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ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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☐
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
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DE
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46-5001985
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(State or Other Jurisdiction of Incorporation or Organization)
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(I.R.S. Employer Identification Number)
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500 West Texas
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Suite 1200
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Midland,
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TX
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79701
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(Address of principal executive offices)
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(Zip code)
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Title of each class
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Trading Symbol(s)
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Name of each exchange on which registered
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Common Units
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VNOM
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The Nasdaq Stock Market LLC
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(NASDAQ Global Select Market)
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Large Accelerated Filer
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☒
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Accelerated Filer
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☐
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Non-Accelerated Filer
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☐
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Smaller Reporting Company
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☐
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Emerging Growth Company
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☐
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Page
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3-D seismic
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Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
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Basin
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A large depression on the earth’s surface in which sediments accumulate.
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Bbl
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Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
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BOE
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Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
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BOE/d
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Barrels of oil equivalent per day.
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British Thermal Unit or Btu
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The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
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Completion
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The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
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Condensate
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Liquid hydrocarbons associated with the production that is primarily natural gas.
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Crude oil
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Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
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Deterministic method
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The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.
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Developed acreage
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Acreage allocated or assignable to productive wells.
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Development costs
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Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
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Development well
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A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
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Differential
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An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
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Dry hole or dry well
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A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
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Exploitation
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A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
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Field
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An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
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Finding and development costs
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Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
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Fracturing
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The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
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Gross acres or gross wells
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The total acres or wells, as the case may be, in which a working interest is owned.
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Horizontal drilling
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A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
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Horizontal wells
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Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
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MBbls
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Thousand barrels of crude oil or other liquid hydrocarbons.
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MBOE
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One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
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Mcf
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Thousand cubic feet of natural gas.
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Mineral interests
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The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
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MMBtu
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Million British Thermal Units.
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Working interest
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An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
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WTI
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West Texas Intermediate.
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Delaware Act
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Delaware Revised Uniform Limited Partnership Act.
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Diamondback
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Diamondback Energy, Inc., a Delaware corporation.
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Diamondback E&P LLC
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A subsidiary of Diamondback.
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EPA
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U.S. Environmental Protection Agency.
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Exchange Act
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The Securities Exchange Act of 1934, as amended.
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FERC
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Federal Energy Regulatory Commission.
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GAAP
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Accounting principles generally accepted in the United States.
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General partner
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Viper Energy Partners GP LLC, a Delaware limited liability company; the general partner of the Partnership and a wholly-owned subsidiary of Diamondback.
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Inception
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September 18, 2013, the date Viper Energy Partners LLC was formed.
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IPO
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The partnership’s initial public offering of common units.
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LTIP
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Viper Energy Partners LP Long Term Incentive Plan.
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Operating Company
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Viper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy Partners LP.
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OSHA
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Federal Occupational Safety and Health Act.
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Partnership
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Viper Energy Partners LP, a Delaware limited partnership.
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Partnership agreement
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The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018.
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Ryder Scott
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Ryder Scott Company, L.P.
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SEC
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Securities and Exchange Commission.
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Securities Act
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The Securities Act of 1933, as amended.
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Wells Fargo
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Wells Fargo Bank, National Association.
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•
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our ability to execute our business strategies;
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the volatility of realized oil and natural gas prices;
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the level of production on our properties;
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the impact of reduced drilling activity;
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regional supply and demand factors, delays or interruptions of production;
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our ability to replace our oil and natural gas reserves;
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our ability to identify, complete and integrate acquisitions of properties or businesses, including the recently completed acquisitions from Diamondback and Santa Elena Minerals, LP.;
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conditions in the capital markets and our ability to obtain capital on favorable terms or at all;
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general economic, business or industry conditions;
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competition in the oil and natural gas industry;
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the ability of our operators to obtain capital or financing needed for development and exploration operations;
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title defects in the properties in which we invest;
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uncertainties with respect to identified drilling locations and estimates of reserves;
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the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;
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restrictions on the use of water;
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the availability of transportation facilities;
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the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
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federal and state legislative and regulatory initiatives relating to hydraulic fracturing;
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title defects in the properties in which we invest;
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future operating results;
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exploration and development drilling prospects, inventories, projects and programs;
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operating hazards faced by our operators; and
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the ability of our operators to keep pace with technological advancements.
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Capitalize on the development of the properties underlying our mineral interests to grow our cash flow. Our assets primarily consist of mineral interests in the Permian Basin and the Eagle Ford Shale in Texas. We expect the production from our mineral interests will increase as Diamondback and our other operators continue to drill and develop our acreage. We expect to capitalize on this development, which requires no capital expenditure funding from us, and believe the anticipated increase in our aggregate royalty payment receipts will enable us to grow our cash flows.
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Leverage our relationship with Diamondback to participate with it in acquisitions of mineral or other interests in producing properties from third parties and to increase the size and scope of our potential third-party acquisition targets. We have in the past and intend to continue to make opportunistic acquisitions of mineral interests that have substantial oil-weighted resource potential and organic growth potential. Diamondback was formed, in part, to acquire and develop oil and natural gas properties, some of which will likely meet our acquisition criteria. In addition, Diamondback’s executives have an established track record of evaluating, pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with Diamondback and its affiliates, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third-party acquisition opportunities. We may have additional opportunities to work jointly with Diamondback to pursue certain acquisitions of mineral or other interests in oil and natural gas properties from third parties. For example, we and Diamondback may jointly pursue an acquisition where we would acquire mineral or other interests in properties and Diamondback would acquire the remaining working and revenue interests in such properties. We believe this arrangement may give us access to third-party acquisition opportunities that we would not otherwise be in a position to pursue.
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Seek to acquire from Diamondback, from time to time, mineral or other interests in producing oil and natural gas properties that meet our acquisition criteria. Since our formation, we have acquired, and may have additional opportunities from time to time in the future to acquire, mineral or other interests in producing oil and natural gas properties directly from Diamondback. We believe Diamondback may be incentivized to sell properties to us, as doing so may enhance Diamondback’s economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through distributions on Diamondback’s limited partner interests in us. However, none of Diamondback or any of its affiliates is contractually obligated to offer or sell any interests in properties to us.
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Maintain a conservative capital structure to allow financial flexibility. Since our formation, we have maintained a conservative capital structure that has allowed us to opportunistically purchase accretive mineral and other interests. We are committed to maintaining a conservative leverage profile, and will continue to seek to opportunistically fund accretive acquisitions.
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Oil rich resource base in one of North America’s leading resource plays. The majority of the acreage underlying our mineral interests is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. As of December 31, 2019, 373 horizontal drilling rigs were operating in the Permian Basin, representing 53% of the total U.S. onshore horizontal rig activity. The majority of our current properties is well positioned in the core of both the Midland and Delaware Basins. Production on our properties for the year ended December 31, 2019 was approximately 65% oil, 19% natural gas liquids and 16% natural gas. As of December 31, 2019, our estimated net proved reserves were comprised of approximately 61% oil, 21% natural gas liquids and 18% natural gas.
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Multi-year drilling inventory in one of North America’s leading oil resource plays. We expect our reserves and cash flow to grow organically as our operators continue to drill new wells on our acreage. Diamondback, as the operator of approximately 50% of our acreage as of December 31, 2019, has advised us that it has identified a multi-year inventory of potential drilling locations for our oil-weighted reserves from the acreage underlying our mineral interests. At an assumed price of $60.00 per Bbl WTI, Diamondback had identified approximately 5,348 potential economic horizontal locations on the acreage Diamondback operates in the Midland and Delaware Basins, based on Diamondback’s evaluation of applicable geologic and engineering data.
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Sustainable, high margin business unburdened by capital expenses with minimal operating expenses. Our mineral and royalty interests provide us cash flows without the requirement to fund drilling and completion costs or lease operating expenses. Our operating costs consist of certain royalty taxes, gathering, processing and transportation costs and general and administrative expenses, providing us with a low cost structure and high operating margins that generate increasing free cash flow growth in a stable or rising price environment as the underlying production associated with our royalty interests continues to grow.
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Experienced and proven management team. The members of our executive team have an average of over 25 years of industry experience, most of which has been focused on resource play development in the Permian Basin. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with property acquisition. We expect to benefit from the industry relationships of the management team. We believe the experience of our management team is essential for the execution of our business strategy.
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Favorable and stable operating environment. We primarily focus our growth in the Permian Basin, one of the oldest, most prolific hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With over 350,000 wells drilled in the Permian Basin since the 1940s, we believe that the geological and regulatory environment is more stable and predictable, and that we are faced with fewer operational risks, in the Permian Basin as compared to emerging hydrocarbon basins. We believe that the impact of the proven application of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of development and exploration activities as compared to emerging hydrocarbon basins.
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review and verification of historical production data, which data is based on actual production as reported by our operators;
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preparation of reserve estimates by the Executive Vice President–Reservoir Engineering of our general partner or under his direct supervision;
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review by the Executive Vice President–Reservoir Engineering of our general partner of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
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direct reporting responsibilities by the Executive Vice President–Reservoir Engineering of our general partner to the Chief Executive Officer of our general partner;
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verification of property ownership by our land department; and
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no employee’s compensation is tied to the amount of reserves booked.
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December 31,
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2019
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2018
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2017
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Estimated proved developed reserves:
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Oil (MBbls)
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40,857
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29,526
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18,788
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Natural gas (MMcf)
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80,737
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49,681
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29,256
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Natural gas liquids (MBbls)
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14,994
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7,965
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4,536
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Total (MBOE)
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69,307
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45,771
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28,200
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Estimated proved undeveloped reserves:
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Oil (MBbls)
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13,563
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12,352
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7,097
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Natural gas (MMcf)
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15,037
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11,916
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7,139
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Natural gas liquids (MBbls)
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3,570
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3,027
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1,759
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Total (MBOE)
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19,639
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17,365
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10,046
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Estimated Net Proved Reserves:
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|
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Oil (MBbls)
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54,420
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41,878
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25,885
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Natural gas (MMcf)
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95,774
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61,597
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36,395
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Natural gas liquids (MBbls)
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18,564
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10,992
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6,295
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Total (MBOE)(1)
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88,946
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63,136
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38,246
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Percent proved developed
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78
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%
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72
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%
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74
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%
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(1)
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Estimates of reserves as of December 31, 2019, 2018 and 2017 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, 2019, 2018 and 2017, respectively, in accordance with SEC guidelines applicable to reserve estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
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additions of 7,591 MBOE, primarily from 97 horizontal well locations attributable to extensions resulting from strategic drilling of wells to delineate our acreage position;
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downgrade of PUDs into probable category of 3,153 MBOE for 24 short lateral horizontal wells that are not expected to be drilled due to changes in the development plan and optimization of the inventory;
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the conversion of approximately 5,618 MBOE attributable to PUDs into proved developed reserves;
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acquisitions of approximately 3,347 MBOE; and
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positive revisions of approximately 107 MBOE in PUDs primarily due to changes in type curves and realized prices.
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Year Ended December 31,
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2019
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2018
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2017
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Production Data:
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Oil (MBbls)
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5,123
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4,399
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2,899
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Natural gas (MMcf)
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7,657
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5,840
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3,549
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Natural gas liquids (MBbl)
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1,459
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933
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533
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Combined volumes (MBOE)
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7,858
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6,305
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4,024
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Daily combined volumes (BOE/d)
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21,529
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17,275
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11,023
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Average Prices:
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Oil (per Bbl)
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$
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51.61
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$
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56.13
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$
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48.36
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Natural gas (per Mcf)
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$
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1.06
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$
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2.22
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$
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2.62
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Natural gas liquids (per Bbl)
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$
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14.63
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$
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24.41
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$
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20.02
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Combined (per BOE)
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$
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37.39
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$
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44.83
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$
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39.81
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Basin
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Gross Acreage
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Net Royalty Acreage
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Delaware
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321,308
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11,380
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Midland
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372,563
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12,243
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Eagle Ford Shale
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120,353
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681
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Total acreage
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814,224
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24,304
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•
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the location of wells;
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•
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the method of drilling and casing wells;
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•
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the timing of construction or drilling activities, including seasonal wildlife closures;
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the rates of production or “allowables”;
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the surface use and restoration of properties upon which wells are drilled;
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•
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the plugging and abandoning of wells; and
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•
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notice to, and consultation with, surface owners and other third parties.
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•
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the domestic and foreign supply of oil and natural gas;
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•
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the level of prices and expectations about future prices of oil and natural gas;
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•
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the level of global oil and natural gas exploration and production;
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•
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the cost of exploring for, developing, producing and delivering oil and natural gas;
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•
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the price and quantity of foreign imports;
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•
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political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;
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•
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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
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•
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speculative trading in crude oil and natural gas derivative contracts;
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•
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the level of consumer product demand;
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•
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weather conditions and other natural disasters;
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•
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risks associated with operating drilling rigs;
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•
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technological advances affecting energy consumption;
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•
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the price and availability of alternative fuels;
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•
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domestic and foreign governmental regulations and taxes;
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•
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the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
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•
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the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and
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•
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overall domestic and global economic conditions.
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•
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commodity prices;
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•
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the timing and amount of capital expenditures by our operators, which could be significantly more than anticipated;
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•
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the ability of our operators to access capital;
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•
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the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
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•
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the operators’ expertise, operating efficiency and financial resources;
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•
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approval of other participants in drilling wells;
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•
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the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
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•
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the selection of technology;
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•
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the selection of counterparties for the sale of production; and
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•
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the rate of production of the reserves.
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•
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recoverable reserves;
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•
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future oil and natural gas prices and their applicable differentials;
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•
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operating costs; and
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•
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potential environmental and other liabilities.
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•
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our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to the notes, including any repurchase obligations that may arise thereunder;
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•
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a significant portion of our cash flows could be used to service the senior notes and our other indebtedness, which could reduce the funds available to us for operations and other purposes;
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•
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a high level of debt could increase our vulnerability to general adverse economic and industry conditions;
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•
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the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay distributions and make certain investments;
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•
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a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
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•
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our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to, changes in the economy and in our industry;
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•
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a high level of debt may make it more likely that a reduction in the borrowing base following a periodic redetermination could require us and the Operating Company to repay a portion of the then-outstanding bank borrowings;
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•
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a high level of debt could limit our ability to access the capital markets to raise capital on favorable terms;
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•
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a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and
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•
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we may be vulnerable to interest rate increases, as the borrowings under the Operating Company’s revolving credit facility are at variable interest rates.
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•
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incur or guarantee additional indebtedness;
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•
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make certain investments;
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•
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create additional liens;
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•
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sell or transfer assets;
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•
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lease property as a lessee;
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•
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issue redeemable or preferred equity;
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•
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voluntarily redeem or prepay debt, including the senior notes;
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•
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merge or consolidate with another entity;
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•
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pay dividends or make distributions;
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•
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designate certain of our subsidiaries as unrestricted subsidiaries;
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•
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create unrestricted subsidiaries;
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•
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engage in transactions with affiliates;
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•
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enter into gas imbalance, take-or-pay and similar agreements; and
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•
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enter into certain swap agreements.
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•
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unusual or unexpected geological formations;
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•
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loss of drilling fluid circulation;
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•
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title problems;
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•
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facility or equipment malfunctions;
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•
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unexpected operational events;
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•
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shortages or delivery delays of equipment and services;
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•
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compliance with environmental and other governmental requirements; and
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•
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adverse weather conditions.
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•
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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.
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•
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Neither our partnership agreement nor any other agreement requires Diamondback to pursue a business strategy that favors us.
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•
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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.
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•
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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
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•
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Our general partner determines 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.
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•
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Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.
|
•
|
Our partnership agreement does not restrict our general 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 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.
|
•
|
how to allocate business opportunities among us and its affiliates;
|
•
|
whether to exercise its call right;
|
•
|
how to exercise its voting rights with respect to the units it owns;
|
•
|
whether to exercise its registration rights; and
|
•
|
whether or not to consent to any merger or consolidation of the partnership or any amendment to the partnership agreement.
|
•
|
whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner 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;
|
•
|
our general 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 or 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
|
•
|
our general 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:
|
•
|
approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or
|
•
|
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.
|
•
|
the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;
|
•
|
the amount of cash distributions on each common unit may decrease;
|
•
|
the ratio of our taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding common unit may be diminished; and
|
•
|
the market price of the common units may decline.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(In thousands, except per unit amounts)
|
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total operating income
|
|
$
|
298,283
|
|
|
$
|
288,820
|
|
|
$
|
172,033
|
|
|
$
|
79,146
|
|
|
$
|
74,859
|
|
Total costs and expenses
|
|
104,743
|
|
|
85,833
|
|
|
58,212
|
|
|
88,457
|
|
|
50,484
|
|
|||||
Income (loss) from operations
|
|
193,540
|
|
|
202,987
|
|
|
113,821
|
|
|
(9,311
|
)
|
|
24,375
|
|
|||||
Total other income (expense), net
|
|
(13,912
|
)
|
|
(12,475
|
)
|
|
(2,343
|
)
|
|
(1,588
|
)
|
|
44
|
|
|||||
Income (loss) before income taxes
|
|
179,628
|
|
|
190,512
|
|
|
111,478
|
|
|
(10,899
|
)
|
|
24,419
|
|
|||||
Benefit from income taxes
|
|
(41,582
|
)
|
|
(72,365
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income (loss)
|
|
221,210
|
|
|
262,877
|
|
|
111,478
|
|
|
(10,899
|
)
|
|
24,419
|
|
|||||
Net income attributable to non-controlling interest
|
|
174,929
|
|
|
118,919
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income (loss) attributable to Viper Energy Partners LP
|
|
$
|
46,281
|
|
|
$
|
143,958
|
|
|
$
|
111,478
|
|
|
$
|
(10,899
|
)
|
|
$
|
24,419
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income (loss) attributable to common limited partners per unit:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
0.75
|
|
|
$
|
2.01
|
|
|
$
|
1.07
|
|
|
$
|
(0.13
|
)
|
|
$
|
0.31
|
|
Diluted
|
|
$
|
0.75
|
|
|
$
|
2.01
|
|
|
$
|
1.07
|
|
|
$
|
(0.13
|
)
|
|
$
|
0.31
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted average number of common limited partner units outstanding:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
61,744
|
|
|
71,546
|
|
|
104,318
|
|
|
83,081
|
|
|
79,717
|
|
|||||
Diluted
|
|
61,787
|
|
|
71,626
|
|
|
104,383
|
|
|
83,081
|
|
|
79,727
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash dividends declared per common unit
|
|
$
|
1.76
|
|
|
$
|
2.17
|
|
|
$
|
1.43
|
|
|
$
|
0.80
|
|
|
$
|
0.84
|
|
|
|
December 31,
|
||||||||||||||||||
(In thousands)
|
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
|
$
|
3,602
|
|
|
$
|
22,676
|
|
|
$
|
24,197
|
|
|
$
|
9,213
|
|
|
$
|
539
|
|
Total assets
|
|
2,785,626
|
|
|
1,654,064
|
|
|
1,013,037
|
|
|
670,549
|
|
|
529,731
|
|
|||||
Current liabilities
|
|
13,432
|
|
|
6,022
|
|
|
5,629
|
|
|
2,151
|
|
|
87
|
|
|||||
Long-term debt, net
|
|
586,774
|
|
|
411,000
|
|
|
93,500
|
|
|
120,500
|
|
|
34,500
|
|
|||||
Total unitholders’ equity
|
|
931,135
|
|
|
542,102
|
|
|
913,908
|
|
|
547,898
|
|
|
495,144
|
|
|||||
Total equity
|
|
$
|
2,185,420
|
|
|
$
|
1,237,042
|
|
|
$
|
913,908
|
|
|
$
|
547,898
|
|
|
$
|
495,144
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(In thousands)
|
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
236,691
|
|
|
$
|
244,493
|
|
|
$
|
139,219
|
|
|
$
|
68,627
|
|
|
$
|
63,832
|
|
Net cash used in investing activities
|
|
$
|
(530,572
|
)
|
|
$
|
(614,253
|
)
|
|
$
|
(344,079
|
)
|
|
$
|
(205,721
|
)
|
|
$
|
(43,907
|
)
|
Net cash provided by (used in) financing activities
|
|
$
|
274,807
|
|
|
$
|
368,239
|
|
|
$
|
219,844
|
|
|
$
|
145,768
|
|
|
$
|
(34,496
|
)
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(In thousands)
|
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
Adjusted EBITDA attributable to Viper Energy Partners LP(1)
|
|
$
|
124,374
|
|
|
$
|
140,888
|
|
|
$
|
157,556
|
|
|
$
|
72,660
|
|
|
$
|
68,317
|
|
(1)
|
For more information, please read “—Non-GAAP Financial Measure” below.
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Net income (loss)
|
$
|
221,210
|
|
|
$
|
262,877
|
|
|
$
|
111,478
|
|
|
$
|
(10,899
|
)
|
|
$
|
24,419
|
|
Interest expense, net
|
21,076
|
|
|
13,849
|
|
|
3,164
|
|
|
2,455
|
|
|
1,110
|
|
|||||
Non-cash unit-based compensation expense
|
1,822
|
|
|
2,763
|
|
|
2,395
|
|
|
3,815
|
|
|
3,929
|
|
|||||
Depletion
|
78,178
|
|
|
58,830
|
|
|
40,519
|
|
|
29,820
|
|
|
35,436
|
|
|||||
Impairment
|
—
|
|
|
—
|
|
|
—
|
|
|
47,469
|
|
|
3,423
|
|
|||||
(Gain) loss on revaluation of investment
|
(4,832
|
)
|
|
550
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Benefit from income taxes
|
(41,582
|
)
|
|
(72,365
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Consolidated Adjusted EBITDA
|
275,872
|
|
|
266,504
|
|
|
157,556
|
|
|
72,660
|
|
|
68,317
|
|
|||||
EBITDA attributable to non-controlling interest
|
(151,498
|
)
|
|
(125,616
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Adjusted EBITDA attributable to Viper Energy Partners LP
|
$
|
124,374
|
|
|
$
|
140,888
|
|
|
$
|
157,556
|
|
|
$
|
72,660
|
|
|
$
|
68,317
|
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
Year Ended December 31,
|
||||
|
2019
|
|
2018
|
||
Operating income:
|
|
|
|
||
Royalty income:
|
|
|
|
||
Oil sales
|
89
|
%
|
|
85
|
%
|
Natural gas sales
|
3
|
%
|
|
4
|
%
|
Natural gas liquid sales
|
7
|
%
|
|
8
|
%
|
Lease bonus income
|
1
|
%
|
|
3
|
%
|
|
100
|
%
|
|
100
|
%
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(In thousands)
|
||||||
Operating Results:
|
|
|
|
||||
Operating income:
|
|
|
|
||||
Royalty income
|
$
|
293,811
|
|
|
$
|
282,661
|
|
Lease bonus income
|
4,117
|
|
|
6,029
|
|
||
Other operating income
|
355
|
|
|
130
|
|
||
Total operating income
|
298,283
|
|
|
288,820
|
|
||
Costs and expenses:
|
|
|
|
||||
Production and ad valorem taxes
|
19,076
|
|
|
19,048
|
|
||
Depletion
|
78,178
|
|
|
58,830
|
|
||
General and administrative expenses
|
7,489
|
|
|
7,955
|
|
||
Total costs and expenses
|
104,743
|
|
|
85,833
|
|
||
Income from operations
|
193,540
|
|
|
202,987
|
|
||
Other income (expense):
|
|
|
|
||||
Interest expense, net
|
(21,076
|
)
|
|
(13,849
|
)
|
||
Gain (loss) on revaluation of investment
|
4,832
|
|
|
(550
|
)
|
||
Other income, net
|
2,332
|
|
|
1,924
|
|
||
Total other expense, net
|
(13,912
|
)
|
|
(12,475
|
)
|
||
Income before income taxes
|
179,628
|
|
|
190,512
|
|
||
Benefit from income taxes
|
(41,582
|
)
|
|
(72,365
|
)
|
||
Net income
|
221,210
|
|
|
262,877
|
|
||
Net income attributable to non-controlling interest
|
174,929
|
|
|
118,919
|
|
||
Net income attributable to Viper Energy Partners LP
|
$
|
46,281
|
|
|
$
|
143,958
|
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(In thousands)
|
||||||
Production Data:
|
|
|
|
||||
Oil (MBbls)
|
5,123
|
|
|
4,399
|
|
||
Natural gas (MMcf)
|
7,657
|
|
|
5,840
|
|
||
Natural gas liquids (MBbls)
|
1,459
|
|
|
933
|
|
||
Combined volumes (MBOE)
|
7,858
|
|
|
6,305
|
|
||
|
|
|
|
||||
Average daily oil volumes (BO/d)
|
14,035
|
|
|
12,053
|
|
||
Average daily combined volumes (BOE/d)
|
21,529
|
|
|
17,275
|
|
||
% Oil
|
65
|
%
|
|
70
|
%
|
||
|
|
|
|
||||
Average sales prices:
|
|
|
|
||||
Oil, realized ($/Bbl)
|
$
|
51.61
|
|
|
$
|
56.13
|
|
Natural gas realized ($/Mcf)(1)
|
$
|
1.06
|
|
|
$
|
2.22
|
|
Natural gas liquids ($/Bbl)
|
$
|
14.63
|
|
|
$
|
24.41
|
|
Average price realized ($/BOE)
|
$
|
37.39
|
|
|
$
|
44.83
|
|
|
|
|
|
||||
Average Costs ($/BOE):
|
|
|
|
||||
Production and ad valorem taxes
|
$
|
2.43
|
|
|
$
|
3.02
|
|
General and administrative - cash component
|
0.72
|
|
|
0.82
|
|
||
Total operating expense - cash
|
$
|
3.15
|
|
|
$
|
3.84
|
|
|
|
|
|
||||
General and administrative - non-cash component
|
$
|
0.23
|
|
|
$
|
0.44
|
|
Interest expense, net
|
$
|
2.68
|
|
|
$
|
2.20
|
|
Depletion
|
$
|
9.95
|
|
|
$
|
9.33
|
|
(1)
|
The average realized price of $1.06 per Mcf of natural gas was primarily due to the pricing terms under our operators’ natural gas delivery contracts, which are generally tied to NYMEX price quoted at Henry Hub. Actual volumetric prices realized from the sale of natural gas, however, differ from the quoted NYMEX price as a result of quality and location differentials. During the fourth quarter, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of $(1.22) relative to the NYMEX price quoted at Henry Hub. Our operators may have varying terms under which they sell their natural gas, but we are mostly impacted by location differences resulting from supply and demand imbalances and limited takeaway capacity within the Permian Basin.
|
|
2019 vs. 2018
|
|||||||
|
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
|
$
|
(4.52
|
)
|
5,123
|
|
$
|
(23,153
|
)
|
Natural gas
|
$
|
(1.17
|
)
|
7,657
|
|
(8,922
|
)
|
|
Natural gas liquids
|
$
|
(9.78
|
)
|
1,459
|
|
(14,275
|
)
|
|
Total income due to change in price
|
|
|
$
|
(46,350
|
)
|
|
2019 vs. 2018
|
|||||||
|
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
|
723
|
|
$
|
56.13
|
|
$
|
40,607
|
|
Natural gas
|
1,817
|
|
$
|
2.22
|
|
4,038
|
|
|
Natural gas liquids
|
527
|
|
$
|
24.41
|
|
12,855
|
|
|
Total income due to change in production volumes
|
|
|
57,500
|
|
||||
Total change in income
|
|
|
$
|
11,150
|
|
(1)
|
Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.
|
|
Year Ended December 31,
|
||||||||||||||
|
2019
|
|
2018
|
||||||||||||
|
Amount
|
|
Per BOE
|
|
Amount
|
|
Per BOE
|
||||||||
Production taxes
|
$
|
14,354
|
|
|
$
|
1.83
|
|
|
$
|
13,666
|
|
|
$
|
2.17
|
|
Ad valorem taxes
|
4,722
|
|
|
0.60
|
|
|
5,382
|
|
|
0.85
|
|
||||
Total production and ad valorem taxes
|
$
|
19,076
|
|
|
$
|
2.43
|
|
|
$
|
19,048
|
|
|
$
|
3.02
|
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Net income
|
$
|
221,210
|
|
|
$
|
262,877
|
|
Interest expense, net
|
21,076
|
|
|
13,849
|
|
||
Non-cash unit-based compensation expense
|
1,822
|
|
|
2,763
|
|
||
Depletion
|
78,178
|
|
|
58,830
|
|
||
(Gain) loss on revaluation of investment
|
(4,832
|
)
|
|
550
|
|
||
Benefit from income taxes
|
(41,582
|
)
|
|
(72,365
|
)
|
||
Consolidated Adjusted EBITDA
|
275,872
|
|
|
266,504
|
|
||
EBITDA attributable to non-controlling interest
|
(151,498
|
)
|
|
(125,616
|
)
|
||
Adjusted EBITDA attributable to Viper Energy Partners LP
|
$
|
124,374
|
|
|
$
|
140,888
|
|
|
Year Ended December 31, 2019
|
||||||||||||||
(in thousands)
|
Oil
|
|
Natural gas
|
|
Natural gas liquids
|
|
Total
|
||||||||
Net oil, natural gas and natural gas liquids sales (GAAP)
|
$
|
264,376
|
|
|
$
|
8,092
|
|
|
$
|
21,343
|
|
|
$
|
293,811
|
|
Plus: Gathering and transportation expenses
|
1,328
|
|
|
1,589
|
|
|
1,448
|
|
|
4,365
|
|
||||
Gross oil, natural gas and natural gas liquids sales (non-GAAP)
|
$
|
265,704
|
|
|
$
|
9,681
|
|
|
$
|
22,791
|
|
|
$
|
298,176
|
|
Sales volumes (MBbl/MMcf/MBbl/MBOE)
|
5,123
|
|
|
7,657
|
|
|
1,459
|
|
|
7,858
|
|
||||
Gross sales price (non-GAAP)
|
$
|
51.87
|
|
|
$
|
1.26
|
|
|
$
|
15.62
|
|
|
$
|
37.94
|
|
|
|
|
|
|
|
|
|
||||||||
|
Year Ended December 31, 2018
|
||||||||||||||
(in thousands)
|
Oil
|
|
Natural gas
|
|
Natural gas liquids
|
|
Total
|
||||||||
Net oil, natural gas and natural gas liquids sales (GAAP)
|
$
|
246,922
|
|
|
$
|
12,976
|
|
|
$
|
22,763
|
|
|
$
|
282,661
|
|
Plus: Gathering and transportation expenses
|
765
|
|
|
848
|
|
|
830
|
|
|
2,443
|
|
||||
Gross oil, natural gas and natural gas liquids (non-GAAP)
|
$
|
247,687
|
|
|
$
|
13,824
|
|
|
$
|
23,593
|
|
|
$
|
285,104
|
|
Sales volumes (MBbl/MMcf/MBbl/MBOE)
|
4,399
|
|
|
5,840
|
|
|
933
|
|
|
6,305
|
|
||||
Gross sales price (non-GAAP)
|
$
|
56.30
|
|
|
$
|
2.37
|
|
|
$
|
25.30
|
|
|
$
|
45.22
|
|
Declaration Date
|
|
Quarter
|
|
Amount per Common Unit
|
|
Payment Date
|
|
Amount Distributed to Diamondback
|
||||
|
|
|
|
|
|
|
|
(in thousands)
|
||||
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 31, 2018
|
|
Q4 2017
|
|
$
|
0.460
|
|
|
February 26, 2018
|
|
$
|
33,649
|
|
April 5, 2018
|
|
Q1 2018
|
|
$
|
0.480
|
|
|
April 27, 2018
|
|
$
|
35,112
|
|
July 27, 2018
|
|
Q2 2018
|
|
$
|
0.600
|
|
|
August 20, 2018
|
|
$
|
43,901
|
|
October 23, 2018
|
|
Q3 2018
|
|
$
|
0.580
|
|
|
November 19, 2018
|
|
$
|
42,447
|
|
January 30, 2019
|
|
Q4 2018
|
|
$
|
0.510
|
|
|
February 25, 2019
|
|
$
|
37,326
|
|
April 25, 2019
|
|
Q1 2019
|
|
$
|
0.380
|
|
|
May 20, 2019
|
|
$
|
27,817
|
|
July 28, 2019
|
|
Q2 2019
|
|
$
|
0.470
|
|
|
August 21, 2019
|
|
$
|
34,400
|
|
October 25, 2019
|
|
Q3 2019
|
|
$
|
0.460
|
|
|
November 15, 2019
|
|
$
|
33,668
|
|
February 7, 2020
|
|
Q4 2019
|
|
$
|
0.450
|
|
|
February 28, 2020
|
|
*
|
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Cash Flow Data:
|
|
|
|
||||
Net cash provided by operating activities
|
$
|
236,691
|
|
|
$
|
244,493
|
|
Net cash used in investing activities
|
(530,572
|
)
|
|
(614,253
|
)
|
||
Net cash provided by financing activities
|
274,807
|
|
|
368,239
|
|
||
Net decrease in cash
|
$
|
(19,074
|
)
|
|
$
|
(1,521
|
)
|
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
|
|
Payments Due by Period
|
||||||||||||||||||
|
Total
|
|
2020
|
|
2021-2022
|
|
2023-2024
|
|
Thereafter
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Credit agreement(1)
|
$
|
96,500
|
|
|
$
|
—
|
|
|
$
|
96,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Commitment fees under our credit agreement(2)
|
7,214
|
|
|
2,544
|
|
|
4,670
|
|
|
—
|
|
|
—
|
|
|||||
Senior Notes
|
500,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
500,000
|
|
|||||
Interest expense related to the senior notes(3)
|
210,582
|
|
|
26,875
|
|
|
53,750
|
|
|
53,750
|
|
|
76,207
|
|
|||||
|
$
|
814,296
|
|
|
$
|
29,419
|
|
|
$
|
154,920
|
|
|
$
|
53,750
|
|
|
$
|
576,207
|
|
(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 commitment fees due, which as of December 31, 2019 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.
|
(3)
|
Interest represents the scheduled cash payments on the senior notes.
|
Name
|
Age
|
Position With Our General Partner
|
Travis D. Stice
|
58
|
Chief Executive Officer and Director
|
Kaes Van't Hof
|
33
|
President
|
Teresa L. Dick
|
50
|
Chief Financial Officer, Executive Vice President and Assistant Secretary
|
Russell Pantermuehl
|
60
|
Executive Vice President and Chief Engineer
|
Thomas F. Hawkins
|
65
|
Executive Vice President—Land
|
Matt Zmigrosky
|
41
|
Executive Vice President, General Counsel and Secretary
|
Steven E. West
|
59
|
Chairman of the Board
|
W. Wesley Perry
|
63
|
Director
|
Spencer D. Armour
|
65
|
Director
|
James L. Rubin
|
35
|
Director
|
Rosalind Redfern Grover
|
78
|
Director
|
The Board of Directors of Viper Energy Partners GP LLC
|
Travis D. Stice
|
Steven E. West
|
W. Wesley Perry
|
Spencer D. Armour
|
James L. Rubin
|
Rosalind Redfern Grover
|
Name
|
Fees Earned or Paid in cash(a)
|
Unit Awards(b)
|
Total
|
||||||
Spencer D. Armour(c)(d)(e)
|
$
|
75,000
|
|
$
|
104,094
|
|
$
|
179,094
|
|
Rosalind Redfern Grover(c)(d)(e)
|
$
|
75,000
|
|
$
|
104,094
|
|
$
|
179,094
|
|
W. Wesley Perry(c)(d)(e)
|
$
|
85,000
|
|
$
|
104,094
|
|
$
|
189,094
|
|
James L. Rubin(c)(d)(e)
|
$
|
60,000
|
|
$
|
104,094
|
|
$
|
164,094
|
|
Steven E. West(c)(d)(e)
|
$
|
60,000
|
|
$
|
104,094
|
|
$
|
164,094
|
|
(a)
|
This column reflects the value of a director’s annual retainer.
|
(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.” Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.
|
(c)
|
Each of Ms. Grover and Messrs. Armour, Perry, Rubin and West received a grant of 6,414 phantom units on July 25, 2017, which vested and settled 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.
|
(d)
|
Each of Ms. Grover and Messrs. Armour, Perry, Rubin and West received a grant of 3,063 phantom units on July 10, 2018, which vested and settled on July 10, 2019, pursuant to the LTIP, with each unit having a grant date fair value of $34.33. Each phantom unit is the economic equivalent of one of our common units.
|
(e)
|
Each of Ms. Grover and Messrs. Armour, Perry, Rubin and West received a grant of 3,257 phantom units on July 10, 2019, which will vest and settle on July 10, 2020, pursuant to the LTIP, with each unit having a grant date fair value of $31.96. Each phantom unit is the economic equivalent of one of our common units.
|
•
|
our general partner;
|
•
|
each of our general partner’s directors and executive officers; and
|
•
|
all of our general partner’s directors and executive officers as a group.
|
Name of Beneficial Owner
|
Common Units Beneficially Owned(1)
|
Percentage of Common Units Beneficially Owned
|
|
Diamondback Energy, Inc.
|
731,500
|
|
1%
|
Viper Energy Partners GP LLC
|
—
|
|
—
|
Travis D. Stice(2)
|
112,448
|
|
*
|
Kaes Van't Hof(3)
|
39,624
|
|
*
|
Teresa L. Dick
|
11,540
|
|
*
|
Russell Pantermuehl
|
48,487
|
|
*
|
Thomas F. Hawkins
|
—
|
|
—
|
Matt Zmigrosky(4)
|
6,247
|
|
*
|
Steven E. West(5)
|
59,550
|
|
*
|
W. Wesley Perry(5)
|
45,505
|
|
*
|
Spencer D. Armour(5)
|
9,477
|
|
*
|
James L. Rubin(6)
|
—
|
|
—
|
Rosalind Redfern Grover(5)
|
19,839
|
|
*
|
All directors and executive officers as a group (11 persons)
|
352,717
|
|
*
|
*
|
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 January 31, 2020 and (ii) common units subject to options or phantom units held by that person that are exercisable or vesting within 60 days of January 31, 2020 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 67,805,707 common units outstanding as of January 31, 2020. 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 31, 2020 or within 60 days of January 31, 2020. Unless otherwise noted, the address for each beneficial owner listed below is 500 West Texas Avenue, Suite 1200, 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. Includes 16,011 phantom units that are scheduled to vest on February 16, 2020.
|
(3)
|
Includes 23,136 phantom units that are scheduled to vest on February 16, 2020.
|
(4)
|
Includes 3,667 phantom units that are scheduled to vest on March 1, 2020. Excludes 3,667 phantom units that are scheduled to vest on March 1, 2021.
|
(5)
|
Excludes 3,257 phantom units that are scheduled to vest on July 10, 2020.
|
(6)
|
Excludes 26,505 common units (representing vested phantom units previously granted to Mr. Rubin) and 3,257 phantom units that are scheduled to vest on July 10, 2020, all of which have been assigned by Mr. Rubin to Wexford under the terms of his employment with Wexford.
|
|
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)
|
392,042
|
|
*
|
Kaes Van't Hof(3)
|
13,548
|
|
*
|
Teresa L. Dick(4)
|
37,547
|
|
*
|
Russell Pantermuehl(5)
|
96,980
|
|
*
|
Thomas F. Hawkins(6)
|
12,710
|
|
*
|
Matt Zmigrosky(7)
|
4,054
|
|
*
|
Steven E. West(8)
|
7,461
|
|
*
|
W. Wesley Perry
|
—
|
|
—
|
Spencer D. Armour
|
—
|
|
—
|
James L. Rubin
|
—
|
|
—
|
Rosalind Redfern Grover
|
—
|
|
—
|
All directors and executive officers as a group (11 persons)
|
564,342
|
|
*
|
*
|
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 January 31, 2020 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 31, 2020, 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 67,805,707 shares of common stock outstanding as of January 31, 2020. 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 31, 2020 or within 60 days of January 31, 2020. 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 6,797 restricted stock units that are scheduled to vest on February 21, 2020 and (ii) 10,986 restricted stock units that are scheduled to vest on March 1, 2020. Excludes 10,986 restricted stock units that are scheduled to vest on March 1, 2021. Also excludes (i) 44,460 performance-based restricted stock units awarded to Mr. Stice on February 16, 2017 that will vest effective December 31, 2019 (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 three-year performance period ended on December 31, 2019 by Diamondback’s compensation committee, (ii) 30,585 performance-based restricted stock units awarded to Mr. Stice on February 13, 2018, 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, 2020 and (iii) 49,436 performance-based restricted stock units awarded to Mr. Stice on March 1, 2019, 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, 2021.
|
(3)
|
Includes (i) 1,333 restricted stock units that are scheduled to vest on February 21, 2020 and (ii) 5,127 restricted stock units that are scheduled to vest on March 1, 2020. Excludes (i) 5,127 restricted stock units that are scheduled to vest on March 1, 2021, (ii) 8,790 restricted stock units that are scheduled to vest in five equal annual installments beginning on March 1, 2025, (iii) 23,070 performance-based restricted stock units awarded on March 1, 2019 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, 2021 and (iv) 13,183 performance-based restricted stock units awarded on March 1, 2019 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, 2021 and are scheduled vest in five equal installments beginning on March 1, 2025.
|
(4)
|
Includes (i) 1,866 restricted stock units that are scheduled to vest on February 21, 2020 and (ii) 2,930 restricted stock units that are scheduled to vest on March 1, 2020. Excludes 2,930 restricted stock units that are scheduled to vest on March 1, 2021. Also excludes (i) 11,700 performance-based restricted stock units awarded to Ms. Dick on February 16, 2017 that will vest effective December 31, 2019 (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 three-year performance period ended on December 31, 2019 by Diamondback’s compensation committee, (ii) 8,396 performance-based restricted stock units awarded to Ms. Dick on February 13, 2018, 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, 2020 and (iii) 13,183 performance-based restricted stock units awarded to Ms. Dick on March 1, 2019, 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, 2021.
|
(5)
|
Includes (i) 3,412 restricted stock units that are scheduled to vest on February 21, 2020 and (ii) 5,127 restricted stock units that are scheduled to vest on March 1, 2020. Excludes 5,127 restricted stock units that are scheduled to vest on March 1, 2021. Also excludes (i) 23,400 performance-based restricted stock units awarded to Mr. Pantermuehl on February 16, 2017 that will vest effective December 31, 2019 (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 three-year performance period ended on December 31, 2019 by Diamondback’s compensation committee, (ii) 15,353 performance-based restricted stock units awarded to Mr. Pantermuehl on February 13, 2018, 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, 2020 and (iii) excludes 23,070 performance-based restricted stock units awarded to Mr. Pantermuehl on March 1, 2019, 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, 2021.
|
(6)
|
Includes (i) 1,280 restricted stock units that are scheduled to vest on February 21, 2020 and (ii) 1,905 restricted stock units that are scheduled to vest on March 1, 2020. Excludes 1,905 restricted stock units that are scheduled to vest on March 1, 2021. Also excludes 8,569 performance-based restricted stock units awarded to Mr. Hawkins on March 1, 2019 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, 2021.
|
(7)
|
Includes 2,344 restricted stock units that are scheduled to vest on March 1, 2020. Excludes 2,344 restricted stock units that are scheduled to vest on March 1, 2021. Also excludes 10,546 performance-based restricted stock units awarded to Mr. Zmigrosky on March 1, 2019 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, 2021.
|
(8)
|
Excludes 1,830 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 2020 annual meeting of stockholders of Diamondback.
|
|
|
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 1200
Midland, Texas 79701
|
|
731,500
|
|
1.1
|
%
|
|
90,709,946
|
|
|
100
|
%
|
Wellington Management Group LLP
c/o Wellington Management Company LLP
280 Congress Street
Boston, MA 02210
|
|
9,179,000(3)
|
|
13.5
|
%
|
|
—
|
|
|
—
|
|
FMR LLC
245 Summer Street
Boston, MA 02210
|
|
7,651,509(4)
|
|
11.3
|
%
|
|
—
|
|
|
—
|
|
Santa Elena Minerals, LP(5)
400 W. Illinois, Suite 1300
Midland, TX 79701
|
|
5,152,124
|
|
7.6
|
%
|
|
—
|
|
|
—
|
|
Goldman Sachs Asset Management(6)
200 West Street New York, NY 10282 |
|
4,431,694(7)
|
|
6.5
|
%
|
|
—
|
|
|
—
|
|
Capital World Investors
333 South Hope Street
Los Angeles, CA 90071
|
|
3,721,763(8)
|
|
5.5
|
%
|
|
—
|
|
|
—
|
|
(1)
|
Beneficial ownership is determined in accordance with SEC rules. The percentage of common units beneficially owned is based on 67,805,707 common units outstanding as of January 31, 2020. 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 81,765,429 Class B units directly. Diamondback also has the beneficial ownership of 8,944,517 Class B units, which are held by Energen Resources Corporation, its indirect wholly-owned subsidiary (“Energen Resources”). An aggregate of 90,709,946 Class B units, together with the same aggregate number of units of the Operating Company (each, an “OpCo unit”), held by Diamondback and Energen Resources, are exchangeable from time to time, in their 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 directly. Diamondback also has shared voting and dispositive power of 8,944,517 Class B units held by Energen Resources, which represent approximately 9.9% of the outstanding Class B units. The directors of Diamondback are Travis D. Stice, Steven E. West, Michael P. Cross, David L. Houston, Mark L. Plaumann and Melanie M. Trent. Travis D. Stice is the sole director of Energen Resources.
|
(3)
|
Based solely on Schedule 13G/A jointly filed with the SEC on January 8, 2020 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, 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
|
(4)
|
Based solely on Schedule 13G/A jointly filed with the SEC on February 7, 2020 by FMR LLC (“FMR”) and Abigail P. Johnson. Ms. Johnson is a Director, the Chairman and the Chief Executive Officer of FMR. Members of the Johnson family, including Abigail P. Johnson, are the predominant owners, directly or through trusts, of 49% of the voting power of FMR. Members of the Johnson family may be deemed to form a controlling group with respect to FMR. Neither FMR nor Ms. Johnson has the sole power to vote or direct the voting of the common units owned directly by the various investment companies (“Fidelity Funds”) advised by Fidelity Management & Research Company (“FMR Co.”), a wholly owned subsidiary of FMR, which power resides with the Fidelity Funds’ Boards of Trustees. FMR Co. carries out the voting of the common units under written guidelines established by the Fidelity Funds’ Boards of Trustees. FMR reported sole voting power over 189,187 common units and sole dispositive power over 7,651,509 common units. Ms. Johnson reported sole dispositive power over 7,651,509 common units. Various persons have the right to receive or the power to direct the receipt of dividends from, or the proceeds from the sale of common units. FMR Co. Inc. beneficially owns more than 5% of the common units.
|
(5)
|
Based on Viper’s records.
|
(6)
|
Goldman Sachs Asset Management, L.P. together with GS Investment Strategies, LLC reported as “Goldman Sachs Asset Management.”
|
(7)
|
Based solely on Schedule 13G filed with the SEC on January 31, 2020 by Goldman Sachs Asset Management. Goldman Sachs Asset Management reported shared voting power with respect to 4,261,361 common units and shared dispositive power with respect to 4,431,694 common units.
|
(8)
|
Based solely on Schedule 13G filed with the SEC on February 14, 2020 by Capital World Investors. Capital World Investors reported sole voting power over 3,721,763 common units and sole dispositive power over 3,721,763 common units.
|
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
|
95,248
|
|
$
|
—
|
|
8,797,670
|
|
(1)
|
Our general partner adopted the LTIP in connection with the IPO in June 2014.
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Audit fees(1)
|
$
|
322
|
|
|
$
|
230
|
|
Audit-related fees(2)
|
89
|
|
|
—
|
|
||
Tax fees(3)
|
—
|
|
|
—
|
|
||
All other fees(4)
|
—
|
|
|
—
|
|
||
Total
|
$
|
411
|
|
|
$
|
230
|
|
(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 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.
|
(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.
|
|
3. Exhibits
|
||
Exhibit Number
|
|
Description
|
3.1
|
|
|
3.2
|
|
|
3.3
|
|
|
3.4
|
|
|
4.1*
|
|
|
4.2
|
|
|
4.3
|
|
|
10.1
|
|
|
10.2
|
|
|
10.3+
|
|
|
10.4
|
|
|
10.5
|
|
3. Exhibits
|
||
Exhibit Number
|
|
Description
|
10.6
|
|
|
10.7+
|
|
|
10.8+*
|
|
|
10.9
|
|
|
10.10
|
|
|
10.11
|
|
|
10.12
|
|
|
10.13
|
|
|
10.14
|
|
|
10.15
|
|
|
10.16
|
|
|
21.1*
|
|
|
23.1*
|
|
|
23.2*
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1++
|
|
|
99.1*
|
|
|
101
|
|
The following financial information from the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2019, 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.
|
104.0
|
|
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
|
*
|
Filed herewith.
|
+
|
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.
|
|
|
VIPER ENERGY PARTNERS LP
|
|
Date:
|
February 18, 2020
|
|
|
|
|
By:
|
VIPER ENERGY PARTNERS GP LLC
|
|
|
|
its general partner
|
|
|
|
|
|
|
By:
|
/s/ Travis D. Stice
|
|
|
Name:
|
Travis D. Stice
|
|
|
Title:
|
Chief Executive Officer
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Travis D. Stice
|
|
Chief Executive Officer and Director
|
|
February 18, 2020
|
Travis D. Stice
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Teresa L. Dick
|
|
Chief Financial Officer
|
|
February 18, 2020
|
Teresa L. Dick
|
|
(Principal Financial and Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Steven E. West
|
|
Director
|
|
February 18, 2020
|
Steven E. West
|
|
|
|
|
|
|
|
|
|
/s/ W. Wesley Perry
|
|
Director
|
|
February 18, 2020
|
W. Wesley Perry
|
|
|
|
|
|
|
|
|
|
/s/ Spencer D. Armour
|
|
Director
|
|
February 18, 2020
|
Spencer D. Armour
|
|
|
|
|
|
|
|
|
|
/s/ James L. Rubin
|
|
Director
|
|
February 18, 2020
|
James L. Rubin
|
|
|
|
|
|
|
|
|
|
/s/ Rosalind Redfern Grover
|
|
Director
|
|
February 18, 2020
|
Rosalind Redfern Grover
|
|
|
|
|
|
|
|
|
|
•
|
We tested the design and operating effectiveness of key controls relating to the preparation of the ceiling test calculation, management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Partnership’s oil and gas properties for potential impairment, and management’s estimation of the fair value of acquired mineral and/or royalty interests. Specifically, these controls related to the use of historical information in the estimation of proved reserves derived from the Partnership’s accounting records and the management review controls on information provided to the reservoir engineering specialists and the management review controls on the final proved reserve report prepared by the Partnership’s specialists.
|
•
|
We evaluated the level of knowledge, skill, and ability of the Partnership’s reservoir engineering specialists and their relationship to the Partnership, 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.
|
•
|
For acquisitions of mineral interests during the year in which proved developed producing properties are significant and to the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Partnership’s accounting records, such as historical pricing differentials and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support. Specifically, our audit procedures involved testing management’s assumptions as follows:
|
◦
|
Analyzed the appropriateness of fair value pricing used in the acquisition reserve report to published product pricing on the acquisition closing date;
|
◦
|
Evaluated the net revenue interests used in the acquisition reserve report by inspecting a sample of land and division order records;
|
◦
|
Analyzed, on a sample basis, the appropriateness of management’s estimated future production volumes and the production decline curves; and
|
◦
|
Utilized valuation specialists to compare the acreage value allocated, on a per acre basis, to other recent acquisitions in the same or similar locations.
|
•
|
To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Partnership’s accounting records, such as historical pricing differentials and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows:
|
◦
|
Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
|
◦
|
Evaluated the net revenue interests used in the reserve report by inspecting a sample of land and division order records;
|
◦
|
Evaluated the Partnership’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the operator’s intent to develop the proved undeveloped properties;
|
◦
|
Evaluated the estimated ultimate recovery of proved undeveloped properties to the estimated ultimate recovery of comparable proved developed producing properties; and
|
◦
|
Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In thousands, except unit amounts)
|
||||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
3,602
|
|
|
$
|
22,676
|
|
Royalty income receivable
|
58,089
|
|
|
38,823
|
|
||
Royalty income receivable—related party
|
10,576
|
|
|
3,489
|
|
||
Other current assets
|
397
|
|
|
257
|
|
||
Total current assets
|
72,664
|
|
|
65,245
|
|
||
Property:
|
|
|
|
||||
Oil and natural gas interests, full cost method of accounting ($1,551,767 and $871,485 excluded from depletion at December 31, 2019 and December 31, 2018, respectively)
|
2,868,459
|
|
|
1,716,713
|
|
||
Land
|
5,688
|
|
|
5,688
|
|
||
Accumulated depletion and impairment
|
(326,474
|
)
|
|
(248,296
|
)
|
||
Property, net
|
2,547,673
|
|
|
1,474,105
|
|
||
Deferred tax asset
|
142,466
|
|
|
96,883
|
|
||
Other assets
|
22,823
|
|
|
17,831
|
|
||
Total assets
|
$
|
2,785,626
|
|
|
$
|
1,654,064
|
|
Liabilities and Unitholders’ Equity
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable—related party
|
$
|
150
|
|
|
$
|
—
|
|
Accrued liabilities
|
13,282
|
|
|
6,022
|
|
||
Total current liabilities
|
13,432
|
|
|
6,022
|
|
||
Long-term debt, net
|
586,774
|
|
|
411,000
|
|
||
Total liabilities
|
600,206
|
|
|
417,022
|
|
||
Commitments and contingencies (Note 12)
|
|
|
|
||||
Unitholders’ equity:
|
|
|
|
||||
General partner
|
889
|
|
|
1,000
|
|
||
Common units (67,805,707 units issued and outstanding as of December 31, 2019 and 51,653,956 units issued and outstanding as of December 31, 2018)
|
929,116
|
|
|
540,112
|
|
||
Class B units (90,709,946 units issued and outstanding as of December 31, 2019 and 72,418,500 units issued and outstanding December 31, 2018)
|
1,130
|
|
|
990
|
|
||
Total Viper Energy Partners LP unitholders’ equity
|
931,135
|
|
|
542,102
|
|
||
Non-controlling interest
|
1,254,285
|
|
|
694,940
|
|
||
Total equity
|
2,185,420
|
|
|
1,237,042
|
|
||
Total liabilities and unitholders’ equity
|
$
|
2,785,626
|
|
|
$
|
1,654,064
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(In thousands, except per unit amounts)
|
||||||||||
Operating income:
|
|
|
|
|
|
||||||
Royalty income
|
$
|
293,811
|
|
|
$
|
282,661
|
|
|
$
|
160,163
|
|
Lease bonus income
|
4,117
|
|
|
6,029
|
|
|
11,870
|
|
|||
Other operating income
|
355
|
|
|
130
|
|
|
—
|
|
|||
Total operating income
|
298,283
|
|
|
288,820
|
|
|
172,033
|
|
|||
Costs and expenses:
|
|
|
|
|
|
||||||
Production and ad valorem taxes
|
19,076
|
|
|
19,048
|
|
|
10,608
|
|
|||
Gathering and transportation
|
—
|
|
|
—
|
|
|
789
|
|
|||
Depletion
|
78,178
|
|
|
58,830
|
|
|
40,519
|
|
|||
General and administrative expenses
|
7,489
|
|
|
7,955
|
|
|
6,296
|
|
|||
Total costs and expenses
|
104,743
|
|
|
85,833
|
|
|
58,212
|
|
|||
Income from operations
|
193,540
|
|
|
202,987
|
|
|
113,821
|
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest expense, net
|
(21,076
|
)
|
|
(13,849
|
)
|
|
(3,164
|
)
|
|||
Gain (loss) on revaluation of investment
|
4,832
|
|
|
(550
|
)
|
|
—
|
|
|||
Other income, net
|
2,332
|
|
|
1,924
|
|
|
821
|
|
|||
Total other expense, net
|
(13,912
|
)
|
|
(12,475
|
)
|
|
(2,343
|
)
|
|||
Income before income taxes
|
179,628
|
|
|
190,512
|
|
|
111,478
|
|
|||
Benefit from income taxes
|
(41,582
|
)
|
|
(72,365
|
)
|
|
—
|
|
|||
Net income
|
221,210
|
|
|
262,877
|
|
|
111,478
|
|
|||
Net income attributable to non-controlling interest
|
174,929
|
|
|
118,919
|
|
|
—
|
|
|||
Net income attributable to Viper Energy Partners LP
|
$
|
46,281
|
|
|
$
|
143,958
|
|
|
$
|
111,478
|
|
|
|
|
|
|
|
||||||
Net income attributable to common limited partner units:
|
|
|
|
|
|
||||||
Basic
|
$
|
0.75
|
|
|
$
|
2.01
|
|
|
$
|
1.07
|
|
Diluted
|
$
|
0.75
|
|
|
$
|
2.01
|
|
|
$
|
1.07
|
|
Weighted average number of common limited partner units outstanding:
|
|
|
|
|
|
||||||
Basic
|
61,744
|
|
71,546
|
|
104,318
|
||||||
Diluted
|
61,787
|
|
71,626
|
|
104,383
|
|
Limited Partners
|
|
General Partner
|
|
Non-Controlling Interest
|
|
|
||||||||||||||||||
|
Common
|
|
|
|
Class B
|
|
|
|
Amount
|
|
Amount
|
|
|
||||||||||||
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
|
|
Total
|
||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||
Balance at December 31, 2016
|
87,800
|
|
|
$
|
547,898
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
547,898
|
|
Net proceeds from the issuance of common units - public
|
25,175
|
|
|
369,896
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
369,896
|
|
||||||
Net proceeds from the issuance of common units - Diamondback
|
700
|
|
|
10,067
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,067
|
|
||||||
Common units issued for acquisition
|
175
|
|
|
3,050
|
|
|
|
|
|
|
—
|
|
|
—
|
|
|
3,050
|
|
|||||||
Unit-based compensation
|
32
|
|
|
2,395
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,395
|
|
||||||
Distributions to public
|
|
|
(41,367
|
)
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(41,367
|
)
|
|||||||
Distributions to Diamondback
|
|
|
(89,509
|
)
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(89,509
|
)
|
|||||||
Net income
|
|
|
111,478
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
111,478
|
|
|||||||
Balance at December 31, 2017
|
113,882
|
|
|
913,908
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
913,908
|
|
|||||
Impact of adoption of ASU 2016-01
|
|
|
(18,651
|
)
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18,651
|
)
|
|||||||
Unit exchange related to tax conversion
|
(73,150
|
)
|
|
(545,441
|
)
|
|
73,150
|
|
|
1,000
|
|
|
1,000
|
|
|
545,441
|
|
|
2,000
|
|
|||||
Recapitalization related to tax conversion
|
732
|
|
|
—
|
|
|
(732
|
)
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
|||||
Net proceeds from the issuance of common units - public
|
10,080
|
|
|
303,121
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
303,121
|
|
||||||
Unit-based compensation
|
103
|
|
|
2,763
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,763
|
|
||||||
Unit options exercised
|
8
|
|
|
140
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
140
|
|
||||||
Distributions to public
|
|
|
(98,333
|
)
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(98,333
|
)
|
|||||||
Distributions to Diamondback
|
|
|
(69,655
|
)
|
|
|
|
—
|
|
|
—
|
|
|
(85,454
|
)
|
|
(155,109
|
)
|
|||||||
Distributions to General Partner
|
|
|
(31
|
)
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(31
|
)
|
|||||||
Change in ownership of consolidated subsidiaries, net
|
|
|
(91,667
|
)
|
|
|
|
—
|
|
|
—
|
|
|
116,034
|
|
|
24,367
|
|
|||||||
Net income
|
|
|
143,958
|
|
|
|
|
—
|
|
|
—
|
|
|
118,919
|
|
|
262,877
|
|
|||||||
Balance at December 31, 2018
|
51,654
|
|
|
$
|
540,112
|
|
|
72,419
|
|
|
$
|
990
|
|
|
$
|
1,000
|
|
|
$
|
694,940
|
|
|
$
|
1,237,042
|
|
|
Limited Partners
|
|
General Partner
|
|
Non-Controlling Interest
|
|
|
||||||||||||||||||
|
Common
|
|
|
|
Class B
|
|
|
|
Amount
|
|
Amount
|
|
|
||||||||||||
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
|
|
Total
|
||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||
Balance at December 31, 2018
|
51,654
|
|
|
$
|
540,112
|
|
|
72,419
|
|
|
$
|
990
|
|
|
$
|
1,000
|
|
|
$
|
694,940
|
|
|
$
|
1,237,042
|
|
Net proceeds from the issuance of common units - public
|
10,925
|
|
|
340,860
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
340,860
|
|
|||||
Common units issued for acquisition
|
5,152
|
|
|
124,012
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
124,012
|
|
|||||
Offering costs
|
—
|
|
|
(221
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(221
|
)
|
|||||
Unit-based compensation
|
85
|
|
|
1,822
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,822
|
|
|||||
Class B and OpCo units issued for the Drop-Down acquisition
|
—
|
|
|
—
|
|
|
18,291
|
|
|
250
|
|
|
—
|
|
|
497,162
|
|
|
497,412
|
|
|||||
Distributions to public
|
—
|
|
|
(107,074
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(107,074
|
)
|
|||||
Distributions to Diamondback
|
—
|
|
|
(1,300
|
)
|
|
—
|
|
|
(110
|
)
|
|
—
|
|
|
(131,801
|
)
|
|
(133,211
|
)
|
|||||
Distributions to General Partner
|
—
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
(111
|
)
|
|
—
|
|
|
(80
|
)
|
|||||
Change in ownership of consolidated subsidiaries, net
|
—
|
|
|
(15,054
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,055
|
|
|
4,001
|
|
|||||
Units repurchased for tax withholding
|
(11
|
)
|
|
(353
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(353
|
)
|
|||||
Net income
|
—
|
|
|
46,281
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
174,929
|
|
|
221,210
|
|
|||||
Balance at December 31, 2019
|
67,806
|
|
|
$
|
929,116
|
|
|
90,710
|
|
|
$
|
1,130
|
|
|
$
|
889
|
|
|
$
|
1,254,285
|
|
|
$
|
2,185,420
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(In thousands)
|
||||||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
221,210
|
|
|
$
|
262,877
|
|
|
$
|
111,478
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Benefit from deferred income taxes
|
(41,582
|
)
|
|
(72,516
|
)
|
|
—
|
|
|||
Depletion
|
78,178
|
|
|
58,830
|
|
|
40,519
|
|
|||
(Gain) loss on revaluation of investment
|
(4,832
|
)
|
|
550
|
|
|
—
|
|
|||
Amortization of debt issuance costs
|
978
|
|
|
737
|
|
|
589
|
|
|||
Non-cash unit-based compensation
|
1,822
|
|
|
2,763
|
|
|
2,395
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
||||||
Restricted cash
|
—
|
|
|
—
|
|
|
500
|
|
|||
Royalty income receivable
|
(19,266
|
)
|
|
(13,069
|
)
|
|
(15,711
|
)
|
|||
Royalty income receivable—related party
|
(7,087
|
)
|
|
1,653
|
|
|
(1,672
|
)
|
|||
Accounts payable and accrued liabilities
|
7,091
|
|
|
2,545
|
|
|
1,298
|
|
|||
Accounts payable—related party
|
150
|
|
|
—
|
|
|
—
|
|
|||
Income tax payable
|
169
|
|
|
151
|
|
|
—
|
|
|||
Other current assets
|
(140
|
)
|
|
(28
|
)
|
|
(177
|
)
|
|||
Net cash provided by operating activities
|
236,691
|
|
|
244,493
|
|
|
139,219
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Acquisition of oil and natural gas interests
|
(530,572
|
)
|
|
(610,131
|
)
|
|
(344,079
|
)
|
|||
Acquisition of land
|
—
|
|
|
(4,687
|
)
|
|
—
|
|
|||
Proceeds from sale of assets
|
—
|
|
|
441
|
|
|
—
|
|
|||
Proceeds from the sale of investments
|
—
|
|
|
124
|
|
|
—
|
|
|||
Net cash used in investing activities
|
(530,572
|
)
|
|
(614,253
|
)
|
|
(344,079
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from borrowings under credit facility
|
590,500
|
|
|
691,500
|
|
|
278,500
|
|
|||
Repayment on credit facility
|
(905,000
|
)
|
|
(374,000
|
)
|
|
(305,500
|
)
|
|||
Proceeds from senior notes
|
500,000
|
|
|
—
|
|
|
—
|
|
|||
Debt issuance costs
|
(10,863
|
)
|
|
(1,039
|
)
|
|
(2,259
|
)
|
|||
Proceeds from public offerings
|
340,860
|
|
|
305,773
|
|
|
380,412
|
|
|||
Public offering costs
|
(221
|
)
|
|
(2,652
|
)
|
|
(433
|
)
|
|||
Units purchased for tax withholding
|
(353
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from exercise of unit options
|
—
|
|
|
140
|
|
|
—
|
|
|||
Contributions by members
|
250
|
|
|
2,000
|
|
|
—
|
|
|||
Distributions to partners
|
(240,366
|
)
|
|
(253,483
|
)
|
|
(130,876
|
)
|
|||
Net cash provided by financing activities
|
274,807
|
|
|
368,239
|
|
|
219,844
|
|
|||
Net (decrease) increase in cash
|
(19,074
|
)
|
|
(1,521
|
)
|
|
14,984
|
|
|||
Cash and cash equivalents at beginning of period
|
22,676
|
|
|
24,197
|
|
|
9,213
|
|
|||
Cash and cash equivalents at end of period
|
$
|
3,602
|
|
|
$
|
22,676
|
|
|
$
|
24,197
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(In thousands)
|
||||||||||
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
||||||
Interest paid
|
$
|
13,803
|
|
|
$
|
12,438
|
|
|
$
|
2,589
|
|
Supplemental disclosure of non—cash transactions:
|
|
|
|
|
|
||||||
OpCo units issued for the Drop-Down transaction (Note 3)
|
$
|
497,162
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Common units issued for acquisition
|
$
|
124,012
|
|
|
$
|
—
|
|
|
$
|
3,050
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(In thousands)
|
||||||
Interest payable
|
$
|
6,718
|
|
|
$
|
728
|
|
Ad valorem taxes payable
|
5,632
|
|
|
5,039
|
|
||
Other
|
932
|
|
|
255
|
|
||
Total accrued liabilities
|
$
|
13,282
|
|
|
$
|
6,022
|
|
Standard
|
Description
|
Date of Adoption
|
Effect on Financial Statements or Other Significant Matters
|
Recently Adopted Pronouncements
|
|||
ASU 2016-13, “Financial Instruments - Credit Losses”
|
This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.
|
Q1 2020
|
The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
|
ASU 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”
|
This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels.
|
Q1 2020
|
The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
|
ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”
|
This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement.
|
Q1 2020
|
The Partnership adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
|
ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)”
|
This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis.
|
Q1 2020
|
The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
|
Pronouncements Not Yet Adopted
|
|||
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”
|
This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.
|
Q1 2021
|
This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership does not believe the adoption of this standard will have an impact on its financial position, results of operations or liquidity.
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
Oil and natural gas interests:
|
|
|
|
||||
Subject to depletion
|
$
|
1,316,692
|
|
|
$
|
845,228
|
|
Not subject to depletion
|
1,551,767
|
|
|
871,485
|
|
||
Gross oil and natural gas interests
|
2,868,459
|
|
|
1,716,713
|
|
||
Accumulated depletion and impairment
|
(326,474
|
)
|
|
(248,296
|
)
|
||
Oil and natural gas interests, net
|
2,541,985
|
|
|
1,468,417
|
|
||
Land
|
5,688
|
|
|
5,688
|
|
||
Property, net of accumulated depletion and impairment
|
$
|
2,547,673
|
|
|
$
|
1,474,105
|
|
|
|
|
|
||||
Balance of costs not subject to depletion:
|
|
|
|
||||
Incurred in 2019
|
$
|
827,680
|
|
|
|
||
Incurred in 2018
|
460,977
|
|
|
|
|||
Incurred in 2017
|
263,110
|
|
|
|
|||
Total not subject to depletion
|
$
|
1,551,767
|
|
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(in thousands)
|
||||||
5.375 % Senior Notes due 2027
|
$
|
500,000
|
|
|
$
|
—
|
|
Revolving credit facility
|
96,500
|
|
|
411,000
|
|
||
Unamortized debt issuance costs
|
(2,458
|
)
|
|
—
|
|
||
Unamortized discount costs
|
(7,268
|
)
|
|
—
|
|
||
Total long-term debt
|
$
|
586,774
|
|
|
$
|
411,000
|
|
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
|
|
Phantom
Units |
|
Weighted Average
Grant-Date Fair Value |
|||
Unvested at December 31, 2018
|
125,053
|
|
|
$
|
23.44
|
|
Granted
|
56,582
|
|
|
$
|
30.33
|
|
Vested
|
(85,359
|
)
|
|
$
|
23.96
|
|
Forfeited
|
(1,028
|
)
|
|
$
|
42.50
|
|
Unvested at December 31, 2019
|
95,248
|
|
|
$
|
26.87
|
|
|
Common Units
|
|
Balance at December 31, 2018
|
51,653,956
|
|
Common units issued in public offerings
|
10,925,000
|
|
Common units vested and issued under the LTIP
|
85,359
|
|
Units repurchased for tax withholding
|
(10,732
|
)
|
Common units issued for acquisition
|
5,152,124
|
|
Balance at December 31, 2019
|
67,805,707
|
|
|
Class B Units
|
|
Balance at December 31, 2018
|
72,418,500
|
|
Units issued for the Drop-Down
|
18,291,446
|
|
Balance at December 31, 2019
|
90,709,946
|
|
Declaration Date
|
|
Quarter
|
|
Amount per Common Unit
|
|
Payment Date
|
|
Amount Distributed to Diamondback
|
||||
|
|
|
|
|
|
|
|
(in thousands)
|
||||
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 31, 2018
|
|
Q4 2017
|
|
$
|
0.460
|
|
|
February 26, 2018
|
|
$
|
33,649
|
|
April 5, 2018
|
|
Q1 2018
|
|
$
|
0.480
|
|
|
April 27, 2018
|
|
$
|
35,112
|
|
July 27, 2018
|
|
Q2 2018
|
|
$
|
0.600
|
|
|
August 20, 2018
|
|
$
|
43,901
|
|
October 23, 2018
|
|
Q3 2018
|
|
$
|
0.580
|
|
|
November 19, 2018
|
|
$
|
42,447
|
|
January 30, 2019
|
|
Q4 2018
|
|
$
|
0.510
|
|
|
February 25, 2019
|
|
$
|
37,326
|
|
April 25, 2019
|
|
Q1 2019
|
|
$
|
0.380
|
|
|
May 20, 2019
|
|
$
|
27,817
|
|
July 28, 2019
|
|
Q2 2019
|
|
$
|
0.470
|
|
|
August 21, 2019
|
|
$
|
34,400
|
|
October 25, 2019
|
|
Q3 2019
|
|
$
|
0.460
|
|
|
November 15, 2019
|
|
$
|
33,668
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(In thousands, except per unit amounts)
|
||||||||||
Net income attributable to the period
|
$
|
46,281
|
|
|
$
|
143,958
|
|
|
$
|
111,478
|
|
Weighted average common units outstanding:
|
|
|
|
|
|
||||||
Basic weighted average common units outstanding
|
61,744
|
|
|
71,546
|
|
|
104,318
|
|
|||
Effect of dilutive securities:
|
|
|
|
|
|
||||||
Potential common units issuable
|
43
|
|
|
80
|
|
|
65
|
|
|||
Diluted weighted average common units outstanding
|
61,787
|
|
|
71,626
|
|
|
104,383
|
|
|||
Net income per common unit, basic
|
$
|
0.75
|
|
|
$
|
2.01
|
|
|
$
|
1.07
|
|
Net income per common unit, diluted
|
$
|
0.75
|
|
|
$
|
2.01
|
|
|
$
|
1.07
|
|
|
Year Ended December 31,
|
|||||||
|
2019
|
|
2018
|
|
2017
|
|||
|
(in thousands)
|
|||||||
Restricted stock units
|
—
|
|
|
1
|
|
|
40
|
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(In thousands)
|
||||||
Current income tax provision (benefit):
|
|
|
|
||||
Federal
|
$
|
—
|
|
|
$
|
—
|
|
State
|
—
|
|
|
151
|
|
||
Total current income tax provision
|
—
|
|
|
151
|
|
||
Deferred income tax provision (benefit):
|
|
|
|
||||
Federal
|
(41,582
|
)
|
|
(72,516
|
)
|
||
State
|
—
|
|
|
—
|
|
||
Total deferred income tax provision (benefit)
|
(41,582
|
)
|
|
(72,516
|
)
|
||
Total benefit from income taxes
|
$
|
(41,582
|
)
|
|
$
|
(72,365
|
)
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(In thousands)
|
||||||
Income tax expense (benefit) at the federal statutory rate (21%)
|
$
|
37,722
|
|
|
$
|
40,008
|
|
Impact of net income attributable to the pre-incorporation period
|
—
|
|
|
(14,279
|
)
|
||
Impact of nontaxable noncontrolling interest
|
(36,735
|
)
|
|
(24,973
|
)
|
||
State income tax expense (benefit), net of federal tax effect
|
—
|
|
|
119
|
|
||
Deferred taxes related to change in tax status
|
(42,424
|
)
|
|
(72,787
|
)
|
||
Other, net
|
(145
|
)
|
|
(453
|
)
|
||
Provision for (benefit from) income taxes
|
$
|
(41,582
|
)
|
|
$
|
(72,365
|
)
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(In thousands)
|
||||||
Deferred tax assets:
|
|
|
|
||||
Net operating loss and interest expense carryforwards (indefinite life carryforward)
|
$
|
7,958
|
|
|
$
|
2,131
|
|
Investment in the Operating Company
|
134,272
|
|
|
94,468
|
|
||
Other
|
237
|
|
|
284
|
|
||
Total deferred tax assets
|
142,467
|
|
|
96,883
|
|
||
Valuation allowance
|
(1
|
)
|
|
—
|
|
||
Net deferred tax assets
|
142,466
|
|
|
96,883
|
|
||
Deferred tax liabilities:
|
|
|
|
||||
Oil and natural gas properties and equipment
|
—
|
|
|
—
|
|
||
Other
|
—
|
|
|
—
|
|
||
Total deferred tax liabilities
|
—
|
|
|
—
|
|
||
Net deferred tax assets (liabilities)
|
$
|
142,466
|
|
|
$
|
96,883
|
|
|
(in thousands)
|
||
Fair value of investment as of December 31, 2018
|
$
|
14,525
|
|
Gain on investment
|
4,832
|
|
|
Fair value of investment as of December 31, 2019
|
$
|
19,357
|
|
|
(in thousands)
|
||
Fair value of investment as of December 31, 2017
|
$
|
33,851
|
|
Impact of adoption of Accounting Standards Update 2016-01
|
(18,651
|
)
|
|
Disposal of shares
|
(125
|
)
|
|
Loss on investment
|
(550
|
)
|
|
Fair value of investment as of December 31, 2018
|
$
|
14,525
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
||||||||
|
(in thousands)
|
||||||||||||||
Debt:
|
|
|
|
|
|
|
|
||||||||
Revolving credit facility
|
$
|
96,500
|
|
|
$
|
96,500
|
|
|
$
|
411,000
|
|
|
$
|
411,000
|
|
5.375% Senior Notes due 2027(1)
|
$
|
490,274
|
|
|
$
|
521,100
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
(In thousands)
|
||||||
Oil and natural gas interests:
|
|
|
|
||||
Proved
|
$
|
1,316,692
|
|
|
$
|
845,228
|
|
Unproved
|
1,551,767
|
|
|
871,485
|
|
||
Total oil and natural gas interests
|
2,868,459
|
|
|
1,716,713
|
|
||
Accumulated depletion and impairment
|
(326,474
|
)
|
|
(248,296
|
)
|
||
Net oil and natural gas interests capitalized
|
$
|
2,541,985
|
|
|
$
|
1,468,417
|
|
|
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(In thousands)
|
||||||||||
Acquisition costs:
|
|
|
|
|
|
||||||
Proved properties
|
$
|
471,464
|
|
|
$
|
256,055
|
|
|
$
|
55,948
|
|
Unproved properties
|
680,282
|
|
|
356,761
|
|
|
287,131
|
|
|||
Total
|
$
|
1,151,746
|
|
|
$
|
612,816
|
|
|
$
|
343,079
|
|
|
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(In thousands)
|
||||||||||
Royalty income
|
$
|
293,811
|
|
|
$
|
282,661
|
|
|
$
|
160,163
|
|
Production and ad valorem taxes
|
(19,076
|
)
|
|
(19,048
|
)
|
|
(10,608
|
)
|
|||
Gathering and transportation
|
—
|
|
|
—
|
|
|
(789
|
)
|
|||
Depletion
|
(78,178
|
)
|
|
(58,830
|
)
|
|
(40,519
|
)
|
|||
Income tax expense
|
(842
|
)
|
|
(422
|
)
|
|
—
|
|
|||
Results of operations from oil, natural gas and natural gas liquids
|
$
|
195,715
|
|
|
$
|
204,361
|
|
|
$
|
108,247
|
|
|
Oil
(Bbls) |
|
Natural Gas Liquids
(Bbls) |
|
Natural Gas
(Mcf) |
|||
|
(In thousands)
|
|||||||
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|||
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
|
|
Purchase of reserves in place
|
5,394
|
|
|
1,163
|
|
|
16,486
|
|
Extensions and discoveries
|
13,858
|
|
|
3,359
|
|
|
13,992
|
|
Revisions of previous estimates
|
1,140
|
|
|
1,108
|
|
|
564
|
|
Production
|
(4,399
|
)
|
|
(933
|
)
|
|
(5,840
|
)
|
As of December 31, 2018
|
41,878
|
|
|
10,992
|
|
|
61,597
|
|
Purchase of reserves in place
|
12,949
|
|
|
4,895
|
|
|
24,423
|
|
Extensions and discoveries
|
11,526
|
|
|
3,095
|
|
|
14,822
|
|
Revisions of previous estimates
|
(6,810
|
)
|
|
1,041
|
|
|
2,589
|
|
Production
|
(5,123
|
)
|
|
(1,459
|
)
|
|
(7,657
|
)
|
As of December 31, 2019
|
54,420
|
|
|
18,564
|
|
|
95,774
|
|
|
|
|
|
|
|
|||
Proved Developed Reserves:
|
|
|
|
|
|
|||
December 31, 2017
|
18,788
|
|
|
4,536
|
|
|
29,256
|
|
December 31, 2018
|
29,526
|
|
|
7,965
|
|
|
49,681
|
|
December 31, 2019
|
40,857
|
|
|
14,994
|
|
|
80,737
|
|
|
|
|
|
|
|
|||
Proved Undeveloped Reserves:
|
|
|
|
|
|
|||
December 31, 2017
|
7,097
|
|
|
1,759
|
|
|
7,139
|
|
December 31, 2018
|
12,352
|
|
|
3,027
|
|
|
11,916
|
|
December 31, 2019
|
13,563
|
|
|
3,570
|
|
|
15,037
|
|
|
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(In thousands)
|
||||||||||
Future cash inflows
|
$
|
3,218,257
|
|
|
$
|
2,962,386
|
|
|
$
|
1,445,883
|
|
Future production taxes
|
(237,181
|
)
|
|
(200,079
|
)
|
|
(125,564
|
)
|
|||
Future income tax expense
|
(150,373
|
)
|
|
(273,643
|
)
|
|
(6,932
|
)
|
|||
Future net cash flows
|
2,830,703
|
|
|
2,488,664
|
|
|
1,313,387
|
|
|||
10% discount to reflect timing of cash flows
|
(1,512,315
|
)
|
|
(1,349,282
|
)
|
|
(688,039
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
1,318,388
|
|
|
$
|
1,139,382
|
|
|
$
|
625,348
|
|
|
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
Unweighted Arithmetic Average
|
||||||||||
|
First-Day-of-the-Month Prices
|
||||||||||
Oil (per Bbl)
|
$
|
52.86
|
|
|
$
|
61.46
|
|
|
$
|
48.21
|
|
Natural gas (per Mcf)
|
$
|
0.51
|
|
|
$
|
1.84
|
|
|
$
|
2.13
|
|
Natural gas liquids (per Bbl)
|
$
|
15.79
|
|
|
$
|
25.04
|
|
|
$
|
19.15
|
|
|
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(In thousands)
|
||||||||||
Standardized measure of discounted future net cash flows at the beginning of the period
|
$
|
1,139,382
|
|
|
$
|
625,348
|
|
|
$
|
412,581
|
|
Purchase of minerals in place
|
339,814
|
|
|
180,990
|
|
|
54,662
|
|
|||
Sales of oil and natural gas, net of production costs
|
(274,735
|
)
|
|
(266,055
|
)
|
|
(149,555
|
)
|
|||
Extensions and discoveries
|
330,097
|
|
|
423,540
|
|
|
214,479
|
|
|||
Net changes in prices and production costs
|
(301,182
|
)
|
|
187,592
|
|
|
99,382
|
|
|||
Revisions of previous quantity estimates
|
(114,409
|
)
|
|
52,487
|
|
|
(50,773
|
)
|
|||
Net changes in income taxes
|
56,502
|
|
|
(123,804
|
)
|
|
(1,129
|
)
|
|||
Accretion of discount
|
126,650
|
|
|
62,867
|
|
|
41,477
|
|
|||
Net changes in timing of production and other
|
16,269
|
|
|
(3,583
|
)
|
|
4,224
|
|
|||
Standardized measure of discounted future net cash flows at the end of the period
|
$
|
1,318,388
|
|
|
$
|
1,139,382
|
|
|
$
|
625,348
|
|
|
2019
|
||||||||||||||
|
First
Quarter |
|
Second
Quarter |
|
Third
Quarter |
|
Fourth
Quarter |
||||||||
|
(In thousands, except per unit amounts)
|
||||||||||||||
Operating income
|
$
|
61,590
|
|
|
$
|
72,194
|
|
|
$
|
71,788
|
|
|
$
|
92,711
|
|
Income from operations
|
40,004
|
|
|
49,570
|
|
|
46,555
|
|
|
57,411
|
|
||||
Income tax expense (benefit)
|
(34,608
|
)
|
|
180
|
|
|
(7,480
|
)
|
|
326
|
|
||||
Net income
|
74,311
|
|
|
47,274
|
|
|
51,097
|
|
|
48,528
|
|
||||
Net income attributable to non-controlling interest
|
40,532
|
|
|
45,009
|
|
|
43,151
|
|
|
46,237
|
|
||||
Net income attributable to Viper Energy Partners LP
|
$
|
33,779
|
|
|
$
|
2,265
|
|
|
$
|
7,946
|
|
|
$
|
2,291
|
|
Net income attributable to common limited partners per unit:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.61
|
|
|
$
|
0.04
|
|
|
$
|
0.13
|
|
|
$
|
0.03
|
|
Diluted
|
$
|
0.61
|
|
|
$
|
0.04
|
|
|
$
|
0.13
|
|
|
$
|
0.03
|
|
|
2018
|
||||||||||||||
|
First
Quarter |
|
Second
Quarter |
|
Third
Quarter |
|
Fourth
Quarter |
||||||||
|
(In thousands, except per unit amounts)
|
||||||||||||||
Operating income
|
$
|
62,178
|
|
|
$
|
75,263
|
|
|
$
|
77,714
|
|
|
$
|
73,665
|
|
Income from operations
|
43,703
|
|
|
54,926
|
|
|
54,846
|
|
|
49,512
|
|
||||
Income tax expense (benefit)
|
—
|
|
|
(71,878
|
)
|
|
764
|
|
|
(1,251
|
)
|
||||
Net income
|
42,896
|
|
|
128,464
|
|
|
50,812
|
|
|
40,705
|
|
||||
Net income attributable to non-controlling interest
|
—
|
|
|
29,060
|
|
|
48,466
|
|
|
41,393
|
|
||||
Net income (loss) attributable to Viper Energy Partners LP
|
$
|
42,896
|
|
|
$
|
99,404
|
|
|
$
|
2,346
|
|
|
$
|
(688
|
)
|
Net income attributable to common limited partners per unit:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.38
|
|
|
$
|
1.36
|
|
|
$
|
0.05
|
|
|
$
|
(0.01
|
)
|
Diluted
|
$
|
0.38
|
|
|
$
|
1.35
|
|
|
$
|
0.05
|
|
|
$
|
(0.01
|
)
|
Issuance of additional units
|
|
No approval right.
|
Amendment of the partnership agreement
|
|
Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority.
|
Merger of our partnership or the sale of all or substantially all of our assets
|
|
Unit majority in certain circumstances.
|
Dissolution of our partnership
|
|
Unit majority.
|
Continuation of our business upon dissolution
|
|
Unit majority.
|
Withdrawal of our general partner
|
|
Under most circumstances, the approval of a unit majority, excluding units held by our general partner and its affiliates, if any, is required for the withdrawal of our general partner prior to June 30, 2024 in a manner that would cause a dissolution of our partnership.
|
Removal of our general partner
|
|
Not less than 66 2/3% of the outstanding units, including units held by our general partner and its affiliates.
|
Transfer of our general partner interest
|
|
No approval right.
|
Transfer of ownership interests in our general partner
|
|
No approval right.
|
|
•
|
|
enlarge the obligations of any limited partner without such limited partner's consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
|
|
•
|
|
enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.
|
|
•
|
|
a change in our name, the location of our principal place of business, our registered agent or our registered office;
|
|
•
|
|
the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
|
|
•
|
|
a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state;
|
|
•
|
|
an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;
|
|
•
|
|
an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;
|
|
•
|
|
any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
|
|
•
|
|
an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
|
|
•
|
|
any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;
|
|
•
|
|
a change in our fiscal year or taxable year and related changes;
|
|
•
|
|
conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or
|
|
•
|
|
any other amendments substantially similar to any of the matters described in the clauses above.
|
|
•
|
|
do not adversely affect the limited partners (including any particular class of partnership interests as compared to other classes of partnership interests) in any material respect;
|
|
•
|
|
are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
|
|
•
|
|
are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;
|
|
•
|
|
are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
|
|
•
|
|
are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
|
|
•
|
|
to remove or replace our general partner;
|
|
•
|
|
to approve some amendments to our partnership agreement; or
|
|
•
|
|
to take other action under our partnership agreement
|
|
•
|
|
the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
|
|
•
|
|
there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;
|
|
•
|
|
the entry of a decree of judicial dissolution of our partnership; or
|
|
•
|
|
the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.
|
|
•
|
|
arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);
|
|
•
|
|
brought in a derivative manner on our behalf;
|
|
•
|
|
asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;
|
|
•
|
|
asserting a claim arising pursuant to any provision of the Delaware Act; or
|
|
•
|
|
asserting a claim governed by the internal affairs doctrine
|
|
•
|
|
the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
|
|
•
|
|
the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.
|
|
•
|
|
a current list of the name and last known address of each record holder;
|
|
•
|
|
copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed; and
|
|
•
|
|
such other information regarding our affairs as our general partner determines is just and reasonable.
|
|
•
|
|
surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
|
|
•
|
|
special charges for services requested by a holder of a common unit or Class B Unit; and
|
|
•
|
|
other similar fees or charges.
|
|
•
|
|
represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;
|
|
•
|
|
automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and
|
|
•
|
|
gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation.
|
Date Phantom Units Become Vested Phantom Units
|
Number of Phantom Units that Become Vested Phantom Units
|
|
|
|
|
|
|
Date Phantom Units are Settled
|
Number of Phantom Units that are Settled by Issuance of Units
|
|
|
|
|
|
|
|
|
|
VIPER ENERGY PARTNERS GP LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated:
|
_________________
|
By:
|
________________________________
|
|
|
|
Travis D. Stice, Chief Executive Officer
|
|
|
|
AWARD RECIPIENT
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated:
|
_________________
|
|
________________________________
|
|
/s/ Ryder Scott Company, L.P.
|
|
|
|
|
|
RYDER SCOTT COMPANY, L.P.
|
|
|
TBPE Firm Registration No. F-1580
|
1.
|
I have reviewed this Annual Report on Form 10-K of Viper Energy Partners LP (the “registrant”).
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
|
|
|
Date:
|
February 18, 2020
|
|
/s/ Travis D. Stice
|
|
|
|
Travis D. Stice
|
|
|
|
Chief Executive Officer
|
|
|
|
Viper Energy Partners GP LLC
|
|
|
|
(as general partner of Viper Energy Partners LP)
|
1.
|
I have reviewed this Annual Report on Form 10-K of Viper Energy Partners LP (the “registrant”).
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
|
|
|
Date:
|
February 18, 2020
|
|
/s/ Teresa L. Dick
|
|
|
|
Teresa L. Dick
|
|
|
|
Chief Financial Officer
|
|
|
|
Viper Energy Partners GP LLC
|
|
|
|
(as general partner of Viper Energy Partners LP)
|
|
|
|
|
Date:
|
February 18, 2020
|
|
/s/ Travis D. Stice
|
|
|
|
Travis D. Stice
|
|
|
|
Chief Executive Officer
|
|
|
|
Viper Energy Partners GP LLC
|
|
|
|
(as general partner of Viper Energy Partners LP)
|
|
|
|
|
Date:
|
February 18, 2020
|
|
/s/ Teresa L. Dick
|
|
|
|
Teresa L. Dick
|
|
|
|
Chief Financial Officer
|
|
|
|
Viper Energy Partners GP LLC
|
|
|
|
(as general partner of Viper Energy Partners LP)
|
|
|
|
|
|
|
|
|
|
|
|
|
\s\ Val Rick Robinson
|
Val Rick Robinson, P.E.
|
TBPE License No. 105137
|
Managing Senior Vice President
|
As of December 31, 2019
|
|
|
Proved
|
||||||||||
|
|
Developed
|
|
|
|
Total
|
||||||
|
|
Producing
|
|
Undeveloped
|
|
Proved
|
||||||
Net Reserves
|
|
|
|
|
|
|
||||||
Oil/Condensate – Mbbl
|
|
40,857
|
|
|
13,563
|
|
|
54,420
|
|
|||
Plant Products – Mbbl
|
|
14,994
|
|
|
3,570
|
|
|
18,564
|
|
|||
Gas – MMcf
|
|
80,737
|
|
|
15,037
|
|
|
95,774
|
|
|||
MBOE
|
|
69,307
|
|
|
19,639
|
|
|
88,946
|
|
|||
|
|
|
|
|
|
|
||||||
Income Data ($M)
|
|
|
|
|
|
|
||||||
Future Gross Revenue
|
|
|
$2,317,872
|
|
|
|
$741,187
|
|
|
|
$3,059,059
|
|
Deductions
|
|
58,807
|
|
|
19,176
|
|
|
77,983
|
|
|||
Future Net Income (FNI)
|
|
|
$2,259,065
|
|
|
|
$722,011
|
|
|
|
$2,981,076
|
|
|
|
|
|
|
|
|
||||||
Discounted FNI @ 10%
|
|
|
$1,036,004
|
|
|
|
$353,004
|
|
|
|
$1,389,008
|
|
|
|
Discounted Future Net Income ($M)
|
||
|
|
As of December 31, 2019
|
||
Discount Rate
|
|
Total
|
|
|
Percent
|
|
Proved
|
|
|
|
|
|
|
|
5
|
|
$1,850,832
|
|
|
15
|
|
$1,138,082
|
|
|
20
|
|
$977,996
|
|
|
30
|
|
$781,477
|
|
Geographic Area
|
Product
|
Price
Reference
|
Average
Benchmark
Prices
|
Average Realized
Prices
|
North America
|
|
|
|
|
|
Oil/Condensate
|
WTI Cushing
|
$55.69/bbl
|
$52.86/bbl
|
United States
|
NGLs
|
WTI Cushing
|
$55.69/bbl
|
$15.79/bbl
|
|
Gas
|
Henry Hub
|
$2.58/MMBTU
|
$0.51/Mcf
|
(1)
|
completion intervals that are open at the time of the estimate but which have not yet started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|