in Balance Sheet | Net Fair Value Presented in Balance Sheet |
| (In thousands) |
| Assets: | | | | | | |
| Current: | | | | | | |
| Derivative instruments | $ | — | | $ | 1,921 | | $ | — | | $ | 1,921 | | $ | (1,921) | | $ | — | |
| | | | | | |
| | | | | | |
| | | | | | |
| Liabilities: | | | | | | |
| Current: | | | | | | |
| Derivative instruments | $ | — | | $ | 5,338 | | $ | — | | $ | 5,338 | | $ | (1,921) | | $ | 3,417 | |
| | | | | | |
| | | | | | |
Assets and Liabilities Not Recorded at Fair Value
The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2022 | | December 31, 2021 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| (In thousands) |
| Debt: | | | | | | | |
| Revolving credit facility | $ | 152,000 | | | $ | 152,000 | | | $ | 304,000 | | | $ | 304,000 | |
5.375% senior notes due 2027(1) | $ | 424,895 | | | $ | 411,634 | | | $ | 472,727 | | | $ | 498,992 | |
(1) The carrying value includes associated deferred loan costs and any discount.
The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Notes was determined using the December 31, 2022 quoted market price, a Level 1 classification in the fair value hierarchy.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include mineral and royalty interests acquired in asset acquisitions and subsequent write-downs of our proved oil and natural gas interests to fair value when they are impaired or held for sale. See Note 2—Summary of Significant Accounting Policies and Note 5—Oil and Natural Gas Interests for further discussion of non-recurring fair value adjustments.
Fair Value of Financial Assets
The Partnership has other financial instruments consisting of cash and cash equivalents, royalty income receivable, other current assets, other assets, accounts payable and accrued liabilities. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.
12. COMMITMENTS AND CONTINGENCIES
The Partnership could be subjectis a party to various possibleroutine legal proceedings, disputes and claims from time to time arising in the ordinary course of its business. While the ultimate outcome of any pending proceedings, disputes or claims, and any resulting impact on the Partnership, cannot be predicted with certainty, the Partnership’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership’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 Partnership’s assessment. The Partnership records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss contingencies which arise primarily from interpretationis probable and the amount of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales mayloss can be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.reasonably estimated.
11.13. SUBSEQUENT EVENTS
Cash Distribution
On January 31, 2018,February 15, 2023, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 20172022 of $0.46$0.49 per common unit, payable on February 26, 2018,March 10, 2023, to unitholders of record at the close of business on February 19, 2018.March 3, 2023. The distribution consists of a base quarterly distribution of $0.25 per common unit and a variable quarterly distribution of $0.24 per common unit.
Recent Acquisitions
Since the end of the fourth quarter of 2017, the Partnership acquired from unrelated third party sellers additional mineral interests underlying 137,443 gross acres, 1,617 net acres and 900 net royalty acres in the Permian Basin and Eagle Ford Shale for an aggregate of approximately $149.4 million, subject to post-closing adjustments. As a result, as of February 2, 2018, the Partnership’s assets included mineral interests underlying 385,046 gross acres, 45,460 net acres and 10,470 net royalty acres primarily in the Permian Basin and Eagle Ford Shale. These acquisitions were primarily funded with cash on hand and borrowings under the Partnership’s revolving credit facility.
12.14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)
The Partnership’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 and amortization are as follows:
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| (In thousands) |
| Oil and natural gas interests: | | | |
| Proved | $ | 2,167,598 | | | $ | 1,873,418 | |
| Unproved | 1,297,221 | | | 1,640,172 | |
| Total oil and natural gas interests | 3,464,819 | | | 3,513,590 | |
| Accumulated depletion and impairment | (720,234) | | | (599,163) | |
| Net oil and natural gas interests capitalized | $ | 2,744,585 | | | $ | 2,914,427 | |
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (In thousands) |
| Oil and natural gas interests: | | | |
| Proved | $ | 589,173 |
| | $ | 508,586 |
|
| Unproved | 514,724 |
| | 252,232 |
|
| Total oil and natural gas interests | 1,103,897 |
| | 760,818 |
|
| Accumulated depletion and impairment | (189,466 | ) | | (148,948 | ) |
| Net oil and natural gas interests capitalized | $ | 914,431 |
| | $ | 611,870 |
|
Viper Energy Partners LP
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:
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands) |
| Acquisition costs: | | | | | |
| Proved properties | $ | 46,307 | | | $ | 138,882 | | | $ | 9,509 | |
| Unproved properties | 16,624 | | | 479,041 | | | 56,169 | |
| Total | $ | 62,931 | | | $ | 617,923 | | | $ | 65,678 | |
|
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Acquisition costs | | | | | |
| Proved properties | $ | 55,948 |
| | $ | 31,441 |
| | $ | 4,121 |
|
| Unproved properties | 287,131 |
| | 174,385 |
| | 39,786 |
|
| Total | $ | 343,079 |
| | $ | 205,826 |
| | $ | 43,907 |
|
Results of Operations from Oil and Natural Gas Producing Activities
|
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Royalty income | $ | 160,163 |
| | $ | 78,837 |
| | $ | 74,859 |
|
| Production and ad valorem taxes | (10,608 | ) | | (5,544 | ) | | (5,531 | ) |
| Gathering and transportation | (789 | ) | | (415 | ) | | (259 | ) |
| Depletion | (40,519 | ) | | (29,820 | ) | | (35,436 | ) |
| Impairment | — |
| | (47,469 | ) | | (3,423 | ) |
| Results of operations from oil, natural gas and natural gas liquids | $ | 108,247 |
| | $ | (4,411 | ) | | $ | 30,210 |
|
Oil and Natural Gas Reserves
Proved oil and natural gas reserve estimates as of December 31, 2017, 2016 and 2015their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., independent petroleum engineers.engineers, as of December 31, 2022 and prepared by Ryder Scott as of December 31, 2021 and 2020. 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.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
The changes in estimated proved reserves are as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Oil
(MBbls) | | Natural Gas
(MMcf) | | Natural Gas Liquids
(MBbls) | | Total (MBOE) |
| (In thousands) | |
| Proved Developed and Undeveloped Reserves: | | | | | | | |
| As of December 31, 2019 | 54,420 | | | 95,774 | | | 18,564 | | | 88,946 | |
| Purchase of reserves in place | 491 | | | 507 | | | 113 | | | 689 | |
| Extensions and discoveries | 15,415 | | | 23,982 | | | 4,424 | | | 23,836 | |
| Revisions of previous estimates | (6,685) | | | 11,043 | | | 763 | | | (4,082) | |
| Divestitures | (155) | | | (370) | | | (63) | | | (280) | |
| Production | (5,956) | | | (11,486) | | | (1,848) | | | (9,718) | |
| As of December 31, 2020 | 57,530 | | | 119,450 | | | 21,953 | | | 99,392 | |
| Purchase of reserves in place | 5,246 | | | 9,549 | | | 2,264 | | | 9,102 | |
| Extensions and discoveries | 17,256 | | | 39,256 | | | 7,182 | | | 30,981 | |
| Revisions of previous estimates | (4,544) | | | 29,788 | | | (1,339) | | | (918) | |
| Divestitures | (180) | | | (681) | | | (114) | | | (409) | |
| Production | (6,068) | | | (13,672) | | | (1,913) | | | (10,260) | |
| As of December 31, 2021 | 69,240 | | | 183,690 | | | 28,033 | | | 127,888 | |
| Purchase of reserves in place | 599 | | | 1,186 | | | 209 | | | 1,006 | |
| Extensions and discoveries | 15,714 | | | 29,177 | | | 5,281 | | | 25,858 | |
| Revisions of previous estimates | 1,453 | | | 15,248 | | | 4,483 | | | 8,477 | |
| Divestitures | (905) | | | (3,469) | | | (564) | | | (2,047) | |
| Production | (7,097) | | | (15,868) | | | (2,540) | | | (12,282) | |
| As of December 31, 2022 | 79,004 | | | 209,964 | | | 34,902 | | | 148,900 | |
| | | | | | | |
| Proved Developed Reserves: | | | | | | | |
| December 31, 2020 | 40,220 | | | 93,617 | | | 16,724 | | | 72,547 | |
| December 31, 2021 | 49,280 | | | 134,485 | | | 19,476 | | | 91,170 | |
| December 31, 2022 | 54,817 | | | 161,119 | | | 25,621 | | | 107,291 | |
| | | | | | | |
| Proved Undeveloped Reserves: | | | | | | | |
| December 31, 2020 | 17,310 | | | 25,833 | | | 5,229 | | | 26,845 | |
| December 31, 2021 | 19,960 | | | 49,205 | | | 8,557 | | | 36,718 | |
| December 31, 2022 | 24,187 | | | 48,845 | | | 9,281 | | | 41,609 | |
|
| | | | | | | | |
| | Oil
(Bbls) | | Natural Gas Liquids
(Bbls) | | Natural Gas
(Mcf) |
| | (In thousands) |
| Proved Developed and Undeveloped Reserves: | | | | | |
| As of December 31, 2014 | 12,830 |
| | 2,514 |
| | 18,994 |
|
| Purchase of reserves in place | 107 |
| | 3 |
| | 431 |
|
| Extensions and discoveries | 8,450 |
| | 2,013 |
| | 9,476 |
|
| Revisions of previous estimates | (1,454 | ) | | (375 | ) | | (3,465 | ) |
| Production | (1,555 | ) | | (239 | ) | | (1,128 | ) |
| As of December 31, 2015 | 18,378 |
| | 3,916 |
| | 24,308 |
|
| Purchase of reserves in place | 1,138 |
| | 437 |
| | 2,315 |
|
| Extensions and discoveries | 5,647 |
| | 1,477 |
| | 7,181 |
|
| Revisions of previous estimates | (2,041 | ) | | 74 |
| | (5,223 | ) |
| Production | (1,778 | ) | | (328 | ) | | (1,490 | ) |
| As of December 31, 2016 | 21,344 |
| | 5,576 |
| | 27,091 |
|
| Purchase of reserves in place | 2,106 |
| | 252 |
| | 5,245 |
|
| Extensions and discoveries | 7,859 |
| | 1,813 |
| | 11,106 |
|
| Revisions of previous estimates | (2,525 | ) | | (813 | ) | | (3,498 | ) |
| Production | (2,899 | ) | | (533 | ) | | (3,549 | ) |
| As of December 31, 2017 | 25,885 |
| | 6,295 |
| | 36,395 |
|
| | | | | | |
| Proved Developed Reserves: | | | | | |
| December 31, 2015 | 9,700 |
| | 2,205 |
| | 13,739 |
|
| December 31, 2016 | 12,332 |
| | 3,247 |
| | 15,933 |
|
| December 31, 2017 | 18,788 |
| | 4,536 |
| | 29,256 |
|
| | | | | | |
| Proved Undeveloped Reserves: | | | | | |
| December 31, 2015 | 8,677 |
| | 1,711 |
| | 10,569 |
|
| December 31, 2016 | 9,012 |
| | 2,329 |
| | 11,158 |
|
| December 31, 2017 | 7,097 |
| | 1,759 |
| | 7,139 |
|
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, 2017,2022, the Partnership’s total extensions and discoveries of 25,858 MBOE resulted primarily from the drilling of 636 new wells and from 199 new proved undeveloped locations added. The Partnership’s total positive revisions of previous estimated quantities of 8,477 MBOE were due to positive revisions of 15,484 MBOE attributable to price and performance revisions which were largely offset by PUD downgrades of 7,007 MBOE. Total purchases of reserves in place of 1,006 MBOE resulted from multiple acquisitions of certain mineral and royalty interests.
During the year ended December 31, 2021, the Partnership’s total extensions and discoveries of 30,981 MBOE resulted primarily from the drilling of 407 new wells and from 336 new proved undeveloped locations added. The Partnership’s total negative revisions of previous estimated quantities of 918 MBOE were due to PUD downgrades of 11,263 MBOE which were largely offset by positive revisions of 10,345 MBOE attributable to price and performance revisions. Total purchases of reserves in place of 9,102 MBOE resulted from multiple acquisitions of certain mineral and royalty interests, including the Swallowtail Acquisition.
Viper Energy Partners LP
Notes to Consolidated Financial Statements - (Continued)
During the year ended December 31, 2020, the Partnership’s extensions and discoveries of 11,524 MBoe23,836 MBOE resulted primarily from the drilling of 96652 new wells and from 40299 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 3,921 MBoe4,082 MBOE were primarilydue to negative price revisions and PUD downgrades. 114 MBOE of PUDs were downgraded from non-operated properties and 804 MBOE of PUDs were downgraded from Diamondback-operated properties, with the Diamondback-operated downgrades due to changes in type curves.the development plan and optimization of the inventory. The purchase of reserves in place of 3,232 MBoe689 MBOE were due to multiple acquisitions primarily located in Pecos, Reevesof certain mineral and Loving counties.royalty interests.
During the year ended December 31, 2016, the Partnership’s extensions and discoveries of 7,125 MBoe resulted primarily from the drilling of 33 new wells and from 32 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 1,968 MBoe were primarily due to technical revisions with the remainder due to lower product pricing. The purchase of reserves in place of 1,575 MBoe were due to multiple acquisitions with the largest being located in Loving and Midland counties.
During the year ended December 31, 2015, purchases of reserves were primarily from one acquisition in Howard County and several minor acquisitions in other areas consisting of 124 vertical wells and one horizontal well. Extensions are primarily
Viper Energy Partners LP
Notes to Financial Statements - (Continued)
the result of horizontal development of the Wolfcamp B and Lower Spraberry shales. The extensions were the result of one vertical well and 83 horizontal wells, of which 51 horizontal wells are in the proved undeveloped category. Diamondback is the operator of 57 of the 84 total wells. Revisions are primarily the result of downgrading nine horizontal wells and 48 vertical wells that were classified as PUDs into the probable category as a result of lower product prices and subsequent changes in drilling plans such that the wells are no longer expected to be drilled within five years of when they were originally booked.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows are 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 Partnership. 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.
The following table sets forth the standardized measure of discounted future net cash flows attributable to the Partnership’s proved oil and natural gas reserves as of December 31, 2017, 20162022, 2021 and 2015.2020:
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands) |
| Future cash inflows | $ | 10,072,969 | | | $ | 5,763,433 | | | $ | 2,460,052 | |
| Future production taxes | (729,256) | | | (416,761) | | | (181,067) | |
| Future income tax expense | (1,465,160) | | | (572,991) | | | (22,993) | |
| Future net cash flows | 7,878,553 | | | 4,773,681 | | | 2,255,992 | |
| 10% discount to reflect timing of cash flows | (4,424,457) | | | (2,680,564) | | | (1,232,398) | |
| Standardized measure of discounted future net cash flows | $ | 3,454,096 | | | $ | 2,093,117 | | | $ | 1,023,594 | |
|
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Future cash inflows | $ | 1,445,883 |
| | $ | 948,090 |
| | $ | 912,276 |
|
| Future production taxes | (125,564 | ) | | (69,109 | ) | | (61,777 | ) |
| Future state margin tax expenses | (6,932 | ) | | (4,615 | ) | | (4,789 | ) |
| Future net cash flows | 1,313,387 |
| | 874,366 |
| | 845,710 |
|
| 10% discount to reflect timing of cash flows | (688,039 | ) | | (461,785 | ) | | (449,947 | ) |
| Standardized measure of discounted future net cash flows | $ | 625,348 |
| | $ | 412,581 |
| | $ | 395,763 |
|
InThe following table presents the table below theweighted average first-day-of–the-month priceprices for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.inflows:
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 | | 2020 |
| |
| |
| Oil (per Bbl) | $ | 95.04 | | | $ | 64.87 | | | $ | 37.61 | |
| Natural gas (per Mcf) | $ | 5.74 | | | $ | 2.97 | | | $ | 0.34 | |
| Natural gas liquids (per Bbl) | $ | 38.95 | | | $ | 25.93 | | | $ | 11.65 | |
|
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| | Unweighted Arithmetic Average |
| | First-Day-of-the-Month Prices |
| Oil (per Bbl) | $ | 48.21 |
| | $ | 39.64 |
| | $ | 45.03 |
|
| Natural gas (per Mcf) | $ | 2.13 |
| | $ | 1.36 |
| | $ | 1.64 |
|
| Natural gas liquids (per Bbl) | $ | 19.15 |
| | $ | 11.69 |
| | $ | 11.41 |
|
Viper Energy Partners LP
Notes to Financial Statements - (Continued)
Principal changes in the standardized measure of discounted future net cash flows attributable to the Partnership’s proved reserves are as follows:
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 | | 2020 |
| (In thousands) |
| Standardized measure of discounted future net cash flows at the beginning of the period | $ | 2,093,117 | | | $ | 1,023,594 | | | $ | 1,318,388 | |
| Purchase of minerals in place | 30,331 | | | 170,205 | | | 10,781 | |
| Divestiture of reserves | (30,076) | | | (4,402) | | | (3,481) | |
| Sales of oil and natural gas, net of production costs | (781,604) | | | (468,976) | | | (227,137) | |
| Extensions and discoveries | 844,010 | | | 615,762 | | | 280,486 | |
| Net changes in prices and production costs | 1,131,202 | | | 863,458 | | | (465,582) | |
| Revisions of previous quantity estimates | 309,338 | | | 45,788 | | | (87,614) | |
| Net changes in income taxes | (393,652) | | | (243,186) | | | 59,754 | |
| Accretion of discount | 234,717 | | | 103,446 | | | 138,901 | |
| Net changes in timing of production and other | 16,713 | | | (12,572) | | | (902) | |
| Standardized measure of discounted future net cash flows at the end of the period | $ | 3,454,096 | | | $ | 2,093,117 | | | $ | 1,023,594 | |
|
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Standardized measure of discounted future net cash flows at the beginning of the period | $ | 412,581 |
| | $ | 395,763 |
| | $ | 553,236 |
|
| Purchase of minerals in place | 54,662 |
| | 23,651 |
| | 2,963 |
|
| Sales of oil and natural gas, net of production costs | (149,555 | ) | | (74,628 | ) | | (69,328 | ) |
| Extensions and discoveries | 214,479 |
| | 104,451 |
| | 181,330 |
|
| Net changes in prices and production costs | 99,382 |
| | (42,155 | ) | | (269,154 | ) |
| Revisions of previous quantity estimates | (50,773 | ) | | (42,883 | ) | | (71,399 | ) |
| Net changes in state margin taxes | (1,129 | ) | | 51 |
| | (1,884 | ) |
| Accretion of discount | 41,477 |
| | 39,800 |
| | 54,911 |
|
| Net changes in timing of production and other | 4,224 |
| | 8,531 |
| | 15,088 |
|
| Standardized measure of discounted future net cash flows at the end of the period | $ | 625,348 |
| | $ | 412,581 |
| | $ | 395,763 |
|
13. QUARTERLY FINANCIAL DATA (Unaudited)
|
| | | | | | | | | | | | | | | |
| | 2017 |
| | First
Quarter | | Second
Quarter | | Third
Quarter | | Fourth
Quarter |
| | (In thousands, except per unit amounts) |
| Royalty income | $ | 32,050 |
| | $ | 35,933 |
| | $ | 42,211 |
| | $ | 49,969 |
|
| Income from operations | 21,450 |
| | 22,479 |
| | 27,067 |
| | 42,825 |
|
| Net income | 20,652 |
| | 22,149 |
| | 26,607 |
| | 42,070 |
|
| Net income attributable to common limited partners per unit: | | | | | | | |
| Basic | $ | 0.22 |
| | $ | 0.23 |
| | $ | 0.24 |
| | $ | 0.37 |
|
| Diluted | $ | 0.22 |
| | $ | 0.23 |
| | $ | 0.24 |
| | $ | 0.37 |
|
|
| | | | | | | | | | | | | | | |
| | 2016 |
| | First
Quarter | | Second
Quarter | | Third
Quarter | | Fourth
Quarter |
| | (In thousands, except per unit amounts) |
| Royalty income | $ | 14,086 |
| | $ | 16,836 |
| | $ | 19,992 |
| | $ | 27,923 |
|
| Income (loss) from operations | (23,104 | ) | | (13,711 | ) | | 10,594 |
| | 16,910 |
|
| Net income (loss) | (23,335 | ) | | (14,020 | ) | | 10,202 |
| | 16,254 |
|
| Net income (loss) attributable to common limited partners per unit: | | | | | | | |
| Basic | $ | (0.29 | ) | | $ | (0.18 | ) | | $ | 0.12 |
| | $ | 0.20 |
|
| Diluted | $ | (0.29 | ) | | $ | (0.18 | ) | | $ | 0.12 |
| | $ | 0.20 |
|