ý | ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
¨ | TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 45-4502447 | ||
(State or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification Number) | ||
500 West Texas, Suite 1200 Midland, Texas | 79701 | ||
(Address of Principal Executive Offices) | (Zip Code) |
Securities registered pursuant to Section 12(b) of the Act: | ||||||
Title of Each Class | Name of Each Exchange on Which Registered | |||||
Common Stock, par value $0.01 per share | The Nasdaq Stock Market LLC | |||||
Securities registered pursuant to Section 12(g) of the Act: None |
Large Accelerated Filer | ý | Accelerated Filer | ¨ | |||
Non-Accelerated Filer | ¨ | Smaller Reporting Company | ¨ | |||
Emerging Growth Company | o |
Page | |
PART I | |
PART II | |
PART III | |
PART IV | |
3-D seismic | 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. |
Basin | A large depression on the earth’s surface in which sediments accumulate. |
Bbl | Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons. |
Bbls/d | Barrels per day. |
BOE | Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. |
BOE/d | Barrels of oil equivalent per day. |
Brent | Brent sweet light crude oil. |
British Thermal Unit or BTU | The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. |
Completion | 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. |
Condensate | Liquid hydrocarbons associated with the production that is primarily natural gas. |
Crude oil | Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources. |
Developed acreage | Acreage assignable to productive wells. |
Development costs | Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves. |
Differential | 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. |
Dry hole or dry well | 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. |
Estimated Ultimate Recovery or EUR | Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. |
Exploitation | 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. |
Field | 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. |
Finding and development costs | 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. |
Fracturing | 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. |
Gross acres or gross wells | The total acres or wells, as the case may be, in which a working interest is owned. |
Horizontal drilling | 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. |
Horizontal wells | Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms. |
MBbls | Thousand barrels of crude oil or other liquid hydrocarbons. |
MBOE | 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. |
Mcf | Thousand cubic feet of natural gas. |
Mcf/d | Thousand cubic feet of natural gas per day. |
Mineral interests | The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources. |
MMBtu | Million British Thermal Units. |
MMcf | Million cubic feet of natural gas. |
Net acres or net wells | The sum of the fractional working interest owned in gross acres. |
Net revenue interest | An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests. |
Net royalty acres | Gross acreage multiplied by the average royalty interest. |
Oil and natural gas properties | Tracts of land consisting of properties to be developed for oil and natural gas resource extraction. |
Operator | The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease. |
Play | A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type. |
Plugging and abandonment | Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells. |
PUD | Proved undeveloped. |
Productive well | A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. |
Prospect | A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons. |
Proved developed reserves | Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. |
Proved reserves | The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. |
Proved undeveloped reserves | Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. |
Recompletion | The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production. |
Reserves | Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). |
Reservoir | A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs. |
Resource play | A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type. |
Royalty interest | An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations. |
Spacing | The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies. |
Stratigraphic play | An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process. |
Structural play | An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata. |
Tight formation | A formation with low permeability that produces natural gas with very low flow rates for long periods of time. |
Undeveloped acreage | Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves. |
Working interest | 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. |
WTI | West Texas Intermediate. |
2012 Plan | The Company’s 2012 Equity Incentive Plan. |
Bison | Bison Drilling and Field Services, LLC. |
Company | Diamondback Energy, Inc., a Delaware corporation, together with its subsidiaries. |
EPA | U.S. Environmental Protection Agency. |
Exchange Act | The Securities Exchange Act of 1934, as amended. |
FERC | Federal Energy Regulatory Commission. |
GAAP | Accounting principles generally accepted in the United States. |
General Partner | Viper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership. |
2024 Indenture | The indenture relating to the 2024 Senior Notes, dated as of October 28, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented. |
2025 Indenture | The indenture relating to the 2025 Senior Notes, dated as of December 20, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented. |
NYMEX | New York Mercantile Exchange. |
OSHA | Federal Occupational Safety and Health Act. |
Partnership | Viper Energy Partners LP, a Delaware limited partnership. |
Partnership agreement | The first amended and restated agreement of limited partnership, dated as of June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the Viper Offering. |
Ryder Scott | Ryder Scott Company, L.P. |
SEC | Securities and Exchange Commission. |
Securities Act | The Securities Act of 1933, as amended. |
2024 Senior Notes | The Company’s 4.750% senior unsecured notes due 2024 in the aggregate principal amount of $500 million. |
2025 Senior Notes | The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $500 million. |
Senior Notes | The 2024 Senior Notes and the 2025 Senior Notes. |
Viper | Viper Energy Partners L.P. |
Viper LTIP | Viper Energy Partners L.P. Long Term Incentive Plan. |
Viper Offering | The Partnerships’ initial public offering. |
Wells Fargo | Wells Fargo Bank, National Association. |
• | business strategy; |
• | exploration and development drilling prospects, inventories, projects and programs; |
• | oil and natural gas reserves; |
• | acquisitions |
• | identified drilling locations; |
• | ability to obtain permits and governmental approvals; |
• | technology; |
• | financial strategy; |
• | realized oil and natural gas prices; |
• | production; |
• | lease operating expenses, general and administrative costs and finding and development costs; |
• | future operating results; and |
• | plans, objectives, expectations and intentions. |
• | Grow production and reserves by developing our oil-rich resource base. We intend to drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital. |
• | Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We have targeted various intervals in the Midland Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. Our initial horizontal focus had been on the Wolfcamp B interval, but our recent focus has included the Lower Spraberry, Middle Spraberry and Wolfcamp A intervals. Our first two horizontal wells were completed in 2012 and had lateral lengths of less than 4,000 feet. As of December 31, 2017, we had drilled 412 horizontal wells as operator and had participated in 61 additional horizontal wells as a non-operator, including two in which we own only a minor wellbore interest. We also acquired interest in 76 horizontal wells on properties we purchased. Of these 549 total horizontal wells, 466 had been completed and were on production. Of the 466 horizontal wells on production, 152 are in the Wolfcamp B interval, 122 are in the Wolfcamp A interval, 163 are in the Lower Spraberry interval, nine are in the Middle Spraberry interval, three are in the Cline interval, three are in the Clearfork interval, seven are in the Bone Spring interval and seven are in various other intervals. These wells have lateral lengths ranging from approximately 2,100 feet to 13,000 feet. In 2018, we expect that our average lateral length will be about 9,300 feet, although the actual length will vary depending on the layout of our acreage and other factors. As technology continues to improve, we expect that our average lateral length will increase, resulting in higher per well recoveries and lower development costs per BOE. During the year ended December 31, 2017, we were able to drill our horizontal wells in the Midland Basin with approximately 7,500 foot lateral lengths to total depth, or TD, in an average of 12.2 days and we drilled approximately 10,000 foot lateral wells in 14.5 days. Further advances in drilling and completion technology may result in economic development of zones that are not currently viable. |
• | Leverage our experience operating in the Permian Basin. Our executive team, which has an average of over 25 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. Our focus on efficient drilling and completion techniques is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. We believe that the experience of our executive team in deviated and horizontal drilling and completions has helped reduce the execution risk normally associated with these complex well paths. In addition, our completion techniques are continually evolving as we evaluate and implement hydraulic fracturing practices that have and are expected to continue to increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices. |
• | Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. Our acreage position in the Wolfberry play is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately 84% of our acreage. This operational control allows us to manage more efficiently the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development. Our average 84% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies. |
• | Pursue strategic acquisitions with substantial resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential. Our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We regularly review acquisition opportunities and intend to pursue acquisitions that meet our strategic and financial targets. During the year ended December 31, 2017, we acquired approximately 99,830 gross (84,468 net) leasehold acres primarily in Pecos and Reeves counties in the Southern Delaware Basin. |
• | Maintain financial flexibility. We seek to maintain a conservative financial position. In connection with our fall 2017 borrowing base redetermination, the agent lender under our revolving credit agreement recommended a borrowing base of $1.8 billion. We elected a commitment amount of $1.0 billion, of which $603.0 million was available for borrowing as of December 31, 2017. As of December 31, 2017, Viper had $93.5 million in outstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility. |
• | Oil rich resource base in one of North America’s leading resource plays. All of our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the Permian Basin. Our production for the year ended December 31, 2017 was approximately 74% oil, 14% natural gas liquids and 12% natural gas. As of December 31, 2017, our estimated net proved reserves were comprised of approximately 70% oil, 14% natural gas liquids and 16% natural gas. |
• | Multi-year drilling inventory in one of North America’s leading oil resource plays. We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 3,800 gross (2,750 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data. These gross identified economic potential horizontal locations have an average lateral length of approximately 8,400 feet, with the actual length depending on lease geometry and other considerations. These locations exist across most of our acreage blocks and in multiple horizons. Of these 3,800 locations, 2,100 are in the Midland Basin and 1,700 are in the Delaware Basin. In the Midland Basin, 860 are in the Lower Spraberry or Wolfcamp B horizons where we have drilled a large number of wells, 825 are in the Wolfcamp A or Middle Spraberry horizons where we have drilled a limited number of wells and 415 are in the Clearfork or Cline horizons where we have drilled very few wells. Our current location count for the Lower Spraberry horizon is based on 660 foot spacing in f Midland, southwest Martin, northeast Andrews, Howard and Glasscock counties, and 880 foot spacing in all other counties. For the Wolfcamp B horizon, the horizontal location count is based on 660 foot spacing between wells in Midland, Martin, northeast Andrews, Howard, and Glasscock counties, and 880 foot spacing in all other counties. In the Wolfcamp A horizon, the horizontal location count in based on 660 foot spacing in Midland, Howard and Glasscock counties, 880 foot spacing in southwest Martin county and 1,320 foot spacing in other counties. The horizontal location count for the Middle Spraberry is based on 880 foot spacing in Midland, Martin and northeast Andrews counties and 1,320 foot spacing in other counties. In the Cline and Clearfork horizons, the horizontal location count is based on 1,320 foot spacing except for the Clearfork in central Andrews County which is based on 660 foot spacing. In the Delaware Basin, 1,240 locations are in the Wolfcamp A or Wolfcamp B horizons, and 460 locations are in the 2nd Bone Spring or 3rd Bone Spring horizon. The horizontal location counts are based on 880 foot spacing in the Wolfcamp A and Wolfcamp B horizons, and 1,320 foot spacing in the Bone Spring horizons. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count. The two-stream gross estimated ultimate recoveries, or EURs, from our future PUD horizontal wells, as estimated by Ryder Scott as of December 31, 2017, range from 528 MBOE per well, consisting of 413 MBbls of oil and 687 MMcf of natural gas, to 1,665 MBOE per well, consisting of 1,307 MBbls of oil and 2,150 MMcf of natural gas, for wells ranging in lateral length from approximately 5,000 feet to approximately 12,500 feet, in intervals including the Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B. Ryder Scott has estimated gross EURs of 910 MBOE for our Lower Spraberry wells in Midland County and 1,071 MBOE for our Wolfcamp A wells in Pecos County, which constitute 36% of our remaining PUD horizontal wells, in each case based on 7,500 foot lateral lengths. In addition, we have approximately 1,837 square miles of proprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including additional horizontal drilling opportunities and strategic leasehold acquisitions. |
• | Experienced, incentivized and proven management team. Our executive team has an average of over 25 years of industry experience per person, most of which is focused on resource play development. 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 both drilling and completing horizontal wells in addition to horizontal well reservoir and geologic expertise, which is of strategic importance as we expand our horizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources. |
• | Favorable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the longest operating hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. We believe that the geological and regulatory environment of the Permian Basin is more stable and predictable, and that we are faced with less operational risks in the Permian Basin as compared to emerging hydrocarbon basins. |
• | High degree of operational control. We are the operator of approximately 84% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of our acreage, we retain the ability to increase or decrease our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects. |
• | review and verification of historical production data, which data is based on actual production as reported by us; |
• | preparation of reserve estimates by our Executive Vice President–Reservoir Engineering or under his direct supervision; |
• | review by our Executive Vice President–Reservoir Engineering 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; |
• | direct reporting responsibilities by our Executive Vice President–Reservoir Engineering to our Chief Executive Officer; |
• | verification of property ownership by our land department; and |
• | no employee’s compensation is tied to the amount of reserves booked. |
December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Estimated proved developed reserves: | ||||||||
Oil (MBbls) | 141,246 | 79,457 | 60,569 | |||||
Natural gas (MMcf) | 190,740 | 105,399 | 96,871 | |||||
Natural gas liquids (MBbls) | 35,412 | 22,080 | 15,418 | |||||
Total (MBOE) | 208,447 | 119,104 | 92,132 | |||||
Estimated proved undeveloped reserves: | ||||||||
Oil (MBbls) | 91,935 | 59,717 | 45,409 | |||||
Natural gas (MMcf) | 94,629 | 69,497 | 52,632 | |||||
Natural gas liquids (MBbls) | 19,198 | 15,054 | 10,586 | |||||
Total (MBOE) | 126,905 | 86,354 | 64,767 | |||||
Estimated Net Proved Reserves: | ||||||||
Oil (MBbls) | 233,181 | 139,174 | 105,979 | |||||
Natural gas (MMcf) | 285,369 | 174,896 | 149,503 | |||||
Natural gas liquids (MBbls) | 54,610 | 37,134 | 26,004 | |||||
Total (MBOE)(1) | 335,352 | 205,458 | 156,899 | |||||
Percent proved developed | 62.2 | % | 58.0 | % | 58.7 | % |
(1) | Estimates of reserves as of December 31, 2017, 2016 and 2015 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2017, 2016 and 2015, respectively, in accordance with SEC guidelines applicable to reserves 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. |
(MBOE) | ||
Beginning proved undeveloped reserves at December 31, 2016 | 86,354 | |
Undeveloped reserves transferred to developed | (31,666 | ) |
Revisions | (4,710 | ) |
Net purchases | 6,246 | |
Extensions and discoveries | 70,680 | |
Ending proved undeveloped reserves at December 31, 2017 | 126,904 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
Production Data: | |||||||||||
Oil (MBbls) | 21,418 | 11,562 | 9,081 | ||||||||
Natural gas (MMcf) | 20,660 | 10,728 | 7,931 | ||||||||
Natural gas liquids (MBbls) | 4,056 | 2,399 | 1,678 | ||||||||
Combined volumes (MBOE) | 28,917 | 15,749 | 12,081 | ||||||||
Daily combined volumes (BOE/d) | 79,224 | 43,031 | 33,098 | ||||||||
Average Prices: | |||||||||||
Oil (per Bbl) | $ | 48.75 | $ | 40.70 | $ | 44.68 | |||||
Natural gas (per Mcf) | 2.53 | 2.10 | 2.47 | ||||||||
Natural gas liquids (per Bbl) | 22.20 | 14.20 | 12.77 | ||||||||
Combined (per BOE) | 41.02 | 33.47 | 36.98 | ||||||||
Oil, hedged ($ per Bbl)(1) | 48.94 | 40.80 | 60.63 | ||||||||
Natural gas, hedged ($ per MMbtu)(1) | 2.65 | 2.06 | 2.47 | ||||||||
Average price, hedged ($ per BOE)(1) | 41.26 | 33.54 | 48.97 | ||||||||
Average Costs per BOE: | |||||||||||
Lease operating expense | $ | 4.38 | $ | 5.23 | $ | 6.84 | |||||
Production and ad valorem taxes | 2.54 | 2.19 | 2.73 | ||||||||
Gathering and transportation expense | 0.44 | 0.74 | 0.50 | ||||||||
General and administrative - cash component | 0.80 | 1.03 | 1.11 | ||||||||
Total operating expense - cash | 8.16 | 9.19 | 11.18 | ||||||||
General and administrative - non-cash component | 0.88 | 1.68 | 1.54 | ||||||||
Depreciation, depletion and amortization | 11.30 | 11.30 | 18.02 | ||||||||
Interest expense | 1.40 | 2.58 | 3.44 | ||||||||
Total expenses | $ | 13.58 | $ | 15.56 | $ | 23.00 |
(1) | Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. |
Developed Acreage(1) | Undeveloped Acreage(2) | Total Acreage(3) | |||||||||||||||
Basin | Gross(4) | Net(5) | Gross(4) | Net(5) | Gross(4) | Net(5) | |||||||||||
Delaware | 58,444 | 49,919 | 69,982 | 54,800 | 128,426 | 104,719 | |||||||||||
Midland | 84,325 | 69,641 | 33,261 | 32,300 | 117,586 | 101,941 | |||||||||||
Total | 142,769 | 119,560 | 103,243 | 87,100 | 246,012 | 206,660 |
(1) | Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells. |
(2) | Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. |
(3) | Does not include Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests. |
(4) | A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. |
(5) | A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. |
2018 | 2019 | 2020 | 2021 | 2022 | |||||||||||||||||||||||||
Basin | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Delaware | 28,572 | 22,198 | 31,091 | 19,415 | 13,097 | 1,286 | 3,639 | 719 | — | — | |||||||||||||||||||
Midland | 897 | 715 | 908 | 255 | 19,678 | 18,933 | — | — | — | — | |||||||||||||||||||
Total | 29,469 | 22,913 | 31,999 | 19,670 | 32,775 | 20,219 | 3,639 | 719 | — | — |
Year Ended December 31, | |||||||||||||||||
2017 | 2016 | 2015 | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Development: | |||||||||||||||||
Productive | 27 | 23 | 6 | 3 | 8 | 6 | |||||||||||
Dry | — | — | — | — | — | — | |||||||||||
Exploratory: | |||||||||||||||||
Productive | 112 | 84 | 82 | 62 | 71 | 57 | |||||||||||
Dry | — | — | — | — | — | — | |||||||||||
Total: | |||||||||||||||||
Productive | 139 | 107 | 88 | 65 | 79 | 63 | |||||||||||
Dry | — | — | — | — | — | — |
Midland Basin | Delaware Basin | Total | ||||||
% of produced oil sold by pipeline | 93 | % | 22 | % | 80 | % | ||
% of produced water connected to pipeline | 93 | % | 87 | % | 91 | % |
Midland Basin | Delaware Basin | ||||||
Oil transportation costs per Bbl: | |||||||
Trucked | $ | 1.84 | $ | 2.28 | |||
Pipeline | $ | 1.09 | $ | 1.31 | |||
Average savings | $ | 0.75 | $ | 0.97 | |||
Water transportation costs per Bbl: | |||||||
Trucked | $ | 2.08 | $ | 1.86 | |||
Pipeline | $ | 0.23 | $ | 0.39 | |||
Average savings | $ | 1.85 | $ | 1.47 |
• | the location of wells; |
• | the method of drilling and casing wells; |
• | the timing of construction or drilling activities, including seasonal wildlife closures; |
• | the rates of production or “allowables”; |
• | the surface use and restoration of properties upon which wells are drilled; |
• | the plugging and abandoning of wells; and |
• | notice to, and consultation with, surface owners and other third parties. |
• | the domestic and foreign supply of oil and natural gas; |
• | the level of prices and expectations about future prices of oil and natural gas; |
• | the level of global oil and natural gas exploration and production; |
• | the cost of exploring for, developing, producing and delivering oil and natural gas; |
• | the price and quantity of foreign imports; |
• | political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia; |
• | the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; |
• | speculative trading in crude oil and natural gas derivative contracts; |
• | the level of consumer product demand; |
• | weather conditions and other natural disasters; |
• | risks associated with operating drilling rigs; |
• | technological advances affecting energy consumption; |
• | the price and availability of alternative fuels; |
• | domestic and foreign governmental regulations and taxes; |
• | the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; |
• | the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and |
• | overall domestic and global economic conditions. |
• | our proved reserves; |
• | the volume of oil and natural gas we are able to produce from existing wells; |
• | the prices at which our oil and natural gas are sold; |
• | our ability to acquire, locate and produce economically new reserves; and |
• | our ability to borrow under our credit facility. |
• | recoverable reserves; |
• | future oil and natural gas prices and their applicable differentials; |
• | operating costs; and |
• | potential environmental and other liabilities. |
• | crude oil swap contracts priced at a weighted average price of $51.10 WTI for 9,761,000 aggregate Bbls; |
• | crude oil swap contracts priced at a weighted average price of $54.89 Brent for 1,830,000 aggregate Bbls; |
• | crude oil basis swap contracts priced at a weighted average price of $0.88 for 5,475,000 aggregate Bbls for the spread between the WTI Midland price and the WTI Cushing price; |
• | natural gas swap contracts priced at a weighted average price of $3.14 for 7,750,000 aggregate MMBtu; and |
• | crude oil costless collars contracts with a floor price of $47.00 for 540,000 aggregate Bbls and a ceiling price of $56.34 for 270,000 aggregate Bbls. |
• | unusual or unexpected geological formations; |
• | loss of drilling fluid circulation; |
• | title problems; |
• | facility or equipment malfunctions; |
• | unexpected operational events; |
• | shortages or delivery delays of equipment and services; |
• | compliance with environmental and other governmental requirements; and |
• | adverse weather conditions. |
• | our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to the senior notes, including any repurchase obligations that may arise thereunder; |
• | 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; |
• | a high level of debt could increase our vulnerability to general adverse economic and industry conditions; |
• | the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; |
• | 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; |
• | 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; |
• | a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; |
• | a high level of debt could limit our ability to access the capital markets to raise capital on favorable terms; |
• | 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 |
• | we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates. |
• | incur or guarantee additional indebtedness; |
• | make certain investments; |
• | create additional liens; |
• | sell or transfer assets; |
• | issue preferred stock; |
• | merge or consolidate with another entity; |
• | pay dividends or make other distributions; |
• | designate certain of our subsidiaries as unrestricted subsidiaries; |
• | create unrestricted subsidiaries; |
• | engage in transactions with affiliates; and |
• | enter into certain swap agreements. |
• | permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested; |
• | permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and |
• | provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests. |
• | our quarterly or annual operating results; |
• | changes in our earnings estimates; |
• | investment recommendations by securities analysts following our business or our industry; |
• | additions or departures of key personnel; |
• | changes in the business, earnings estimates or market perceptions of our competitors; |
• | our failure to achieve operating results consistent with securities analysts’ projections; |
• | changes in industry, general market or economic conditions; and |
• | announcements of legislative or regulatory changes. |
• | provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders; |
• | limitations on the ability of our stockholders to call a special meeting and act by written consent; |
• | the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws; |
• | the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors; |
• | the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and |
• | the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders. |
High | Low | ||||||
2017 | |||||||
1st Quarter | $ | 114.00 | $ | 96.05 | |||
2nd Quarter | $ | 108.17 | $ | 83.22 | |||
3rd Quarter | $ | 98.36 | $ | 82.77 | |||
4th Quarter | $ | 127.45 | $ | 95.69 | |||
2016 | |||||||
1st Quarter | $ | 79.87 | $ | 55.48 | |||
2nd Quarter | $ | 96.01 | $ | 73.12 | |||
3rd Quarter | $ | 99.69 | $ | 83.90 | |||
4th Quarter | $ | 113.23 | $ | 88.74 |
Year Ended December 31, | |||||||||||||||||||
(In thousands, except per share amounts) | 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||
Statements of Operations Data: | |||||||||||||||||||
Total revenues | $ | 1,205,111 | $ | 527,107 | $ | 446,733 | $ | 495,718 | $ | 208,002 | |||||||||
Total costs and expenses | 600,091 | 595,724 | 1,187,002 | 283,048 | 112,808 | ||||||||||||||
Income (loss) from operations | 605,020 | (68,617 | ) | (740,269 | ) | 212,670 | 95,194 | ||||||||||||
Other income (expense) | (107,831 | ) | (96,099 | ) | (8,831 | ) | 92,286 | (8,853 | ) | ||||||||||
Income (loss) before income taxes | 497,189 | (164,716 | ) | (749,100 | ) | 304,956 | 86,341 | ||||||||||||
Provision for (benefit from) income taxes | (19,568 | ) | 192 | (201,310 | ) | 108,985 | 31,754 | ||||||||||||
Net income (loss) | 516,757 | (164,908 | ) | (547,790 | ) | 195,971 | 54,587 | ||||||||||||
Less: Net income attributable to non-controlling interest | 34,496 | 126 | 2,838 | 2,216 | — | ||||||||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | $ | 482,261 | $ | (165,034 | ) | $ | (550,628 | ) | $ | 193,755 | $ | 54,587 | |||||||
Earnings per common share | |||||||||||||||||||
Basic | $ | 4.95 | $ | (2.20 | ) | $ | (8.74 | ) | $ | 3.67 | $ | 1.30 | |||||||
Diluted | $ | 4.94 | $ | (2.20 | ) | $ | (8.74 | ) | $ | 3.64 | $ | 1.29 | |||||||
Weighted average common shares outstanding | |||||||||||||||||||
Basic | 97,458 | 75,077 | 63,019 | 52,826 | 42,015 | ||||||||||||||
Diluted | 97,688 | 75,077 | 63,019 | 53,297 | 42,255 |
As of December 31, | |||||||||||||||||||
(In thousands) | 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||
Balance Sheet Data: | |||||||||||||||||||
Cash and cash equivalents | $ | 112,446 | $ | 1,666,574 | $ | 20,115 | $ | 30,183 | $ | 15,555 | |||||||||
Net property and equipment | 7,343,617 | 3,390,857 | 2,597,625 | 2,791,807 | 1,446,337 | ||||||||||||||
Total assets | 7,770,985 | 5,349,680 | 2,750,719 | 3,095,481 | 1,521,614 | ||||||||||||||
Current liabilities | 577,428 | 209,342 | 141,421 | 266,729 | 121,320 | ||||||||||||||
Long-term debt | 1,477,347 | 1,105,912 | 487,807 | 673,500 | 460,000 | ||||||||||||||
Total stockholders’/ members’ equity(1) | 5,254,860 | 3,697,462 | 1,875,972 | 1,751,011 | 845,541 | ||||||||||||||
Total equity | 5,581,737 | 4,018,292 | 2,108,973 | 1,985,213 | — |
Year Ended December 31, | |||||||||||||||||||
(In thousands) | 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||
Other Financial Data: | |||||||||||||||||||
Net cash provided by operating activities | $ | 888,625 | $ | 332,080 | $ | 416,501 | $ | 356,389 | $ | 155,777 | |||||||||
Net cash used in investing activities | (3,132,282 | ) | (1,310,242 | ) | (895,050 | ) | (1,481,997 | ) | (940,140 | ) | |||||||||
Net cash provided by financing activities | 689,529 | 2,624,621 | 468,481 | 1,140,236 | 773,560 |
Year Ended December 31, | |||||||||||||||||||
(In thousands) | 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||
Consolidated Adjusted EBITDA(2) | $ | 928,039 | $ | 387,535 | $ | 449,245 | $ | 398,334 | $ | 157,604 |
(1) | For the years ended December 31, 2017, 2016, 2015 and 2014, total stockholders’ equity excludes $326.9 million, $320.8 million, $233.0 million and $234.2 million, respectively, of non-controlling interest related to Viper Energy Partners LP. There was no equity related to non-controlling interest for the year ended December 31, 2013. |
(2) | Consolidated Adjusted EBITDA is a supplemental non-GAAP financial measure. For our definition of Consolidated Adjusted EBITDA and a reconciliation of Consolidated Adjusted EBITDA to net income (loss) see “–Non-GAAP financial measure and reconciliation” below. |
Year Ended December 31, | |||||||||||||||||||
(In thousands) | 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||
Net income (loss) | $ | 516,757 | $ | (164,908 | ) | $ | (547,790 | ) | $ | 195,971 | $ | 54,587 | |||||||
Non-cash (gain) loss on derivative instruments, net | 84,240 | 26,522 | 112,918 | (117,109 | ) | (5,346 | ) | ||||||||||||
Interest expense, net | 40,554 | 40,684 | 41,510 | 34,515 | 8,059 | ||||||||||||||
Depreciation, depletion and amortization | 326,759 | 178,015 | 217,697 | 170,005 | 66,597 | ||||||||||||||
Impairment of oil and natural gas properties | — | 245,536 | 814,798 | — | — | ||||||||||||||
Non-cash equity-based compensation expense | 34,178 | 33,532 | 24,572 | 14,253 | 2,724 | ||||||||||||||
Capitalized equity-based compensation expense | (8,641 | ) | (7,079 | ) | (6,043 | ) | (4,437 | ) | (972 | ) | |||||||||
Asset retirement obligation accretion expense | 1,391 | 1,064 | 833 | 467 | 201 | ||||||||||||||
Loss on extinguishment of debt | — | 33,134 | — | — | — | ||||||||||||||
Income tax (benefit) provision | (19,568 | ) | 192 | (201,310 | ) | 108,985 | 31,754 | ||||||||||||
Non-controlling interest in net (income) loss | (47,631 | ) | 843 | (7,940 | ) | (4,316 | ) | — | |||||||||||
Consolidated Adjusted EBITDA | $ | 928,039 | $ | 387,535 | $ | 449,245 | $ | 398,334 | $ | 157,604 |
Year Ended December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Oil (MBbls) | 74 | % | 73 | % | 75 | % | ||
Natural gas (MMcf) | 12 | % | 11 | % | 11 | % | ||
Natural gas liquids (MBbls) | 14 | % | 16 | % | 14 | % | ||
100 | % | 100 | % | 100 | % |
Year Ended December 31, | |||||
2017 | 2016 | 2015 | |||
Oil (Bbls)/d | 58,678 | 31,590 | 24,880 | ||
Natural Gas (Mcf)/d | 56,602 | 29,313 | 21,729 | ||
Natural Gas Liquids (Bbls)/d | 11,112 | 6,556 | 4,596 | ||
Total average production per day | 79,224 | 43,031 | 33,098 |
2017 | 2016 | 2015 | ||||||
Estimated Net Proved Reserves: | ||||||||
Oil (MBbls) | 233,181 | 139,174 | 105,979 | |||||
Natural gas (MMcf) | 285,369 | 174,896 | 149,503 | |||||
Natural gas liquids (MBbls) | 54,610 | 37,134 | 26,004 | |||||
Total (MBOE) | 335,352 | 205,458 | 156,899 |
Unweighted Arithmetic Average | |||||||||||
First-Day-of-the-Month Prices | |||||||||||
2017 | 2016 | 2015 | |||||||||
Oil (per Bbl) | $ | 48.03 | $ | 39.94 | $ | 45.07 | |||||
Natural gas (per Mcf) | $ | 2.06 | $ | 1.36 | $ | 1.83 | |||||
Natural gas liquids (per Bbl) | $ | 20.79 | $ | 12.91 | $ | 12.56 |
Year Ended December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Revenues | ||||||||
Oil sales | 88 | % | 89 | % | 91 | % | ||
Natural gas sales | 4 | % | 4 | % | 4 | % | ||
Natural gas liquid sales | 8 | % | 7 | % | 5 | % | ||
100 | % | 100 | % | 100 | % |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in thousands) | |||||||||||
Revenues | |||||||||||
Oil, natural gas liquids and natural gas | $ | 1,186,275 | $ | 527,107 | $ | 446,733 | |||||
Lease bonus | 11,764 | — | — | ||||||||
Midstream services | 7,072 | — | — | ||||||||
Total revenues | 1,205,111 | 527,107 | 446,733 | ||||||||
Operating expenses | |||||||||||
Lease operating expenses | 126,524 | 82,428 | 82,625 | ||||||||
Production and ad valorem taxes | 73,505 | 34,456 | 32,990 | ||||||||
Gathering and transportation | 12,834 | 11,606 | 6,091 | ||||||||
Midstream services | 10,409 | — | — | ||||||||
Depreciation, depletion and amortization | 326,759 | 178,015 | 217,697 | ||||||||
Impairment of oil and natural gas properties | — | 245,536 | 814,798 | ||||||||
General and administrative expenses | 48,669 | 42,619 | 31,968 | ||||||||
Asset retirement obligation accretion | 1,391 | 1,064 | 833 | ||||||||
Total expenses | 600,091 | 595,724 | 1,187,002 | ||||||||
Income (loss) from operations | 605,020 | (68,617 | ) | (740,269 | ) | ||||||
Interest expense, net | (40,554 | ) | (40,684 | ) | (41,510 | ) | |||||
Other income, net | 10,235 | 3,064 | 728 | ||||||||
Gain (loss) on derivative instruments, net | (77,512 | ) | (25,345 | ) | 31,951 | ||||||
Loss on extinguishment of debt | — | (33,134 | ) | — | |||||||
Total other expense, net | (107,831 | ) | (96,099 | ) | (8,831 | ) | |||||
Income (loss) before income taxes | 497,189 | (164,716 | ) | (749,100 | ) | ||||||
Provision for (benefit from) income taxes | (19,568 | ) | 192 | (201,310 | ) | ||||||
Net income (loss) | 516,757 | (164,908 | ) | (547,790 | ) | ||||||
Net income attributable to non-controlling interest | 34,496 | 126 | 2,838 | ||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | $ | 482,261 | $ | (165,034 | ) | $ | (550,628 | ) |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
Production Data: | |||||||||||
Oil (MBbls) | 21,418 | 11,562 | 9,081 | ||||||||
Natural gas (MMcf) | 20,660 | 10,728 | 7,931 | ||||||||
Natural gas liquids (MBbls) | 4,056 | 2,399 | 1,678 | ||||||||
Combined volumes (MBOE) | 28,917 | 15,749 | 12,081 | ||||||||
Daily combined volumes (BOE/d) | 79,224 | 43,031 | 33,098 | ||||||||
Average Prices: | |||||||||||
Oil (per Bbl) | $ | 48.75 | $ | 40.70 | $ | 44.68 | |||||
Natural gas (per Mcf) | 2.53 | 2.10 | 2.47 | ||||||||
Natural gas liquids (per Bbl) | 22.20 | 14.20 | 12.77 | ||||||||
Combined (per BOE) | 41.02 | 33.47 | 36.98 | ||||||||
Oil, hedged ($ per Bbl)(1) | 48.94 | 40.80 | 60.63 | ||||||||
Natural gas, hedged ($ per MMbtu)(1) | 2.65 | 2.06 | 2.47 | ||||||||
Average price, hedged ($ per BOE)(1) | 41.26 | 33.54 | 48.97 | ||||||||
Average Costs per BOE: | |||||||||||
Lease operating expense | $ | 4.38 | $ | 5.23 | $ | 6.84 | |||||
Production and ad valorem taxes | 2.54 | 2.19 | 2.73 | ||||||||
Gathering and transportation expense | 0.44 | 0.74 | 0.50 | ||||||||
General and administrative - cash component | 0.80 | 1.03 | 1.11 | ||||||||
Total operating expense - cash | $ | 8.16 | $ | 9.19 | $ | 11.18 | |||||
General and administrative - non-cash component | $ | 0.88 | $ | 1.68 | $ | 1.54 | |||||
Depreciation, depletion and amortization | 11.30 | 11.30 | 18.02 | ||||||||
Interest expense | 1.40 | 2.58 | 3.44 | ||||||||
Total expenses | $ | 13.58 | $ | 15.56 | $ | 23.00 | |||||
Average realized oil price ($/Bbl) | $ | 48.75 | $ | 40.70 | $ | 44.68 | |||||
Average NYMEX ($/Bbl) | $ | 50.80 | $ | 43.29 | $ | 48.66 | |||||
Differential to NYMEX | $ | (2.05 | ) | $ | (2.59 | ) | $ | (3.98 | ) | ||
Average realized oil price to NYMEX | 96 | % | 94 | % | 92 | % | |||||
Average realized natural gas price ($/Mcf) | $ | 2.53 | $ | 2.10 | $ | 2.47 | |||||
Average NYMEX ($/Mcf) | $ | 2.99 | $ | 2.52 | $ | 2.62 | |||||
Differential to NYMEX | $ | (0.46 | ) | $ | (0.42 | ) | $ | (0.15 | ) | ||
Average realized natural gas price to NYMEX | 85 | % | 83 | % | 94 | % | |||||
Average realized natural gas liquids price ($/Bbl) | $ | 22.20 | $ | 14.20 | $ | 12.77 | |||||
Average NYMEX oil price ($/Bbl) | $ | 50.80 | $ | 43.29 | $ | 48.66 | |||||
Average realized natural gas liquids price to NYMEX oil price | 44 | % | 33 | % | 26 | % |
(1) | Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. |
Change in prices | Production volumes(1) | Total net dollar effect of change | |||||||||
(in thousands) | |||||||||||
Effect of changes in price: | |||||||||||
Oil | $ | 8.05 | 21,418 | $ | 172,403 | ||||||
Natural gas liquids | $ | 8.00 | 4,056 | $ | 32,446 | ||||||
Natural gas | $ | 0.43 | 20,660 | $ | 8,884 | ||||||
Total revenues due to change in price | $ | 213,733 | |||||||||
Change in production volumes(1) | Prior period average prices | Total net dollar effect of change | |||||||||
(in thousands) | |||||||||||
Effect of changes in production volumes: | |||||||||||
Oil | 9,856 | $ | 40.70 | $ | 401,080 | ||||||
Natural gas liquids | 1,656 | $ | 14.20 | $ | 23,521 | ||||||
Natural gas | 9,931 | $ | 2.10 | $ | 20,834 | ||||||
Total revenues due to change in production volumes | $ | 445,435 | |||||||||
Total change in revenues | $ | 659,168 |
(1) | Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas. |
Year Ended December 31, | |||||||
2017 | 2016 | ||||||
(in thousands, except BOE amounts) | |||||||
Depletion of proved oil and natural gas properties | $ | 321,870 | $ | 176,369 | |||
Depreciation of midstream assets | 3,451 | 252 | |||||
Depreciation of other property and equipment | 1,438 | 1,394 | |||||
Depreciation, depletion and amortization expense | $ | 326,759 | $ | 178,015 | |||
Oil and natural gas properties depreciation, depletion and amortization expense per BOE | $ | 11.11 | $ | 11.23 | |||
Total depreciation, depletion and amortization expense per BOE | $ | 11.30 | $ | 11.30 |
Change in prices | Production volumes(1) | Total net dollar effect of change | |||||||||
(in thousands) | |||||||||||
Effect of changes in price: | |||||||||||
Oil | $ | (3.98 | ) | 11,562 | $ | (46,031 | ) | ||||
Natural gas liquids | $ | 1.43 | 2,399 | $ | 3,431 | ||||||
Natural gas | $ | (0.37 | ) | 10,728 | $ | (3,970 | ) | ||||
Total revenues due to change in price | $ | (46,570 | ) | ||||||||
Change in production volumes(1) | Prior period average prices | Total net dollar effect of change | |||||||||
(in thousands) | |||||||||||
Effect of changes in production volumes: | |||||||||||
Oil | 2,481 | $ | 44.68 | $ | 110,815 | ||||||
Natural gas liquids | 722 | $ | 12.77 | $ | 9,219 | ||||||
Natural gas | 2,797 | $ | 2.47 | $ | 6,910 | ||||||
Total revenues due to change in production volumes | $ | 126,944 | |||||||||
Total change in revenues | $ | 80,374 |
(1) | Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas. |
Year Ended December 31, | |||||||
2016 | 2015 | ||||||
(in thousands, except BOE amounts) | |||||||
Depletion of proved oil and natural gas properties | $ | 176,369 | $ | 216,056 | |||
Depreciation of midstream assets | 252 | 239 | |||||
Depreciation of other property and equipment | 1,394 | 1,402 | |||||
Depreciation, depletion and amortization expense | $ | 178,015 | $ | 217,697 | |||
Oil and natural gas properties depreciation, depletion and amortization expense per BOE | $ | 11.23 | $ | 17.84 | |||
Total depreciation, depletion and amortization expense per BOE | $ | 11.30 | $ | 18.02 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in thousands) | |||||||||||
Net cash provided by operating activities | $ | 888,625 | $ | 332,080 | $ | 416,501 | |||||
Net cash used in investing activities | (3,132,282 | ) | (1,310,242 | ) | (895,050 | ) | |||||
Net cash provided by financing activities | $ | 689,529 | $ | 2,624,621 | $ | 468,481 | |||||
Net change in cash | $ | (1,554,128 | ) | $ | 1,646,459 | $ | (10,068 | ) |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in thousands) | |||||||||||
Drilling, completion and infrastructure | $ | (860,738 | ) | $ | (363,087 | ) | $ | (419,512 | ) | ||
Additions to midstream assets | (68,139 | ) | (1,188 | ) | — | ||||||
Acquisition of leasehold interests | (1,960,591 | ) | (611,280 | ) | (437,455 | ) | |||||
Acquisition of mineral interests | (407,450 | ) | (205,721 | ) | (43,907 | ) | |||||
Acquisition of midstream assets | (50,279 | ) | — | — | |||||||
Purchase of other property and equipment | (22,779 | ) | (9,891 | ) | (1,213 | ) | |||||
Proceeds from sale of property and equipment | 65,656 | 4,661 | 9,739 | ||||||||
Funds held in escrow | 104,087 | (121,391 | ) | — | |||||||
Equity investments | (188 | ) | (2,345 | ) | (2,702 | ) | |||||
Net cash used in investing activities | $ | (3,200,421 | ) | $ | (1,310,242 | ) | $ | (895,050 | ) |
Financial Covenant | Required Ratio |
Ratio of total debt to EBITDAX | Not greater than 3.0 to 1.0 |
Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
Financial Covenant | Required Ratio |
Ratio of total debt to EBITDAX | Not greater than 4.0 to 1.0 |
Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
• | $1.175 billion to $1.325 billion will be spent on drilling and completing 170 to 190 gross (146 to 163 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins; and |
• | $125.0 million to $175.0 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions. |
Payments Due by Period | |||||||||||||||||||
2018 | 2019-2020 | 2021-2022 | Thereafter | Total | |||||||||||||||
(in thousands) | |||||||||||||||||||
Secured revolving credit facility(1) | $ | — | $ | — | $ | 397,000 | $ | — | $ | 397,000 | |||||||||
Interest expense related to the secured revolving credit facility | 2,261 | 10,522 | 7,144 | — | $ | 19,927 | |||||||||||||
Senior notes | — | — | — | 1,000,000 | $ | 1,000,000 | |||||||||||||
Interest expense related to the senior notes(2) | 50,625 | 101,250 | 101,250 | 108,475 | $ | 361,600 | |||||||||||||
Viper's secured revolving credit facility(1) | — | — | 93,500 | — | $ | 93,500 | |||||||||||||
Interest and commitment fees under Viper's credit agreement(3) | 1,149 | 2,299 | 2,107 | — | $ | 5,555 | |||||||||||||
Asset retirement obligations (4) | 1,163 | — | — | 20,122 | $ | 21,285 | |||||||||||||
Drilling commitments(5) | 21,882 | 10,082 | — | — | $ | 31,964 | |||||||||||||
Sand supply agreements | — | 18,000 | 18,000 | 9,000 | $ | 45,000 | |||||||||||||
Operating lease obligations(6) | 3,581 | 6,234 | 4,648 | 7,973 | $ | 22,436 | |||||||||||||
Fasken Center office building7) | 99,000 | — | — | — | $ | 99,000 | |||||||||||||
$ | 179,661 | $ | 148,387 | $ | 623,649 | $ | 1,145,570 | $ | 2,097,267 |
(1) | Includes the outstanding principal amount under the revolving credit facilities, 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) | Interest represents the scheduled cash payments on the senior notes. |
(3) | Includes only the minimum amount of interest and commitment fees due which, as of December 31, 2017, includes a commitment fee equal to 0.375% per year of the unused portion of the borrowing base of Viper’s credit agreement. |
(4) | Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to |
(5) | Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2017. |
(6) | Operating lease obligations represent future commitments for building and vehicle leases. |
(7) | Fasken Center office buildings represents the amount we paid on January 31, 2018 at the closing of this transaction. The Fasken building contains our corporate offices. |
(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 Company’s consolidated financial statements and related notes. |
3. Exhibits | ||
Exhibit Number | Description | |
2.1# | ||
2.2# | ||
2.3# | ||
2.4# | ||
3.1 | ||
3.2 | ||
3.3 | ||
4.1 | ||
4.2 | ||
4.3 | ||
4.4 | ||
4.5 | ||
4.6 | ||
4.7 | ||
10.1 | ||
10.2+ |
3. Exhibits | ||
10.3+ | ||
10.4+ | ||
10.5 | ||
10.6 | ||
10.7+ | ||
10.8+ | ||
10.9+ | ||
10.10+ | ||
10.11+ | ||
10.12+ | ||
10.13+ | ||
10.14+ | ||
10.15 | ||
10.16 | ||
10.17 | ||
10.18 | ||
10.19 |
3. Exhibits | ||
10.20 | ||
10.21 | ||
10.22 | ||
10.23 | ||
10.24 | ||
10.25 | ||
10.26 | ||
10.27 | ||
10.28 | ||
10.29 | ||
10.30+ | ||
10.31 | ||
10.32 | ||
10.33 | ||
10.34 | ||
10.35 | ||
10.36 |
3. Exhibits | ||
10.37 | ||
10.38 | ||
10.39 | ||
10.40 | ||
10.41 | ||
10.42 | ||
10.43 | ||
10.44 | ||
10.45 | ||
10.46 | ||
10.47 | ||
10.48 | ||
10.49 |
3. Exhibits | ||
10.50 | ||
10.51 | ||
10.52 | ||
10.53 | ||
10.54 | ||
10.55 | ||
21.1* | ||
23.1* | ||
23.2* | ||
23.3* | ||
31.1* | ||
31.2* | ||
32.1** | ||
32.2** | ||
99.1* | ||
99.2* | ||
101.INS* | XBRL Instance Document. | |
101.SCH* | XBRL Taxonomy Extension Schema Document. | |
101.CAL* | XBRL Taxonomy Extension Calculation Linkbase. | |
101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document. | |
101.LAB* | XBRL Taxonomy Extension Labels Linkbase Document. | |
101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document. |
* | Filed herewith. |
** | The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. |
+ | Management contract, compensatory plan or arrangement. |
# | The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request. |
DIAMONDBACK ENERGY, INC. | |||
Date: | February 14, 2018 | ||
/s/ Travis D. Stice | |||
Travis D. Stice | |||
Chief Executive Officer | |||
(Principal Executive Officer) |
Signature | Title | Date | ||
/s/ Steven E. West | Chairman of the Board and Director | February 14, 2018 | ||
Steven E. West | ||||
/s/ Travis D. Stice | Chief Executive Officer and Director | February 14, 2018 | ||
Travis D. Stice | (Principal Executive Officer) | |||
/s/ Michael P. Cross | Director | February 14, 2018 | ||
Michael P. Cross | ||||
/s/ David L. Houston | Director | February 14, 2018 | ||
David L. Houston | ||||
/s/ Mark L. Plaumann | Director | February 14, 2018 | ||
Mark L. Plaumann | ||||
/s/ Teresa L. Dick | Chief Financial Officer, Senior Vice President, and Assistant Secretary | February 14, 2018 | ||
Teresa L. Dick | (Principal Financial and Accounting Officer) |
December 31, | |||||||
2017 | 2016 | ||||||
(In thousands, except share amounts) | |||||||
Assets | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 112,446 | $ | 1,666,574 | |||
Restricted cash | — | 500 | |||||
Accounts receivable: | |||||||
Joint interest and other | 73,038 | 49,476 | |||||
Oil and natural gas sales | 158,575 | 70,349 | |||||
Related party | — | 297 | |||||
Inventories | 9,108 | 1,983 | |||||
Derivative instruments | 531 | — | |||||
Prepaid expenses and other | 4,903 | 2,987 | |||||
Total current assets | 358,601 | 1,792,166 | |||||
Property and equipment: | |||||||
Oil and natural gas properties, full cost method of accounting ($4,105,865 and $1,730,519 excluded from amortization at December 31, 2017 and 2016, respectively) | 9,232,694 | 5,160,261 | |||||
Midstream assets | 191,519 | 8,362 | |||||
Other property, equipment and land | 80,776 | 58,290 | |||||
Accumulated depletion, depreciation, amortization and impairment | (2,161,372 | ) | (1,836,056 | ) | |||
Net property and equipment | 7,343,617 | 3,390,857 | |||||
Funds held in escrow | 6,304 | 121,391 | |||||
Derivative instruments | — | 709 | |||||
Other assets | 62,463 | 44,557 | |||||
Total assets | $ | 7,770,985 | $ | 5,349,680 | |||
Liabilities and Stockholders’ Equity | |||||||
Current liabilities: | |||||||
Accounts payable-trade | $ | 94,590 | $ | 47,648 | |||
Accounts payable-related party | — | 1 | |||||
Accrued capital expenditures | 221,256 | 60,350 | |||||
Other accrued liabilities | 92,512 | 55,330 | |||||
Revenues and royalties payable | 68,703 | 23,405 | |||||
Derivative instruments | 100,367 | 22,608 | |||||
Total current liabilities | 577,428 | 209,342 | |||||
Long-term debt | 1,477,347 | 1,105,912 | |||||
Derivative instruments | 6,303 | — | |||||
Asset retirement obligations | 20,122 | 16,134 | |||||
Deferred income taxes | 108,048 | — | |||||
Total liabilities | 2,189,248 | 1,331,388 | |||||
Commitments and contingencies (Note 15) | |||||||
Stockholders’ equity: | |||||||
Common stock, $0.01 par value, 200,000,000 shares authorized, 98,167,289 issued and outstanding at December 31, 2017; 90,143,934 issued and outstanding at December 31, 2016 | 982 | 901 | |||||
Additional paid-in capital | 5,291,011 | 4,215,955 | |||||
Accumulated deficit | (37,133 | ) | (519,394 | ) | |||
Total Diamondback Energy, Inc. stockholders’ equity | 5,254,860 | 3,697,462 | |||||
Non-controlling interest | 326,877 | 320,830 | |||||
Total equity | 5,581,737 | 4,018,292 | |||||
Total liabilities and equity | $ | 7,770,985 | $ | 5,349,680 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(In thousands, except per share amounts) | |||||||||||
Revenues: | |||||||||||
Oil sales | $ | 1,044,017 | $ | 470,528 | $ | 405,715 | |||||
Natural gas sales | 52,210 | 22,506 | 19,592 | ||||||||
Natural gas liquid sales | 90,048 | 34,073 | 21,426 | ||||||||
Lease bonus | 11,764 | — | — | ||||||||
Midstream services | 7,072 | — | — | ||||||||
Total revenues | 1,205,111 | 527,107 | 446,733 | ||||||||
Costs and expenses: | |||||||||||
Lease operating expenses | 126,524 | 82,428 | 82,625 | ||||||||
Production and ad valorem taxes | 73,505 | 34,456 | 32,990 | ||||||||
Gathering and transportation | 12,834 | 11,606 | 6,091 | ||||||||
Midstream services | 10,409 | — | — | ||||||||
Depreciation, depletion and amortization | 326,759 | 178,015 | 217,697 | ||||||||
Impairment of oil and natural gas properties | — | 245,536 | 814,798 | ||||||||
General and administrative expenses (including non-cash equity-based compensation, net of capitalized amounts, of $25,537, $26,453 and $18,529 for the year ended December 31, 2017, 2016 and 2015, respectively) | 48,669 | 42,619 | 31,968 | ||||||||
Asset retirement obligation accretion | 1,391 | 1,064 | 833 | ||||||||
Total costs and expenses | 600,091 | 595,724 | 1,187,002 | ||||||||
Income (loss) from operations | 605,020 | (68,617 | ) | (740,269 | ) | ||||||
Other income (expense): | |||||||||||
Interest expense, net | (40,554 | ) | (40,684 | ) | (41,510 | ) | |||||
Other income, net | 10,235 | 3,064 | 728 | ||||||||
Gain (loss) on derivative instruments, net | (77,512 | ) | (25,345 | ) | 31,951 | ||||||
Loss on extinguishment of debt | — | (33,134 | ) | — | |||||||
Total other expense, net | (107,831 | ) | (96,099 | ) | (8,831 | ) | |||||
Income (loss) before income taxes | 497,189 | (164,716 | ) | (749,100 | ) | ||||||
Provision for (benefit from) income taxes | (19,568 | ) | 192 | (201,310 | ) | ||||||
Net income (loss) | 516,757 | (164,908 | ) | (547,790 | ) | ||||||
Net income attributable to non-controlling interest | 34,496 | 126 | 2,838 | ||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | $ | 482,261 | $ | (165,034 | ) | $ | (550,628 | ) | |||
Earnings per common share: | |||||||||||
Basic | $ | 4.95 | $ | (2.20 | ) | $ | (8.74 | ) | |||
Diluted | $ | 4.94 | $ | (2.20 | ) | $ | (8.74 | ) | |||
Weighted average common shares outstanding: | |||||||||||
Basic | 97,458 | 75,077 | 63,019 | ||||||||
Diluted | 97,688 | 75,077 | 63,019 |
Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Non-Controlling Interest | ||||||||||||||||||
Shares | Amount | Total | |||||||||||||||||||
(In thousands) | |||||||||||||||||||||
Balance December 31, 2014 | 56,888 | $ | 569 | $ | 1,554,174 | $ | 196,268 | $ | 234,202 | $ | 1,985,213 | ||||||||||
Unit-based compensation | — | — | — | 3,929 | 3,929 | ||||||||||||||||
Distribution to non-controlling interest | — | — | — | (7,968 | ) | (7,968 | ) | ||||||||||||||
Stock-based compensation | — | 20,645 | — | — | 20,645 | ||||||||||||||||
Common shares issued in public offering, net of offering costs | 9,488 | 94 | 649,979 | — | — | 650,073 | |||||||||||||||
Exercise of stock options and vesting of restricted stock units | 421 | 5 | 4,866 | — | — | 4,871 | |||||||||||||||
Net income (loss) | — | — | (550,628 | ) | 2,838 | (547,790 | ) | ||||||||||||||
Balance December 31, 2015 | 66,797 | 668 | 2,229,664 | (354,360 | ) | 233,001 | 2,108,973 | ||||||||||||||
Net proceeds from issuance of common units - Viper Energy Partners LP | — | — | — | 93,462 | 93,462 | ||||||||||||||||
Unit-based compensation | — | — | — | 3,815 | 3,815 | ||||||||||||||||
Distribution to non-controlling interest | — | — | — | (9,574 | ) | (9,574 | ) | ||||||||||||||
Stock-based compensation | — | 29,717 | — | — | 29,717 | ||||||||||||||||
Common shares issued in public offering, net of offering costs | 23,000 | 229 | 1,956,079 | — | — | 1,956,308 | |||||||||||||||
Exercise of stock options and awards of restricted stock | 347 | 4 | 495 | — | — | 499 | |||||||||||||||
Net income (loss) | — | — | (165,034 | ) | 126 | (164,908 | ) | ||||||||||||||
Balance December 31, 2016 | 90,144 | 901 | 4,215,955 | (519,394 | ) | 320,830 | 4,018,292 | ||||||||||||||
Net proceeds from issuance of common units - Viper Energy Partners LP | — | — | — | 369,896 | 369,896 | ||||||||||||||||
Unit-based compensation | — | — | — | 2,395 | 2,395 | ||||||||||||||||
Common units issued for acquisition | — | — | — | 3,050 | 3,050 | ||||||||||||||||
Stock-based compensation | — | 31,783 | — | — | 31,783 | ||||||||||||||||
Distribution to non-controlling interest | — | — | — | (41,367 | ) | (41,367 | ) | ||||||||||||||
Common shares issued in public offering, net of offering costs | — | 14 | — | — | 14 | ||||||||||||||||
Common shares issued for acquisition | 7,686 | 77 | 809,096 | — | — | 809,173 | |||||||||||||||
Exercise of stock options and awards of restricted stock | 337 | 4 | 355 | — | — | 359 | |||||||||||||||
Change in ownership of consolidated subsidiaries, net | — | 233,808 | — | (362,423 | ) | (128,615 | ) | ||||||||||||||
Net income | — | — | 482,261 | 34,496 | 516,757 | ||||||||||||||||
Balance December 31, 2017 | 98,167 | $ | 982 | $ | 5,291,011 | $ | (37,133 | ) | $ | 326,877 | $ | 5,581,737 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(In thousands) | |||||||||||
Cash flows from operating activities: | |||||||||||
Net income (loss) | $ | 516,757 | $ | (164,908 | ) | $ | (547,790 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
Provision for deferred income taxes | (20,567 | ) | — | (201,545 | ) | ||||||
Impairment of oil and natural gas properties | — | 245,536 | 814,798 | ||||||||
Asset retirement obligation accretion | 1,391 | 1,064 | 833 | ||||||||
Depreciation, depletion and amortization | 326,759 | 178,015 | 217,697 | ||||||||
Amortization of debt issuance costs | 3,943 | 2,717 | 2,601 | ||||||||
Loss on early extinguishment of debt | — | 33,134 | — | ||||||||
Change in fair value of derivative instruments | 84,240 | 26,522 | 112,918 | ||||||||
Income from equity investment | (657 | ) | (676 | ) | — | ||||||
Equity-based compensation expense | 25,537 | 26,453 | 18,529 | ||||||||
Gain (loss) on sale of assets, net | (455 | ) | (61 | ) | 668 | ||||||
Changes in operating assets and liabilities: | |||||||||||
Accounts receivable | (97,611 | ) | (35,030 | ) | 8,998 | ||||||
Accounts receivable-related party | 297 | 1,294 | 2,149 | ||||||||
Restricted cash | 500 | — | — | ||||||||
Inventories | (2,245 | ) | (255 | ) | 224 | ||||||
Prepaid expenses and other | (11,362 | ) | (709 | ) | (1,310 | ) | |||||
Accounts payable and accrued liabilities | 36,762 | 15,922 | 802 | ||||||||
Accounts payable and accrued liabilities-related party | (2 | ) | (216 | ) | 218 | ||||||
Income tax payable | 814 | — | — | ||||||||
Accrued interest | (20,774 | ) | (3,161 | ) | (255 | ) | |||||
Revenues and royalties payable | 45,298 | 6,439 | (13,034 | ) | |||||||
Net cash provided by operating activities | 888,625 | 332,080 | 416,501 | ||||||||
Cash flows from investing activities: | |||||||||||
Additions to oil and natural gas properties | (792,599 | ) | (362,450 | ) | (419,241 | ) | |||||
Additions to oil and natural gas properties-related party | — | (637 | ) | (271 | ) | ||||||
Additions to midstream assets | (68,139 | ) | (1,188 | ) | — | ||||||
Purchase of other property, equipment and land | (22,779 | ) | (9,891 | ) | (1,213 | ) | |||||
Acquisition of leasehold interests | (1,960,591 | ) | (611,280 | ) | (437,455 | ) | |||||
Acquisition of mineral interests | (407,450 | ) | (205,721 | ) | (43,907 | ) | |||||
Acquisition of midstream assets | (50,279 | ) | — | — | |||||||
Proceeds from sale of assets | 65,656 | 4,661 | 9,739 | ||||||||
Funds held in escrow | 104,087 | (121,391 | ) | — | |||||||
Equity investments | (188 | ) | (2,345 | ) | (2,702 | ) | |||||
Net cash used in investing activities | (3,132,282 | ) | (1,310,242 | ) | (895,050 | ) | |||||
Cash flows from financing activities: | |||||||||||
Proceeds from borrowings under credit facility | 753,500 | 164,000 | 425,001 | ||||||||
Repayment under credit facility | (383,500 | ) | (89,000 | ) | (603,001 | ) | |||||
Proceeds from senior notes | — | 1,000,000 | — | ||||||||
Repayment of senior notes | — | (450,000 | ) | — | |||||||
Premium on extinguishment of debt | — | (26,561 | ) | — | |||||||
Debt issuance costs | (9,296 | ) | (15,063 | ) | (526 | ) | |||||
Public offering costs | (510 | ) | (1,182 | ) | (586 | ) |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(In thousands) | |||||||||||
Proceeds from public offerings | 370,344 | 2,051,503 | 650,688 | ||||||||
Proceeds from exercise of stock options | 358 | 498 | 4,873 | ||||||||
Distributions to non-controlling interest | (41,367 | ) | (9,574 | ) | (7,968 | ) | |||||
Net cash provided by financing activities | 689,529 | 2,624,621 | 468,481 | ||||||||
Net increase (decrease) in cash and cash equivalents | (1,554,128 | ) | 1,646,459 | (10,068 | ) | ||||||
Cash and cash equivalents at beginning of period | 1,666,574 | 20,115 | 30,183 | ||||||||
Cash and cash equivalents at end of period | $ | 112,446 | $ | 1,666,574 | $ | 20,115 | |||||
Supplemental disclosure of cash flow information: | |||||||||||
Interest paid, net of capitalized interest | $ | 57,668 | $ | 38,177 | $ | 38,758 | |||||
Cash paid for income taxes | $ | — | $ | 192 | $ | 267 | |||||
Supplemental disclosure of non-cash transactions: | |||||||||||
Change in accrued capital expenditures | $ | 160,906 | $ | 413 | $ | (69,460 | ) | ||||
Capitalized stock-based compensation | $ | 8,641 | $ | 7,079 | $ | 6,043 | |||||
Common stock issued for oil and natural gas properties | $ | 809,173 | $ | — | $ | — | |||||
Asset retirement obligations acquired | $ | 2,432 | $ | 3,696 | $ | 3,159 |
December 31, | |||||||
2017 | 2016 | ||||||
(In thousands) | |||||||
Liability for drilling costs prepaid by joint interest partners | $ | 30,320 | $ | 21,595 | |||
Interest payable | 6,770 | 5,445 | |||||
Lease operating expenses payable | 27,850 | 13,857 | |||||
Ad valorem taxes payable | 3,306 | 776 | |||||
Current portion of asset retirement obligations | 1,163 | 1,288 | |||||
Other | 23,103 | 12,369 | |||||
Total other accrued liabilities | $ | 92,512 | $ | 55,330 |
(in thousands) | |||
Proved oil and natural gas properties | $ | 386,308 | |
Unevaluated oil and natural gas properties | 2,122,597 | ||
Midstream assets | 47,432 | ||
Prepaid capital costs | 3,460 | ||
Oil inventory | 839 | ||
Equipment | 163 | ||
Revenues and royalties payable | (9,650 | ) | |
Asset retirement obligations | (1,550 | ) | |
Total fair value of net assets | $ | 2,549,599 |
Year Ended December 31, | |||||||
2017 | 2016 | ||||||
(in thousands, except per share amounts) | |||||||
Revenues | $ | 1,228,040 | $ | 627,301 | |||
Income (loss) from operations | 619,369 | (12,812 | ) | ||||
Net income (loss) | 472,649 | (109,229 | ) | ||||
Basic earnings per common share | 4.85 | (1.45 | ) | ||||
Diluted earnings per common share | 4.84 | (1.45 | ) |
December 31, | |||||||
2017 | 2016 | ||||||
(in thousands) | |||||||
Oil and natural gas properties: | |||||||
Subject to depletion | $ | 5,126,829 | $ | 3,429,742 | |||
Not subject to depletion | 4,105,865 | 1,730,519 | |||||
Gross oil and natural gas properties | 9,232,694 | 5,160,261 | |||||
Accumulated depletion | (1,009,893 | ) | (687,685 | ) | |||
Accumulated impairment | (1,143,498 | ) | (1,143,498 | ) | |||
Oil and natural gas properties, net | 7,079,303 | 3,329,078 | |||||
Midstream assets | 191,519 | 8,362 | |||||
Other property, equipment and land | 80,776 | 58,290 | |||||
Accumulated depreciation | (7,981 | ) | (4,873 | ) | |||
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment | $ | 7,343,617 | $ | 3,390,857 | |||
Balance of costs not subject to depletion: | |||||||
Incurred in 2017 | $ | 2,746,936 | |||||
Incurred in 2016 | 727,411 | ||||||
Incurred in 2015 | 301,879 | ||||||
Incurred in 2014 | 316,455 | ||||||
Incurred in 2013 | 13,184 | ||||||
Total not subject to depletion | $ | 4,105,865 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in thousands) | |||||||||||
Asset retirement obligations, beginning of period | $ | 17,422 | $ | 12,711 | $ | 8,486 | |||||
Additional liabilities incurred | 1,526 | 637 | 594 | ||||||||
Liabilities acquired | 2,432 | 3,696 | 3,159 | ||||||||
Liabilities settled | (1,555 | ) | (711 | ) | (292 | ) | |||||
Accretion expense | 1,391 | 1,064 | 833 | ||||||||
Revisions in estimated liabilities | 69 | 25 | (69 | ) | |||||||
Asset retirement obligations, end of period | 21,285 | 17,422 | 12,711 | ||||||||
Less current portion | 1,163 | 1,288 | 193 | ||||||||
Asset retirement obligations - long-term | $ | 20,122 | $ | 16,134 | $ | 12,518 |
December 31, | |||||||
2017 | 2016 | ||||||
(in thousands) | |||||||
4.750 % Senior Notes due 2024 | 500,000 | 500,000 | |||||
5.375 % Senior Notes due 2025 | 500,000 | 500,000 | |||||
Unamortized debt issuance costs | (13,153 | ) | (14,588 | ) | |||
Revolving credit facility | 397,000 | — | |||||
Partnership revolving credit facility | 93,500 | 120,500 | |||||
Total long-term debt | $ | 1,477,347 | $ | 1,105,912 |
Financial Covenant | Required Ratio |
Ratio of total debt to EBITDAX | Not greater than 3.0 to 1.0 |
Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
Financial Covenant | Required Ratio |
Ratio of total debt to EBITDAX | Not greater than 4.0 to 1.0 |
Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in thousands) | |||||||||||
Interest expense | $ | 60,671 | $ | 39,642 | $ | 40,221 | |||||
Less capitalized interest | (22,097 | ) | — | — | |||||||
Other fees and expenses | 2,160 | 1,426 | 1,292 | ||||||||
Total interest expense | $ | 40,734 | $ | 41,068 | $ | 41,513 |
Date | Number of Shares of Common Stock Sold | Number of Shares of Common Stock Issued to Underwriters | Price per Share Sold to Underwriters | Proceeds Received by the Company | |||||
January 2015 | 2,012,500 | 262,500 | $ | 59.34 | $ | 119,422 | |||
May 2015 | 4,600,000 | 600,000 | $ | 72.53 | $ | 333,638 | |||
August 2015 | 2,875,000 | 375,000 | $ | 68.74 | $ | 197,628 | |||
January 2016 | 4,600,000 | 600,000 | $ | 55.33 | $ | 254,518 | |||
July 2016 | 6,325,000 | 825,000 | $ | 87.24 | $ | 551,777 | |||
December 2016 | 12,075,000 | 1,575,000 | $ | 95.3025 | $ | 1,150,828 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
Net income (loss) attributable to common stock | $ | 482,261 | $ | (165,034 | ) | $ | (550,628 | ) | |||
Weighted average common shares outstanding | |||||||||||
Basic weighted average common units outstanding | 97,458 | 75,077 | 63,019 | ||||||||
Effect of dilutive securities: | |||||||||||
Potential common shares issuable | 230 | — | — | ||||||||
Diluted weighted average common shares outstanding | 97,688 | 75,077 | 63,019 | ||||||||
Basic net income (loss) attributable to common stock | $ | 4.95 | $ | (2.20 | ) | $ | (8.74 | ) | |||
Diluted net income (loss) attributable to common stock | $ | 4.94 | $ | (2.20 | ) | $ | (8.74 | ) |
2017 | 2016 | 2015 | |||||||||
(In thousands) | |||||||||||
General and administrative expenses | $ | 25,537 | $ | 26,453 | $ | 18,529 | |||||
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties | 8,641 | 7,079 | 6,043 |
Weighted Average | ||||||||||||
Exercise | Remaining | Intrinsic | ||||||||||
Options | Price | Term | Value | |||||||||
(in years) | (in thousands) | |||||||||||
Outstanding at December 31, 2016 | 15,750 | $ | 22.72 | |||||||||
Exercised | (15,750 | ) | $ | 22.72 | ||||||||
Outstanding at December 31, 2017 | — | $ | — | 0.00 | $ | — |
Restricted Stock Awards & Units | Weighted Average Grant-Date Fair Value | |||||
Unvested at December 31, 2016 | 206,004 | $ | 70.33 | |||
Granted | 188,438 | $ | 102.77 | |||
Vested | (147,934 | ) | $ | 77.44 | ||
Forfeited | (2,931 | ) | $ | 89.21 | ||
Unvested at December 31, 2017 | 243,577 | $ | 90.88 |
2017 | 2016 | ||||||||||||||||||
Two-Year Performance Period | Three-Year Performance Period | Two-Year Performance Period | Three-Year Performance Period | 2015 | |||||||||||||||
Grant-date fair value | $ | 162.13 | $ | 168.73 | $ | 103.41 | $ | 102.35 | $ | 137.14 | |||||||||
Risk-free rate | 1.27 | % | 1.59 | % | 0.86 | % | 1.10 | % | 0.49 | % | |||||||||
Company volatility | 39.32 | % | 41.14 | % | 41.91 | % | 42.16 | % | 43.36 | % |
Performance Restricted Stock Units | Weighted Average Grant-Date Fair Value | |||||
Unvested at December 31, 2016 | 252,471 | $ | 103.06 | |||
Granted | 118,169 | $ | 166.53 | |||
Vested | (168,314 | ) | $ | 103.41 | ||
Unvested at December 31, 2017(1) | 202,326 | $ | 139.83 |
(1) | A maximum of 404,652 units could be awarded based upon the Company’s final TSR ranking. |
2015 | |||
Grant-date fair value | $ | 4.24 | |
Expected volatility | 36.0 | % | |
Expected dividend yield | 5.9 | % | |
Expected term (in years) | 3.0 | ||
Risk-free rate | 0.99 | % |
Weighted Average | ||||||||||||
Unit Options | Exercise Price | Remaining Term | Intrinsic Value | |||||||||
(in years) | (in thousands) | |||||||||||
Outstanding at December 31, 2016 | 2,424,266 | $ | 26.00 | |||||||||
Forfeited | (2,416,666 | ) | $ | 26.00 | ||||||||
Outstanding at December 31, 2017 | 7,600 | $ | 18.49 | 0.00 | $ | — | ||||||
Vested and Expected to vest at December 31, 2017 | 7,600 | $ | 18.49 | 0.00 | $ | — |
Phantom Units | Weighted Average Grant-Date Fair Value | |||||
Unvested at December 31, 2016 | 21,048 | $ | 16.23 | |||
Granted | 116,567 | $ | 17.09 | |||
Vested | (32,176 | ) | $ | 16.49 | ||
Unvested at December 31, 2017 | 105,439 | $ | 17.10 |
Date of Amendments | Rent for Additional Space | Approx. Annual Increase of Monthly Base Rent |
2nd quarter 2014 | $27,000 | N/A |
4th quarter 2014 | $53,000 | 4% |
April 2015 | $23,000 | N/A |
June 2015 | $22,000 | 2% |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(In thousands) | |||||||||||
Current income tax provision (benefit): | |||||||||||
Federal | $ | — | $ | — | $ | (33 | ) | ||||
State | 999 | 192 | 268 | ||||||||
Total current income tax provision | 999 | 192 | 235 | ||||||||
Deferred income tax provision (benefit): | |||||||||||
Federal | (21,720 | ) | (579 | ) | (198,729 | ) | |||||
State | 1,153 | 579 | (2,816 | ) | |||||||
Total deferred income tax provision (benefit) | (20,567 | ) | — | (201,545 | ) | ||||||
Total provision for (benefit from) income taxes | $ | (19,568 | ) | $ | 192 | $ | (201,310 | ) |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(In thousands) | |||||||||||
Income tax expense (benefit) at the federal statutory rate (35%) | $ | 174,016 | $ | (57,694 | ) | $ | (263,179 | ) | |||
Impact of nontaxable noncontrolling interest | (12,073 | ) | — | — | |||||||
Income tax benefit relating to change in statutory tax rate | (67,938 | ) | — | (1,145 | ) | ||||||
State income tax expense (benefit), net of federal tax effect | 3,413 | 770 | (2,548 | ) | |||||||
Non-deductible compensation | 13,492 | 3,990 | 1,354 | ||||||||
Change in valuation allowance | (127,485 | ) | 53,336 | 61,056 | |||||||
Other, net | (2,993 | ) | (210 | ) | 3,152 | ||||||
Provision for (benefit from) income taxes | $ | (19,568 | ) | $ | 192 | $ | (201,310 | ) |
December 31, | |||||||
2017 | 2016 | ||||||
(In thousands) | |||||||
Current: | |||||||
Deferred tax assets | |||||||
Derivative instruments | $ | — | $ | 7,771 | |||
Other | — | 3,518 | |||||
Current deferred tax assets | — | 11,289 | |||||
Valuation allowance | — | (11,289 | ) | ||||
Current deferred tax assets, net of valuation allowance | — | — | |||||
Deferred tax liabilities | |||||||
Derivative instruments | — | — | |||||
Total current deferred tax liabilities | — | — | |||||
Net current deferred tax assets | — | — | |||||
Noncurrent: | |||||||
Deferred tax assets | |||||||
Net operating loss carryforwards (subject to 20 year expiration) | 74,997 | 139,065 | |||||
Derivative instruments | 22,918 | — | |||||
Stock based compensation | 942 | 6,234 | |||||
Other | 2,464 | — | |||||
Noncurrent deferred tax assets | 101,321 | 145,299 | |||||
Valuation allowance | (104 | ) | (103,112 | ) | |||
Noncurrent deferred tax assets, net of valuation allowance | 101,217 | 42,187 | |||||
Deferred tax liabilities | |||||||
Oil and natural gas properties and equipment | 202,997 | 42,187 | |||||
Midstream assets | 6,268 | — | |||||
Total noncurrent deferred tax liabilities | 209,265 | 42,187 | |||||
Net noncurrent deferred tax liabilities | 108,048 | — | |||||
Net deferred tax liabilities | $ | 108,048 | $ | — |
2018 | 2019 | ||||||||||
Volume (Bbls/MMBtu) | Fixed Price Swap (per Bbl/MMBtu) | Volume (Bbls/MMBtu) | Fixed Price Swap (per Bbl/MMBtu) | ||||||||
Oil Swaps - WTI | 9,761,000 | $ | 51.10 | 1,095,000 | $ | 49.82 | |||||
Oil Swaps - BRENT | 1,830,000 | $ | 54.89 | 0 | $ | — | |||||
Oil Basis Swaps | 5,475,000 | $ | 0.88 | 0 | $ | — | |||||
Natural Gas Swaps | 7,750,000 | $ | 3.14 | 0 | $ | — |
Floor | Ceiling | ||||||||||
Volume (Bbls) | Fixed Price (per Bbl) | Volume (Bbls) | Fixed Price (per Bbl) | ||||||||
January 2018 - March 2018 | |||||||||||
Costless Collars | 540,000 | $ | 47.00 | 270,000 | $ | 56.34 |
December 31, | |||||||
2017 | 2016 | ||||||
(in thousands) | |||||||
Gross amounts of assets presented in the Consolidated Balance Sheet | $ | 531 | $ | 709 | |||
Net amounts of assets presented in the Consolidated Balance Sheet | 531 | 709 | |||||
Gross amounts of liabilities presented in the Consolidated Balance Sheet | 106,670 | 22,608 | |||||
Net amounts of liabilities presented in the Consolidated Balance Sheet | $ | 106,670 | $ | 22,608 |
December 31, | |||||||
2017 | 2016 | ||||||
(in thousands) | |||||||
Current assets: derivative instruments | $ | 531 | $ | — | |||
Noncurrent assets: derivative instruments | — | 709 | |||||
Total assets | $ | 531 | $ | 709 | |||
Current liabilities: derivative instruments | $ | 100,367 | $ | 22,608 | |||
Noncurrent liabilities: derivative instruments | 6,303 | — | |||||
Total liabilities | $ | 106,670 | $ | 22,608 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in thousands) | |||||||||||
Change in fair value of open non-hedge derivative instruments | $ | (84,240 | ) | $ | (26,522 | ) | $ | (112,918 | ) | ||
Gain on settlement of non-hedge derivative instruments | 6,728 | 1,177 | 144,869 | ||||||||
Gain (loss) on derivative instruments | $ | (77,512 | ) | $ | (25,345 | ) | $ | 31,951 |
December 31, | |||||||
2017 | 2016 | ||||||
(in thousands) | |||||||
Fixed price swaps: | |||||||
Quoted prices in active markets level 1 | $ | — | $ | — | |||
Significant other observable inputs level 2 | (106,139 | ) | 23,317 | ||||
Significant unobservable inputs level 3 | — | — | |||||
Total | $ | (106,139 | ) | $ | 23,317 |
December 31, 2017 | December 31, 2016 | ||||||||||||||
Carrying | Carrying | ||||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||
(in thousands) | |||||||||||||||
Debt: | |||||||||||||||
Revolving credit facility | $ | 397,000 | $ | 397,000 | $ | — | $ | — | |||||||
4.750% Senior Notes due 2024 | 500,000 | 501,855 | 500,000 | 491,250 | |||||||||||
5.375% Senior Notes due 2025 | 500,000 | 515,000 | 500,000 | 502,850 | |||||||||||
Partnership revolving credit facility | 93,500 | 93,500 | 120,500 | 120,500 |
Year Ending December 31, | Drilling Rig Commitments | Office and Equipment Leases | |||||
(in thousands) | |||||||
2018 | $ | 21,882 | $ | 3,581 | |||
2019 | 10,082 | 3,307 | |||||
2020 | — | 2,927 | |||||
2021 | — | 2,406 | |||||
2022 | — | 2,242 | |||||
Thereafter | — | 7,973 | |||||
Total | $ | 31,964 | $ | 22,436 |
Year ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in thousands) | |||||||||||
Rent Expense | $ | 2,412 | $ | 1,961 | $ | 1,449 |
Volume (Bbls/MMBtu) | Fixed Price Swap (per Bbl/MMBtu) | ||||
July 2018 - December 2018 | |||||
Oil Swaps - WTI | 184,000 | $ | 60.70 | ||
January 2019 - March 2019 | |||||
Oil Swaps - WTI | 90,000 | $ | 58.70 |
Condensed Consolidated Balance Sheet | |||||||||||||||||||
December 31, 2017 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Non– | |||||||||||||||||||
Guarantor | Guarantor | ||||||||||||||||||
Parent | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Assets | |||||||||||||||||||
Current assets: | |||||||||||||||||||
Cash and cash equivalents | $ | 54,074 | $ | 34,175 | $ | 24,197 | $ | — | $ | 112,446 | |||||||||
Accounts receivable | — | 205,859 | 25,754 | — | 231,613 | ||||||||||||||
Accounts receivable - related party | — | — | 5,142 | (5,142 | ) | — | |||||||||||||
Intercompany receivable | 2,624,810 | 2,267,308 | — | (4,892,118 | ) | — | |||||||||||||
Inventories | — | 9,108 | — | — | 9,108 | ||||||||||||||
Other current assets | 618 | 4,461 | 355 | — | 5,434 | ||||||||||||||
Total current assets | 2,679,502 | 2,520,911 | 55,448 | (4,897,260 | ) | 358,601 | |||||||||||||
Property and equipment: | |||||||||||||||||||
Oil and natural gas properties, at cost, full cost method of accounting | — | 8,129,211 | 1,103,897 | (414 | ) | 9,232,694 | |||||||||||||
Midstream assets | — | 191,519 | — | — | 191,519 | ||||||||||||||
Other property, equipment and land | — | 80,776 | — | — | 80,776 | ||||||||||||||
Accumulated depletion, depreciation, amortization and impairment | — | (1,976,248 | ) | (189,466 | ) | 4,342 | (2,161,372 | ) | |||||||||||
Net property and equipment | — | 6,425,258 | 914,431 | 3,928 | 7,343,617 | ||||||||||||||
Funds held in escrow | — | — | 6,304 | — | 6,304 | ||||||||||||||
Derivative instruments | — | — | — | — | — | ||||||||||||||
Investment in subsidiaries | 3,809,557 | — | — | (3,809,557 | ) | — | |||||||||||||
Other assets | — | 25,609 | 36,854 | — | 62,463 | ||||||||||||||
Total assets | $ | 6,489,059 | $ | 8,971,778 | $ | 1,013,037 | $ | (8,702,889 | ) | $ | 7,770,985 | ||||||||
Liabilities and Stockholders’ Equity | |||||||||||||||||||
Current liabilities: | |||||||||||||||||||
Accounts payable-trade | $ | 1 | $ | 91,629 | $ | 2,960 | $ | — | $ | 94,590 | |||||||||
Intercompany payable | 132,067 | 4,765,193 | — | (4,897,260 | ) | — | |||||||||||||
Other current liabilities | 7,236 | 472,933 | 2,669 | — | 482,838 | ||||||||||||||
Total current liabilities | 139,304 | 5,329,755 | 5,629 | (4,897,260 | ) | 577,428 | |||||||||||||
Long-term debt | 986,847 | 397,000 | 93,500 | — | 1,477,347 | ||||||||||||||
Derivative instruments | — | 6,303 | — | — | 6,303 | ||||||||||||||
Asset retirement obligations | — | 20,122 | — | — | 20,122 | ||||||||||||||
Deferred income taxes | 108,048 | — | — | — | 108,048 | ||||||||||||||
Total liabilities | 1,234,199 | 5,753,180 | 99,129 | (4,897,260 | ) | 2,189,248 | |||||||||||||
Commitments and contingencies | |||||||||||||||||||
Stockholders’ equity | 5,254,860 | 3,218,598 | 913,908 | (4,132,506 | ) | 5,254,860 | |||||||||||||
Non-controlling interest | — | — | — | 326,877 | 326,877 | ||||||||||||||
Total equity | 5,254,860 | 3,218,598 | 913,908 | (3,805,629 | ) | 5,581,737 | |||||||||||||
Total liabilities and equity | $ | 6,489,059 | $ | 8,971,778 | $ | 1,013,037 | $ | (8,702,889 | ) | $ | 7,770,985 |
Condensed Consolidated Balance Sheet | |||||||||||||||||||
December 31, 2016 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Non– | |||||||||||||||||||
Guarantor | Guarantor | ||||||||||||||||||
Parent | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Assets | |||||||||||||||||||
Current assets: | |||||||||||||||||||
Cash and cash equivalents | $ | 1,643,226 | $ | 14,135 | $ | 9,213 | $ | — | $ | 1,666,574 | |||||||||
Restricted cash | — | — | 500 | — | 500 | ||||||||||||||
Accounts receivable | — | 109,782 | 10,043 | — | 119,825 | ||||||||||||||
Accounts receivable - related party | — | 297 | 3,470 | (3,470 | ) | 297 | |||||||||||||
Intercompany receivable | 3,060,566 | 359,502 | — | (3,420,068 | ) | — | |||||||||||||
Inventories | — | 1,983 | — | — | 1,983 | ||||||||||||||
Other current assets | 481 | 2,319 | 187 | — | 2,987 | ||||||||||||||
Total current assets | 4,704,273 | 488,018 | 23,413 | (3,423,538 | ) | 1,792,166 | |||||||||||||
Property and equipment: | |||||||||||||||||||
Oil and natural gas properties, at cost, full cost method of accounting | — | 4,400,002 | 760,818 | (559 | ) | 5,160,261 | |||||||||||||
Midstream assets | — | 8,362 | — | — | 8,362 | ||||||||||||||
Other property, equipment and land | — | 58,290 | — | — | 58,290 | ||||||||||||||
Accumulated depletion, depreciation, amortization and impairment | — | (1,695,701 | ) | (148,948 | ) | 8,593 | (1,836,056 | ) | |||||||||||
Net property and equipment | — | 2,770,953 | 611,870 | 8,034 | 3,390,857 | ||||||||||||||
Funds held in escrow | — | 121,391 | — | — | 121,391 | ||||||||||||||
Derivative instruments | — | 709 | — | — | 709 | ||||||||||||||
Investment in subsidiaries | (15,500 | ) | — | — | 15,500 | — | |||||||||||||
Other assets | — | 9,291 | 35,266 | — | 44,557 | ||||||||||||||
Total assets | $ | 4,688,773 | $ | 3,390,362 | $ | 670,549 | $ | (3,400,004 | ) | $ | 5,349,680 | ||||||||
Liabilities and Stockholders’ Equity | |||||||||||||||||||
Current liabilities: | |||||||||||||||||||
Accounts payable-trade | $ | 30 | $ | 45,838 | $ | 1,780 | $ | — | $ | 47,648 | |||||||||
Accounts payable-related party | 1 | — | — | — | 1 | ||||||||||||||
Intercompany payable | — | 3,423,538 | — | (3,423,538 | ) | — | |||||||||||||
Other current liabilities | 5,868 | 155,454 | 371 | — | 161,693 | ||||||||||||||
Total current liabilities | 5,899 | 3,624,830 | 2,151 | (3,423,538 | ) | 209,342 | |||||||||||||
Long-term debt | 985,412 | — | 120,500 | — | 1,105,912 | ||||||||||||||
Asset retirement obligations | — | 16,134 | — | — | 16,134 | ||||||||||||||
Total liabilities | 991,311 | 3,640,964 | 122,651 | (3,423,538 | ) | 1,331,388 | |||||||||||||
Commitments and contingencies | |||||||||||||||||||
Stockholders’ equity | 3,697,462 | (250,602 | ) | 547,898 | (297,296 | ) | 3,697,462 | ||||||||||||
Non-controlling interest | — | — | — | 320,830 | 320,830 | ||||||||||||||
Total equity | 3,697,462 | (250,602 | ) | 547,898 | 23,534 | 4,018,292 | |||||||||||||
Total liabilities and equity | $ | 4,688,773 | $ | 3,390,362 | $ | 670,549 | $ | (3,400,004 | ) | $ | 5,349,680 |
Condensed Consolidated Statement of Operations | |||||||||||||||||||
Year Ended December 31, 2017 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Non– | |||||||||||||||||||
Guarantor | Guarantor | ||||||||||||||||||
Parent | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues: | |||||||||||||||||||
Oil sales | $ | — | $ | 903,842 | $ | — | $ | 140,175 | $ | 1,044,017 | |||||||||
Natural gas sales | — | 42,899 | — | 9,311 | 52,210 | ||||||||||||||
Natural gas liquid sales | — | 79,371 | — | 10,677 | 90,048 | ||||||||||||||
Royalty income | — | — | 160,163 | (160,163 | ) | — | |||||||||||||
Lease bonus income | — | — | 11,870 | (106 | ) | 11,764 | |||||||||||||
Midstream services | — | 7,072 | — | — | 7,072 | ||||||||||||||
Total revenues | — | 1,033,184 | 172,033 | (106 | ) | 1,205,111 | |||||||||||||
Costs and expenses: | |||||||||||||||||||
Lease operating expenses | — | 126,524 | — | — | 126,524 | ||||||||||||||
Production and ad valorem taxes | — | 62,897 | 10,608 | — | 73,505 | ||||||||||||||
Gathering and transportation | — | 12,045 | 789 | — | 12,834 | ||||||||||||||
Midstream services | — | 10,409 | — | — | 10,409 | ||||||||||||||
Depreciation, depletion and amortization | — | 281,989 | 40,519 | 4,251 | 326,759 | ||||||||||||||
General and administrative expenses | 26,776 | 18,057 | 6,296 | (2,460 | ) | 48,669 | |||||||||||||
Asset retirement obligation accretion | — | 1,391 | — | — | 1,391 | ||||||||||||||
Total costs and expenses | 26,776 | 513,312 | 58,212 | 1,791 | 600,091 | ||||||||||||||
Income (loss) from operations | (26,776 | ) | 519,872 | 113,821 | (1,897 | ) | 605,020 | ||||||||||||
Other income (expense) | |||||||||||||||||||
Interest expense, net | (29,925 | ) | (7,465 | ) | (3,164 | ) | — | (40,554 | ) | ||||||||||
Other income, net | 1,142 | 10,732 | 821 | (2,460 | ) | 10,235 | |||||||||||||
Loss on derivative instruments, net | — | (77,512 | ) | — | — | (77,512 | ) | ||||||||||||
Total other expense, net | (28,783 | ) | (74,245 | ) | (2,343 | ) | (2,460 | ) | (107,831 | ) | |||||||||
Income (loss) before income taxes | (55,559 | ) | 445,627 | 111,478 | (4,357 | ) | 497,189 | ||||||||||||
Benefit from income taxes | (19,568 | ) | — | — | — | (19,568 | ) | ||||||||||||
Net income (loss) | (35,991 | ) | 445,627 | 111,478 | (4,357 | ) | 516,757 | ||||||||||||
Net income attributable to non-controlling interest | — | — | — | 34,496 | 34,496 | ||||||||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | $ | (35,991 | ) | $ | 445,627 | $ | 111,478 | $ | (38,853 | ) | $ | 482,261 |
Condensed Consolidated Statement of Operations | |||||||||||||||||||
Year Ended December 31, 2016 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Non– | |||||||||||||||||||
Guarantor | Guarantor | ||||||||||||||||||
Parent | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues: | |||||||||||||||||||
Oil sales | $ | — | $ | 399,007 | $ | — | $ | 71,521 | $ | 470,528 | |||||||||
Natural gas sales | — | 19,399 | — | 3,107 | 22,506 | ||||||||||||||
Natural gas liquid sales | — | 29,864 | — | 4,209 | 34,073 | ||||||||||||||
Royalty income | — | — | 78,837 | (78,837 | ) | — | |||||||||||||
Lease bonus income | — | — | 309 | (309 | ) | — | |||||||||||||
Total revenues | — | 448,270 | 79,146 | (309 | ) | 527,107 | |||||||||||||
Costs and expenses: | |||||||||||||||||||
Lease operating expenses | — | 82,428 | — | — | 82,428 | ||||||||||||||
Production and ad valorem taxes | — | 28,912 | 5,544 | — | 34,456 | ||||||||||||||
Gathering and transportation | — | 11,189 | 415 | 2 | 11,606 | ||||||||||||||
Depreciation, depletion and amortization | — | 151,376 | 29,820 | (3,181 | ) | 178,015 | |||||||||||||
Impairment of oil and natural gas properties | — | 198,067 | 47,469 | — | 245,536 | ||||||||||||||
General and administrative expenses | 25,959 | 11,451 | 5,209 | — | 42,619 | ||||||||||||||
Asset retirement obligation accretion | — | 1,064 | — | — | 1,064 | ||||||||||||||
Total costs and expenses | 25,959 | 484,487 | 88,457 | (3,179 | ) | 595,724 | |||||||||||||
Income (loss) from operations | (25,959 | ) | (36,217 | ) | (9,311 | ) | 2,870 | (68,617 | ) | ||||||||||
Other income (expense) | |||||||||||||||||||
Interest expense, net | (35,318 | ) | (2,911 | ) | (2,455 | ) | — | (40,684 | ) | ||||||||||
Other income, net | 437 | 2,010 | 867 | (250 | ) | 3,064 | |||||||||||||
Loss on derivative instruments, net | — | (25,345 | ) | — | — | (25,345 | ) | ||||||||||||
Loss on extinguishment of debt | (33,134 | ) | — | — | — | (33,134 | ) | ||||||||||||
Total other expense, net | (68,015 | ) | (26,246 | ) | (1,588 | ) | (250 | ) | (96,099 | ) | |||||||||
Income (loss) before income taxes | (93,974 | ) | (62,463 | ) | (10,899 | ) | 2,620 | (164,716 | ) | ||||||||||
Provision for income taxes | 192 | — | — | — | 192 | ||||||||||||||
Net income (loss) | (94,166 | ) | (62,463 | ) | (10,899 | ) | 2,620 | (164,908 | ) | ||||||||||
Net income attributable to non-controlling interest | — | — | — | 126 | 126 | ||||||||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | $ | (94,166 | ) | $ | (62,463 | ) | $ | (10,899 | ) | $ | 2,494 | $ | (165,034 | ) |
Condensed Consolidated Statement of Operations | |||||||||||||||||||
Year Ended December 31, 2015 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Non– | |||||||||||||||||||
Guarantor | Guarantor | ||||||||||||||||||
Parent | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues: | |||||||||||||||||||
Oil sales | $ | — | $ | 336,106 | $ | — | $ | 69,609 | $ | 405,715 | |||||||||
Natural gas sales | — | 16,932 | — | 2,660 | 19,592 | ||||||||||||||
Natural gas liquid sales | — | 18,836 | — | 2,590 | 21,426 | ||||||||||||||
Royalty income | — | — | 74,859 | (74,859 | ) | — | |||||||||||||
Total revenues | — | 371,874 | 74,859 | — | 446,733 | ||||||||||||||
Costs and expenses: | |||||||||||||||||||
Lease operating expenses | — | 82,625 | — | — | 82,625 | ||||||||||||||
Production and ad valorem taxes | — | 27,459 | 5,531 | — | 32,990 | ||||||||||||||
Gathering and transportation | — | 5,832 | 259 | — | 6,091 | ||||||||||||||
Depreciation, depletion and amortization | — | 182,395 | 35,436 | (134 | ) | 217,697 | |||||||||||||
Impairment of oil and natural gas properties | — | 814,798 | 3,423 | (3,423 | ) | 814,798 | |||||||||||||
General and administrative expenses | 17,077 | 9,056 | 5,835 | — | 31,968 | ||||||||||||||
Asset retirement obligation accretion expense | — | 833 | — | — | 833 | ||||||||||||||
Total costs and expenses | 17,077 | 1,122,998 | 50,484 | (3,557 | ) | 1,187,002 | |||||||||||||
Income (loss) from operations | (17,077 | ) | (751,124 | ) | 24,375 | 3,557 | (740,269 | ) | |||||||||||
Other income (expense) | |||||||||||||||||||
Interest expense, net | (35,651 | ) | (4,749 | ) | (1,110 | ) | — | (41,510 | ) | ||||||||||
Other income, net | 1 | (427 | ) | 1,154 | — | 728 | |||||||||||||
Gain on derivative instruments, net | — | 31,951 | — | — | 31,951 | ||||||||||||||
Total other expense, net | (35,650 | ) | 26,775 | 44 | — | (8,831 | ) | ||||||||||||
Income (loss) before income taxes | (52,727 | ) | (724,349 | ) | 24,419 | 3,557 | (749,100 | ) | |||||||||||
Benefit from income taxes | (201,310 | ) | — | — | — | (201,310 | ) | ||||||||||||
Net income (loss) | $ | 148,583 | $ | (724,349 | ) | $ | 24,419 | $ | 3,557 | $ | (547,790 | ) | |||||||
Net income attributable to non-controlling interest | $ | — | $ | — | $ | — | $ | 2,838 | $ | 2,838 | |||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | $ | 148,583 | $ | (724,349 | ) | $ | 24,419 | $ | 719 | $ | (550,628 | ) |
Condensed Consolidated Statement of Cash Flows | |||||||||||||||||||
Year Ended December 31, 2017 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Non– | |||||||||||||||||||
Guarantor | Guarantor | ||||||||||||||||||
Parent | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Net cash provided by (used in) operating activities | $ | (29,470 | ) | $ | 778,876 | $ | 139,219 | $ | — | $ | 888,625 | ||||||||
Cash flows from investing activities: | |||||||||||||||||||
Additions to oil and natural gas properties | — | (792,599 | ) | — | — | (792,599 | ) | ||||||||||||
Additions to midstream assets | — | (68,139 | ) | — | — | (68,139 | ) | ||||||||||||
Purchase of other property, equipment and land | — | (22,779 | ) | — | — | (22,779 | ) | ||||||||||||
Acquisition of leasehold interests | — | (1,960,591 | ) | — | — | (1,960,591 | ) | ||||||||||||
Acquisition of mineral interests | — | (63,371 | ) | (344,079 | ) | — | (407,450 | ) | |||||||||||
Acquisition of midstream assets | — | (50,279 | ) | — | — | (50,279 | ) | ||||||||||||
Proceeds from sale of assets | — | 65,656 | — | — | 65,656 | ||||||||||||||
Funds held in escrow | — | 104,087 | — | — | 104,087 | ||||||||||||||
Equity investments | — | (188 | ) | — | — | (188 | ) | ||||||||||||
Intercompany transfers | (1,631,078 | ) | 1,631,078 | — | — | — | |||||||||||||
Net cash used in investing activities | (1,631,078 | ) | (1,157,125 | ) | (344,079 | ) | — | (3,132,282 | ) | ||||||||||
Cash flows from financing activities: | |||||||||||||||||||
Proceeds from borrowing on credit facility | — | 475,000 | 278,500 | — | 753,500 | ||||||||||||||
Repayment on credit facility | — | (78,000 | ) | (305,500 | ) | — | (383,500 | ) | |||||||||||
Purchase of subsidiary units by parent | (10,068 | ) | — | — | 10,068 | — | |||||||||||||
Debt issuance costs | (8,326 | ) | 1,289 | (2,259 | ) | — | (9,296 | ) | |||||||||||
Public offering costs | (77 | ) | — | (433 | ) | — | (510 | ) | |||||||||||
Proceeds from public offerings | — | — | 380,412 | (10,068 | ) | 370,344 | |||||||||||||
Distribution from subsidiary | 89,509 | — | — | (89,509 | ) | — | |||||||||||||
Exercise of stock options | 358 | — | — | — | 358 | ||||||||||||||
Distribution to non-controlling interest | — | — | (130,876 | ) | 89,509 | (41,367 | ) | ||||||||||||
Net cash provided by financing activities | 71,396 | 398,289 | 219,844 | — | 689,529 | ||||||||||||||
Net increase (decrease) in cash and cash equivalents | (1,589,152 | ) | 20,040 | 14,984 | — | (1,554,128 | ) | ||||||||||||
Cash and cash equivalents at beginning of period | 1,643,226 | 14,135 | 9,213 | — | 1,666,574 | ||||||||||||||
Cash and cash equivalents at end of period | $ | 54,074 | $ | 34,175 | $ | 24,197 | $ | — | $ | 112,446 |
Condensed Consolidated Statement of Cash Flows | |||||||||||||||||||
Year Ended December 31, 2016 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Non– | |||||||||||||||||||
Guarantor | Guarantor | ||||||||||||||||||
Parent | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Net cash provided by (used in) operating activities | $ | (39,894 | ) | $ | 303,347 | $ | 68,627 | $ | — | $ | 332,080 | ||||||||
Cash flows from investing activities: | |||||||||||||||||||
Additions to oil and natural gas properties | — | (363,087 | ) | — | — | (363,087 | ) | ||||||||||||
Additions to midstream assets | — | (1,188 | ) | — | — | (1,188 | ) | ||||||||||||
Purchase of other property, equipment and land | — | (9,891 | ) | — | — | (9,891 | ) | ||||||||||||
Acquisition of leasehold interests | — | (611,280 | ) | — | — | (611,280 | ) | ||||||||||||
Acquisition of mineral interests | — | — | (205,721 | ) | — | (205,721 | ) | ||||||||||||
Proceeds from sale of assets | — | 4,661 | — | — | 4,661 | ||||||||||||||
Funds held in escrow | — | (121,391 | ) | — | — | (121,391 | ) | ||||||||||||
Equity investments | — | (2,345 | ) | — | — | (2,345 | ) | ||||||||||||
Intercompany transfers | (796,053 | ) | 796,053 | — | — | — | |||||||||||||
Net cash used in investing activities | (796,053 | ) | (308,468 | ) | (205,721 | ) | — | (1,310,242 | ) | ||||||||||
Cash flows from financing activities: | |||||||||||||||||||
Proceeds from borrowing on credit facility | — | — | 164,000 | — | 164,000 | ||||||||||||||
Repayment on credit facility | — | (11,000 | ) | (78,000 | ) | — | (89,000 | ) | |||||||||||
Proceeds from senior notes | 1,000,000 | — | — | — | 1,000,000 | ||||||||||||||
Repayment of senior notes | (450,000 | ) | — | — | — | (450,000 | ) | ||||||||||||
Premium on extinguishment of debt | (26,561 | ) | — | — | — | (26,561 | ) | ||||||||||||
Debt issuance costs | (14,449 | ) | (172 | ) | (442 | ) | — | (15,063 | ) | ||||||||||
Public offering costs | (636 | ) | — | (546 | ) | — | (1,182 | ) | |||||||||||
Proceeds from public offerings | 1,925,923 | — | 125,580 | — | 2,051,503 | ||||||||||||||
Distribution from subsidiary | 55,250 | — | — | (55,250 | ) | — | |||||||||||||
Exercise of stock options | 498 | — | — | — | 498 | ||||||||||||||
Distribution to non-controlling interest | — | — | (64,824 | ) | 55,250 | (9,574 | ) | ||||||||||||
Intercompany transfers | (11,000 | ) | 11,000 | — | — | — | |||||||||||||
Net cash provided by (used in) financing activities | 2,479,025 | (172 | ) | 145,768 | — | 2,624,621 | |||||||||||||
Net increase (decrease) in cash and cash equivalents | 1,643,078 | (5,293 | ) | 8,674 | — | 1,646,459 | |||||||||||||
Cash and cash equivalents at beginning of period | 148 | 19,428 | 539 | — | 20,115 | ||||||||||||||
Cash and cash equivalents at end of period | $ | 1,643,226 | $ | 14,135 | $ | 9,213 | $ | — | $ | 1,666,574 |
Condensed Consolidated Statement of Cash Flows | |||||||||||||||||||
Year Ended December 31, 2015 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Non– | |||||||||||||||||||
Guarantor | Guarantor | ||||||||||||||||||
Parent | Subsidiaries | Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Net cash provided by (used in) operating activities | $ | (37,597 | ) | $ | 390,266 | $ | 63,832 | $ | — | $ | 416,501 | ||||||||
Cash flows from investing activities: | |||||||||||||||||||
Additions to oil and natural gas properties | — | (419,512 | ) | — | — | (419,512 | ) | ||||||||||||
Purchase of other property, equipment and land | — | (1,213 | ) | — | — | (1,213 | ) | ||||||||||||
Acquisition of leasehold interests | — | (437,455 | ) | — | — | (437,455 | ) | ||||||||||||
Acquisition of royalty interests | — | — | (43,907 | ) | — | (43,907 | ) | ||||||||||||
Proceeds from sale of assets | — | 9,739 | — | — | 9,739 | ||||||||||||||
Equity investments | — | (2,702 | ) | — | — | (2,702 | ) | ||||||||||||
Intercompany transfers | (145,023 | ) | 145,023 | — | — | — | |||||||||||||
Net cash used in investing activities | (145,023 | ) | (706,120 | ) | (43,907 | ) | — | (895,050 | ) | ||||||||||
Cash flows from financing activities: | |||||||||||||||||||
Proceeds from borrowing on credit facility | — | 390,501 | 34,500 | — | 425,001 | ||||||||||||||
Repayment on credit facility | — | (603,001 | ) | — | — | (603,001 | ) | ||||||||||||
Debt issuance costs | — | (85 | ) | (441 | ) | — | (526 | ) | |||||||||||
Public offering costs | (586 | ) | — | — | — | (586 | ) | ||||||||||||
Proceeds from public offerings | 650,688 | — | — | — | 650,688 | ||||||||||||||
Distribution from subsidiary | 60,587 | — | — | (60,587 | ) | — | |||||||||||||
Exercise of stock options | 4,873 | — | — | — | 4,873 | ||||||||||||||
Distribution to non-controlling interest | — | — | (68,555 | ) | 60,587 | (7,968 | ) | ||||||||||||
Intercompany transfers | (532,800 | ) | 532,800 | — | — | — | |||||||||||||
Net cash provided by (used in) financing activities | 182,762 | 320,215 | (34,496 | ) | — | 468,481 | |||||||||||||
Net increase (decrease) in cash and cash equivalents | 142 | 4,361 | (14,571 | ) | — | (10,068 | ) | ||||||||||||
Cash and cash equivalents at beginning of period | 6 | 15,067 | 15,110 | — | 30,183 | ||||||||||||||
Cash and cash equivalents at end of period | $ | 148 | $ | 19,428 | $ | 539 | $ | — | $ | 20,115 |
December 31, | |||||||
2017 | 2016 | ||||||
(In thousands) | |||||||
Oil and Natural Gas Properties: | |||||||
Proved properties | $ | 5,126,829 | $ | 3,429,742 | |||
Unproved properties | 4,105,865 | 1,730,519 | |||||
Total oil and natural gas properties | 9,232,694 | 5,160,261 | |||||
Accumulated depreciation, depletion, amortization | (1,009,893 | ) | (687,685 | ) | |||
Accumulated impairment | (1,143,498 | ) | (1,143,498 | ) | |||
Net oil and natural gas properties capitalized | $ | 7,079,303 | $ | 3,329,078 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(In thousands) | |||||||||||
Acquisition costs | |||||||||||
Proved properties | $ | 452,661 | $ | 72,044 | $ | 64,340 | |||||
Unproved properties | 2,692,000 | 752,117 | 448,638 | ||||||||
Development costs | 145,362 | 47,575 | 42,749 | ||||||||
Exploration costs | 779,728 | 329,122 | 319,102 | ||||||||
Capitalized asset retirement costs | 2,682 | 4,030 | 3,458 | ||||||||
Total | $ | 4,072,433 | $ | 1,204,888 | $ | 878,287 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(In thousands) | |||||||||||
Oil, natural gas and natural gas liquid sales | $ | 1,186,275 | $ | 527,107 | $ | 446,733 | |||||
Lease operating expenses | (126,524 | ) | (82,428 | ) | (82,625 | ) | |||||
Production and ad valorem taxes | (73,505 | ) | (34,456 | ) | (32,990 | ) | |||||
Gathering and transportation | (12,834 | ) | (11,606 | ) | (6,091 | ) | |||||
Depreciation, depletion, and amortization | (321,870 | ) | (176,369 | ) | (216,056 | ) | |||||
Impairment | — | (245,536 | ) | (814,798 | ) | ||||||
Asset retirement obligation accretion expense | (1,391 | ) | (1,064 | ) | (833 | ) | |||||
Income tax benefit (expense) | 19,568 | (192 | ) | 201,310 | |||||||
Results of operations | $ | 669,719 | $ | (24,544 | ) | $ | (505,350 | ) |
Oil (MBbls) | Natural Gas Liquids (MBbls) | Natural Gas (MMcf) | ||||||
Proved Developed and Undeveloped Reserves: | ||||||||
As of January 1, 2015 | 75,690 | 18,542 | 111,605 | |||||
Extensions and discoveries | 48,725 | 12,056 | 53,453 | |||||
Revisions of previous estimates | (12,130 | ) | (4,081 | ) | (14,726 | ) | ||
Purchase of reserves in place | 2,775 | 1,165 | 7,102 | |||||
Production | (9,081 | ) | (1,678 | ) | (7,931 | ) | ||
As of December 31, 2015 | 105,979 | 26,004 | 149,503 | |||||
Extensions and discoveries | 55,069 | 13,962 | 64,758 | |||||
Revisions of previous estimates | (12,483 | ) | (1,888 | ) | (34,519 | ) | ||
Purchase of reserves in place | 2,537 | 1,455 | 7,567 | |||||
Divestitures | (366 | ) | — | (1,985 | ) | |||
Production | (11,562 | ) | (2,399 | ) | (10,428 | ) | ||
As of December 31, 2016 | 139,174 | 37,134 | 174,896 | |||||
Extensions and discoveries | 99,980 | 20,825 | 109,032 | |||||
Revisions of previous estimates | (7,715 | ) | (1,466 | ) | (10,065 | ) | ||
Purchase of reserves in place | 24,322 | 2,633 | 34,640 | |||||
Divestitures | (1,163 | ) | (461 | ) | (2,474 | ) | ||
Production | (21,417 | ) | (4,056 | ) | (20,660 | ) | ||
As of December 31, 2017 | 233,181 | 54,609 | 285,369 | |||||
Proved Developed Reserves: | ||||||||
January 1, 2015 | 43,886 | 11,221 | 68,264 | |||||
December 31, 2015 | 60,569 | 15,418 | 96,871 | |||||
December 31, 2016 | 79,457 | 22,080 | 105,399 | |||||
December 31, 2017 | 141,246 | 35,412 | 190,740 | |||||
Proved Undeveloped Reserves: | ||||||||
January 1, 2015 | 31,804 | 7,321 | 43,341 | |||||
December 31, 2015 | 45,409 | 10,586 | 52,632 | |||||
December 31, 2016 | 59,717 | 15,054 | 69,497 | |||||
December 31, 2017 | 91,935 | 19,198 | 94,629 |
(MBOE) | ||
Beginning proved undeveloped reserves at December 31, 2016 | 86,354 | |
Undeveloped reserves transferred to developed | (31,666 | ) |
Revisions | (4,710 | ) |
Net purchases | 6,246 | |
Extensions and discoveries | 70,680 | |
Ending proved undeveloped reserves at December 31, 2017 | 126,904 |
December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(In thousands) | |||||||||||
Future cash inflows | $ | 12,921,897 | $ | 6,275,705 | $ | 5,377,783 | |||||
Future development costs | (1,123,979 | ) | (617,636 | ) | (548,239 | ) | |||||
Future production costs | (2,994,877 | ) | (1,392,852 | ) | (1,279,101 | ) | |||||
Future production taxes | (928,891 | ) | (459,244 | ) | (363,129 | ) | |||||
Future income tax expenses | (83,961 | ) | (75,595 | ) | (28,233 | ) | |||||
Future net cash flows | 7,790,189 | 3,730,378 | 3,159,081 | ||||||||
10% discount to reflect timing of cash flows | (4,033,130 | ) | (2,018,965 | ) | (1,740,948 | ) | |||||
Standardized measure of discounted future net cash flows | $ | 3,757,059 | $ | 1,711,413 | $ | 1,418,133 |
December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
Unweighted Arithmetic Average | |||||||||||
First-Day-of-the-Month Prices | |||||||||||
Oil (per Bbl) | $ | 48.03 | $ | 39.94 | $ | 45.07 | |||||
Natural gas (per Mcf) | $ | 2.06 | $ | 1.36 | $ | 1.83 | |||||
Natural gas liquids (per Bbl) | $ | 20.79 | $ | 12.91 | $ | 12.56 |
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(In thousands) | |||||||||||
Standardized measure of discounted future net cash flows at the beginning of the period | $ | 1,711,413 | $ | 1,418,133 | $ | 2,045,224 | |||||
Sales of oil and natural gas, net of production costs | (986,246 | ) | (411,558 | ) | (331,119 | ) | |||||
Acquisition of reserves | 439,396 | 43,142 | 58,849 | ||||||||
Divestiture of reserves | (11,072 | ) | (5,481 | ) | (1,490 | ) | |||||
Extensions and discoveries, net of future development costs | 1,791,686 | 779,359 | 629,149 | ||||||||
Previously estimated development costs incurred during the period | 190,121 | 85,696 | 129,901 | ||||||||
Net changes in prices and production costs | 577,781 | (150,509 | ) | (1,383,698 | ) | ||||||
Changes in estimated future development costs | (52,908 | ) | 20,647 | 38,638 | |||||||
Revisions of previous quantity estimates | (98,857 | ) | (123,795 | ) | (377,160 | ) | |||||
Accretion of discount | 174,185 | 143,134 | 236,716 | ||||||||
Net change in income taxes | (9,074 | ) | (30,530 | ) | 268,963 | ||||||
Net changes in timing of production and other | 30,634 | (56,825 | ) | 104,160 | |||||||
Standardized measure of discounted future net cash flows at the end of the period | $ | 3,757,059 | $ | 1,711,413 | $ | 1,418,133 |
2017 | |||||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
Revenues | $ | 235,230 | $ | 269,434 | $ | 301,253 | $ | 399,194 | |||||||
Income from operations | 116,410 | 132,308 | 142,639 | 213,663 | |||||||||||
Income tax expense (benefit) | 1,957 | 1,579 | 857 | (23,961 | ) | ||||||||||
Net income | 141,074 | 164,128 | 81,948 | 129,607 | |||||||||||
Net income attributable to non-controlling interest | 4,801 | 5,723 | 8,924 | 15,048 | |||||||||||
Net income attributable to Diamondback Energy, Inc. | $ | 136,273 | $ | 158,405 | $ | 73,024 | $ | 114,559 | |||||||
Earnings per common share | |||||||||||||||
Basic | $ | 1.46 | $ | 1.61 | $ | 0.74 | $ | 1.17 | |||||||
Diluted | $ | 1.46 | $ | 1.61 | $ | 0.74 | $ | 1.16 | |||||||
2016 | |||||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
Revenues | $ | 87,481 | $ | 112,483 | $ | 142,131 | $ | 185,012 | |||||||
Income (loss) from operations | (27,603 | ) | (134,786 | ) | 6,693 | 87,079 | |||||||||
Income tax expense (benefit) | — | 368 | — | (176 | ) | ||||||||||
Net income (loss) | (35,627 | ) | (157,121 | ) | (600 | ) | 28,440 | ||||||||
Net income (loss) attributable to non-controlling interest | (2,715 | ) | (1,631 | ) | 1,630 | 2,842 | |||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | $ | (32,912 | ) | $ | (155,490 | ) | $ | (2,230 | ) | $ | 25,598 | ||||
Earnings per common share | |||||||||||||||
Basic | $ | (0.46 | ) | $ | (2.17 | ) | $ | (0.03 | ) | $ | 0.32 | ||||
Diluted | $ | (0.46 | ) | $ | (2.17 | ) | $ | (0.03 | ) | $ | 0.32 |
Name of Subsidiary | Jurisdiction of Incorporation |
Diamondback E&P LLC | Delaware |
Diamondback O&G LLC | Delaware |
Rattler Midstream LLC | Delaware |
Viper Energy Partners GP | Delaware |
Viper Energy Partners LP | Delaware |
Viper Energy Partners LLC | Delaware |
/s/ Ryder Scott Company, L.P. | ||||
RYDER SCOTT COMPANY, L.P. | ||||
TBPE Firm Registration No. F-1580 |
/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 Diamondback Energy, Inc. |
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 14, 2018 | /s/ Travis D. Stice | |
Travis D. Stice | |||
Chief Executive Officer |
1. | I have reviewed this Annual Report on Form 10-K of Diamondback Energy, Inc. |
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 14, 2018 | /s/ Teresa L. Dick | |
Teresa L. Dick | |||
Chief Financial Officer |
Date: | February 14, 2018 | /s/ Travis D. Stice | |
Travis D. Stice | |||
Chief Executive Officer |
Date: | February 14, 2018 | /s/ Teresa L. Dick | |
Teresa L. Dick | |||
Chief Financial Officer |
\s\ Val Rick Robinson |
Val Rick Robinson, P.E. |
TBPE License No. 105137 |
Managing Senior Vice President |
As of December 31, 2017 |
Proved | ||||||||||||
Developed | Total | |||||||||||
Producing | Non-Producing | Proved | ||||||||||
Net Remaining Reserves | ||||||||||||
Oil/Condensate – MBbl | 122,458 | 84,838 | 207,296 | |||||||||
Plant Products – MBbl | 30,875 | 17,439 | 48,314 | |||||||||
Gas – MMCF | 161,484 | 87,490 | 248,974 | |||||||||
MBOE | 180,247 | 116,859 | 297,106 | |||||||||
Income Data ($M) | ||||||||||||
Future Gross Revenue | $6,520,998 | $4,382,901 | $10,903,899 | |||||||||
Deductions | 2,230,752 | 2,119,316 | 4,350,068 | |||||||||
Future Net Income (FNI) | $4,290,246 | $2,263,585 | $6,553,831 | |||||||||
Discounted FNI @ 10% | $2,329,892 | $838,029 | $3,167,921 |
Discounted Future Net Income (M$) | ||||
As of December 31, 2017 | ||||
Discount Rate | Total | |||
Percent | Proved | |||
5 | $4,262,105 | |||
15 | $2,536,634 | |||
20 | $2,125,329 | |||
30 | $1,618,661 |
Geographic Area | Product | Price Reference | Average Benchmark Prices | Average Proved Realized Prices |
North America | ||||
United States | Oil/Condensate | WTI Cushing | $51.34/Bbl | $48.00/Bbl |
NGLs | Propane, Mt. Belvieu | $31.82/Bbl | $21.01/Bbl | |
Gas | Henry Hub | $2.98/MMBTU | $2.05/MCF |
(1) | completion intervals which are open at the time of the estimate, but which have not started producing; |
(2) | wells which were shut-in for market conditions or pipeline connections; or |
(3) | wells not capable of production for mechanical reasons. |
(i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
\s\ Val Rick Robinson |
Val Rick Robinson, P.E. |
TBPE License No. 105137 |
Managing Senior Vice President |
As of December 31, 2017 |
Proved | ||||||||||||
Developed | Total | |||||||||||
Producing | Undeveloped | Proved | ||||||||||
Net Remaining Reserves | ||||||||||||
Oil/Condensate – MBbl | 18,788 | 7,097 | 25,885 | |||||||||
Plant Products – MBbl | 4,536 | 1,759 | 6,295 | |||||||||
Gas – MMCF | 29,256 | 7,139 | 36,395 | |||||||||
MBOE | 28,200 | 10,046 | 38,246 | |||||||||
Income Data ($M) | ||||||||||||
Future Gross Revenue | $ | 1,004,913 | $ | 368,717 | $ | 1,373,630 | ||||||
Deductions | 38,220 | 15,091 | 53,311 | |||||||||
Future Net Income (FNI) | $ | 966,693 | $ | 353,626 | $ | 1,320,319 | ||||||
Discounted FNI @ 10% | $ | 456,837 | $ | 171,829 | $ | 628,666 |
Discounted Future Net Income ($M) | ||||
As of December 31, 2017 | ||||
Discount Rate | Total | |||
Percent | Proved | |||
5 | $834,824 | |||
15 | $515,654 | |||
20 | $443,507 | |||
30 | $355,098 |
Geographic Area | Product | Price Reference | Average Benchmark Prices | Average Proved Realized Prices |
North America | ||||
United States | Oil/Condensate | WTI Cushing | $51.34/Bbl | $48.21/Bbl |
NGLs | Propane, Mt. Belvieu | $31.82/Bbl | $19.15/Bbl | |
Gas | Henry Hub | $2.98/MMBTU | $2.13/MCF |
(1) | completion intervals which are open at the time of the estimate, but which have not started producing; |
(2) | wells which were shut-in for market conditions or pipeline connections; or |
(3) | wells not capable of production for mechanical reasons. |
(i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
Document and Entity Information - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Feb. 07, 2018 |
Jun. 30, 2017 |
|
Document and Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2017 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Diamondback Energy, Inc. | ||
Entity Central Index Key | 0001539838 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 98,167,289 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 7,801,460,276 |
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Statement of Financial Position [Abstract] | ||
Oil and natural gas properties, full cost method of accounting amount excluded from amortization | $ 4,105,865 | $ 1,730,519 |
Common Stock, Par Value (in dollars per share) | $ 0.01 | $ 0.01 |
Common Stock, Shares, Authorized | 200,000,000 | 100,000,000 |
Common Stock, Shares, Issued | 98,167,289 | 90,143,934 |
Common Stock, Shares, Outstanding | 98,167,289 | 90,143,934 |
Consolidated Statements of Operations (Parentheticals) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
General and Administrative Expense [Member] | |||
Non-cash stock based compensation, net of capitalized amount | $ 25,537 | $ 26,453 | $ 18,529 |
Description of the Business and Basis of Presentation |
12 Months Ended |
---|---|
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of the Business and Basis of Presentation | DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION Organization and Description of the Business Diamondback Energy, Inc. (“Diamondback” or the “Company”) is an independent oil and gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011. On June 17, 2014, Diamondback entered into a contribution agreement with Viper Energy Partners LP (the “Partnership”), Viper Energy Partners GP LLC (the “General Partner”) and Viper Energy Partners LLC to transfer Diamondback’s ownership interest in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. Diamondback also owns and controls the General Partner, which holds a non-economic general partner interest in the Partnership. On June 23, 2014, the Partnership completed its initial public offering (the “Viper Offering”) of 5,750,000 common units, and the Company’s common units represented an approximate 92% limited partner interest in the Partnership. On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. At the completion of this offering, the Company owned approximately 88% of the common units of the Partnership. See Note 4–Viper Energy Partners LP for additional information regarding the Partnership. The wholly-owned subsidiaries of Diamondback, as of December 31, 2017, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, and Rattler Midstream LLC (formerly known as White Fang Energy LLC), a Delaware limited liability company. The consolidated subsidiaries include the wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership, and Viper Energy Partners LLC, a Delaware limited liability company. Basis of Presentation The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation. The Partnership is consolidated in the financial statements of the Company. As of December 31, 2017, the Company owned approximately 64% of the common units of the Partnership and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the General Partner of the Partnership. |
Summary of Significant Accounting Policies |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes. Cash and Cash Equivalents The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. Restricted Cash In 2014, a subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The subsidiary subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. The parties reached a settlement of this matter in April 2017 and the funds were distributed in accordance with the terms of the settlement. Pending such distribution, these funds were classified as restricted cash. Accounts Receivable Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2017 or December 31, 2016. Derivative Instruments The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives and senior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 14–Fair Value Measurements). Oil and Natural Gas Properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 7–Equity Method Investments). Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $11.11, $11.23 and $17.84 for the years ended December 31, 2017, 2016 and 2015, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $321.9 million, $176.4 million and $216.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. During the years ended December 31, 2016 and 2015, the Company recorded impairments on proved oil and natural gas properties of $245.5 million and $814.8 million, respectively. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. Other Property, Equipment and Land Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. Depreciation expense for other property and equipment was $1.4 million for each of the years ended December 31, 2017, 2016 and 2015. Asset Retirement Obligations The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties. Impairment of Long-Lived Assets Other property and equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the years ended December 31, 2017, 2016 and 2015, respectively. Capitalized Interest The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. The Company capitalized interest of $22.1 million for the year ended December 31, 2017. The Company did not have any capitalized interest for the years ended December 31, 2016 and 2015. Inventories Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2017 and 2016. The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2017, the Company estimated that all of its tubular goods and equipment will be utilized within one year. Debt Issuance Costs Other assets included capitalized costs related to the credit facility of $16.7 million and $8.2 million, net of accumulated amortization of $7.0 million and $4.9 million, as of December 31, 2017 and 2016, respectively. Long-term debt included capitalized costs related to the senior notes of $15.2 million and $14.8 million, net of accumulated amortization of $2.0 million and $0.2 million, as of December 31, 2017 and 2016, respectively. The costs associated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior notes using the effective interest method. The costs associated with the Company’s credit facility that are included in other assets are being amortized over the term of the facility. Other Accrued Liabilities Other accrued liabilities consist of the following:
Revenue and Royalties Payable For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties. Revenue Recognition Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of December 31, 2017 or December 31, 2016. Revenues from oil and natural gas services are recognized when services are provided. Investments Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2017, 2016 and 2015. For additional information on the Company’s investments, see Note 7–Equity Method Investments. Accounting for Equity-Based Compensation The Company grants various types of stock-based awards including stock options and restricted stock units. The Partnership grants various unit-based awards including unit options and phantom units to employees, officers and directors of the General Partner and the Company who perform services for the Partnership. These plans and related accounting policies are defined and described more fully in Note 10–Equity-Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. Concentrations The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2017, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. Environmental Compliance and Remediation Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated. Income Taxes Diamondback uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Company is subject to margin tax in the state of Texas. During the years ended December 31, 2017, 2016 and 2015, the Company had no margin tax expense. The Company’s 2013, 2014, 2015, 2016 and 2017 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2017 and December 31, 2016, the Company had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2017, 2016 and 2015, there was no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements. Recent Accounting Pronouncements Recently Issued Pronouncements In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The Company will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company has reviewed various contracts that represent its material revenue streams and determined that there will be no impact to its financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, the Company will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, the Company will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Company. The Company does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams as compared to existing GAAP. In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment. In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company will adopt this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements. In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company will adopt this update retrospectively effective January 1, 2018. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements. In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard. In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses. |
Acquisitions |
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Business Combinations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Acquisitions | ACQUISITIONS 2017 Activity On February 28, 2017, the Company completed its acquisition of certain oil and natural gas properties, midstream assets and other related assets in the Delaware Basin for an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of the Company’s common stock, of which approximately 1.15 million shares were placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. The Company used the net proceeds from its December 2016 equity offering, net proceeds from its December 2016 debt offering, cash on hand and other financing sources to fund the cash portion of the purchase price for this acquisition. The following represents the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5 billion, resulting in no goodwill or bargain purchase gain.
The Company has included in its consolidated statements of operations revenues of $81.4 million and direct operating expenses of $23.5 million for the period from February 28, 2017 to December 31, 2017 due to the acquisition. Pro Forma Financial Information The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the year ended December 31, 2017 and 2016 have been prepared to give effect to the February 28, 2017 acquisition as if it had occurred on January 1, 2016. The pro forma data are not necessarily indicative of the financial results that would have been attained had the acquisitions occurred on January 1, 2016. The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.
2016 Activity On September 1, 2016, the Company acquired from an unrelated third party leasehold interests and related assets in the Southern Delaware Basin for an aggregate purchase price of $558.5 million. This transaction included approximately 26,797 gross (19,262 net) acres primarily in Reeves and Ward counties. The Company financed this acquisition with net proceeds from the July 2016 equity offering discussed in Note 9 and cash on hand. 2015 Activity During 2015, the Company completed acquisitions from unrelated third party sellers of an aggregate of approximately 16,940 gross (12,672 net) acres in the Midland Basin, primarily in northwest Howard County, for an aggregate purchase price of approximately $437.5 million. The acquisitions were accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. These acquisitions were funded with the net proceeds of the May 2015 equity offering discussed in Note 9–Capital Stock and Earnings Per Share and borrowings under the Company’s revolving credit facility discussed in Note 8–Debt. On July 9, 2015, the Company completed the sale of an approximate average 1.5% overriding royalty interest in certain of its acreage primarily located in Howard County, Texas to the Partnership for $31.1 million. The Partnership primarily funded this acquisition with borrowings under its revolving credit facility discussed in Note 8 – Debt. |
Property and Equipment |
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Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property and Equipment | PROPERTY AND EQUIPMENT Property and equipment includes the following:
The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs were approximately $22.0 million $17.2 million and $15.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any acreage expire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. As a result of the significant decline in prices during 2016, the Company recorded non-cash ceiling test impairments for the years ended December 31, 2016 and 2015 of $245.5 million and $814.8 million, respectively, which are included in accumulated depletion. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017. For 2016 and 2015, the impairment charges affected the Company’s reported net income but did not reduce its cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods. At December 31, 2017, there was $26.0 million in exploration costs and development costs and $22.1 million in capitalized interest that are not subject to depletion. At December 31, 2016, there were no exploration costs, development costs or capitalized interest that are not subject to depletion. |
Viper Energy Partners LP |
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Noncontrolling Interest [Abstract] | |
Viper Energy Partners LP | VIPER ENERGY PARTNERS LP The Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Market under the symbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin. Viper Energy Partners GP LLC, a consolidated subsidiary of Diamondback, serves as the general partner of, and holds a non-economic general partner interest in, the Partnership. As of December 31, 2017, the Company owned approximately 64% of the common units of the Partnership. Prior to the completion on June 23, 2014 of the Viper Offering, Diamondback owned all of the general and limited partner interests in the Partnership. The Viper Offering consisted of 5,750,000 common units representing approximately 8% of the limited partner interests in the Partnership at a price to the public of $26.00 per common unit. In connection with the Viper Offering, Diamondback contributed all of the membership interests in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. The contribution of Viper Energy Partners LLC to the Partnership was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. During the year ended December 31, 2017, the Partnership distributed $89.5 million to Diamondback in respect of its common units. In August 2016, the Partnership completed an underwritten public offering of 8,050,000 common units, which included 1,050,000 common units issued pursuant to an option to purchase additional common units granted to the underwriter. In this offering, Diamondback purchased 2,000,000 common units from the underwriter at $15.60 per unit, which is the price per common unit paid by the underwriter to the Partnership. Following the August 2016 public offering, Diamondback had an approximate 83% limited partner interest in the Partnership. The Partnership received net proceeds from this offering of approximately $125.0 million, after deducting underwriting discounts and commissions and estimated offering expenses, which it used to fund an acquisition and repaid outstanding borrowings under its revolving credit facility. In January 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions. In July 2017, the Partnership completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, we purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of the Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, the Company had an approximate 64% limited partner interest in the Partnership. The Partnership received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $152.8 million to repay all of the then-outstanding borrowings under the Partnership’s revolving credit facility and the balance was used fund a portion of the purchase price for acquisitions and for general partnership purposes. As a result of these public offerings and the Partnership’s issuance of unit-based compensation, the Company’s ownership percentage in the Partnership was reduced. During the year ended December 31, 2017, the Company recorded a $362.4 million decrease to Non-controlling interest in the Partnership with an increase to Additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value in the Partnership before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet. Partnership Agreement In connection with the closing of the Viper Offering, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated as of June 23, 2014 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. Tax Sharing In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. Other Agreements See Note 11–Related Party Transactions for information regarding the advisory services agreement the Partnership and the General Partner entered into with Wexford Capital LP (“Wexford”). The Partnership has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 8–Debt for a description of this credit facility. |
Asset Retirement Obligations |
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Asset Retirement Obligation [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS The following table describes the changes to the Company’s asset retirement obligations liability for the following periods:
The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance. |
Equity Method Investments |
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Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | EQUITY METHOD INVESTMENTS In October 2014, the Company obtained a 25% interest in HMW Fluid Management LLC, which was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas. The board of this entity may also authorize the entity to offer these services to other counties in the Permian Basin and to pursue other business opportunities. During the year ended December 31, 2017, the Company invested $0.2 million in this entity and recorded income of $0.7 million, which was the Company’s share of HMW Fluid Management LLC’s net income, bringing the Company’s total investment to $7.2 million at December 31, 2017. During the year ended December 31, 2016, the Company invested $2.3 million in this entity and recorded income of $0.7 million, which was the Company’s share of HMW Fluid Management LLC’s net income, bringing its total investment to $6.3 million at December 31, 2016. The Company will retain a minority interest after all commitments are received. The entity was formed as a limited liability company and maintains a specific ownership account for each investor, similar to a partnership capital account structure. The Company accounts for this investment under the equity method of accounting. |
Debt |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt | DEBT Long-term debt consisted of the following as of the dates indicated:
2024 Senior Notes On October 28, 2016, the Company issued $500.0 million in aggregate principal amount of 4.750% Senior Notes due 2024 (the “2024 Senior Notes”). The 2024 Senior Notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2024 Senior Notes, provided, however, that the 2024 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries. See also “Note 16. Subsequent Events–New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility.” The 2024 Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented (the “2024 Indenture”). The 2024 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. The Company may on any one or more occasions redeem some or all of the 2024 Senior Notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, the Company may on any one or more occasions redeem all or a portion of the 2024 Senior Notes at a price equal to 100% of the principal amount of the 2024 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, the Company may on any one or more occasions redeem the 2024 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 Senior Notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings. 2025 Senior Notes On December 20, 2016, the Company issued $500.0 million in aggregate principal amount of 5.375% Senior Notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year, commencing on May 31, 2017 and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2025 Senior Notes, provided, however, that the 2025 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries. The 2025 Senior Notes were issued under an indenture, dated as of December 20, 2016, among the Company, the guarantors party thereto and Wells Fargo Bank, as the trustee (the “2025 Indenture”). The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. The Company may on any one or more occasions redeem some or all of the 2025 Senior Notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or more occasions redeem all or a portion of the 2025 Senior Notes at a price equal to 100% of the principal amount of the 2025 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem the 2025 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 Senior Notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings. As required under the terms of the registration rights agreements relating to the 2024 Senior Notes and the 2025 Senior Notes, on April 26, 2017, the Company filed with the SEC a Registration Statement on Form S-4 (the “Registration Statement”) relating to the exchange offers of the 2024 Senior Notes and the 2025 Senior Notes for substantially identical notes registered under the Securities Act (the “Exchange Offers”). The Registration Statement was declared effective by the SEC on June 21, 2017 and the Exchange Offers closed on July 27, 2017, in which all of the privately placed 2024 Senior Notes and 2025 Senior Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act. The Company’s Credit Facility The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended on June 9, 2014, November 13, 2014, June 21, 2016, December 15, 2016 and November 28, 2017, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, the Company may request up to two additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $1.8 billion, the Company had elected a commitment amount of $1.0 billion and the Company had $397.0 million of outstanding borrowings under the revolving credit facility. See “Note 16. Subsequent Events-New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility.” Diamondback O&G LLC is the borrower under the credit agreement. As of December 31, 2017, the credit agreement is guaranteed by the Company, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of the Company’s future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of the assets of the Company, Diamondback O&G LLC and the guarantors. The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Company that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternate base rate and from 1.25% to 2.25% in the case of LIBOR, each of which applicable margin rates is increased by 0.25% per annum if the total debt to EBITDAX ratio is greater than 3.0 to 1.0. The applicable margin depends on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance. As of December 31, 2017 and 2016, the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. The Partnership’s Credit Agreement On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, as sole book runner and lead arranger. The credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”) of $400.0 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $400.0 million, and the Partnership had $93.5 million of outstanding borrowings and $306.5 million available for future borrowings under its revolving credit facility. The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Partnership that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the Partnership and its subsidiary’s assets. The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. The lenders may accelerate all of the indebtedness under the Partnership’s credit agreement upon the occurrence and during the continuance of any event of default. The Partnership’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. Interest expense The following amounts have been incurred and charged to interest expense for the years ended December 31, 2017, 2016 and 2015:
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Capital Stock and Earnings Per Share |
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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capital Stock and Earnings Per Share | CAPITAL STOCK AND EARNINGS PER SHARE Diamondback completed the following equity offerings during the years ended December 31, 2017, 2016 and 2015:
Earnings Per Share The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of the Partnership are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
For the years ended December 31, 2017, 2016 and 2015, there were 45,690 shares, 243,654 shares and 100,924 shares, respectively, that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per share in future periods. |
Equity-Based Compensation |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock and Unit Based Compensation | EQUITY-BASED COMPENSATION On October 10, 2012, the Board of Directors approved the Diamondback Energy, Inc. 2012 Equity Incentive Plan (the “2012 Plan”), which is intended to provide eligible employees with equity-based incentives. The 2012 Plan provides for the granting of incentive stock options, nonstatutory stock options, restricted awards (restricted stock and restricted stock units), performance awards, and stock appreciation rights, or any combination of the foregoing. A total of 2,500,000 shares of the Company’s common stock has been reserved for issuance pursuant to this plan. The following table presents the effects of the equity and stock based compensation plans and related costs:
On June 17, 2014, in connection with the Viper Offering, the Board of Directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“Viper LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The Viper LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of 9,070,356 common units has been reserved for issuance pursuant to the Viper LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The Viper LTIP is administered by the Board of Directors of the General Partner or a committee thereof. Stock Options In accordance with the 2012 Plan, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. The shares issued under the 2012 Plan will consist of new shares of Company stock. Unless otherwise specified in an agreement, options become exercisable ratably over a five-year period. However, as described above, options associated with the modification vest in four substantially equal annual installments and are exercisable for five years from the date of grant. The fair value of the stock options on the date of grant is expensed over the applicable vesting period. The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company does not have a long history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards and remaining vesting term at the modification date. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero. All such amounts represent the weighted-average amounts for each year. The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the year ended December 31, 2017.
The aggregate intrinsic value of stock options that were exercised during the years ended December 31, 2016 and 2015 was $1.3 million and $15.7 million, respectively. Restricted Stock Units Under the 2012 Plan, approved by the Board of Directors, the Company is authorized to issue restricted stock and restricted stock units to eligible employees. The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents the Company’s restricted stock units activity under the 2012 Plan during the year ended December 31, 2017.
The aggregate fair value of restricted stock units that vested during the year ended December 31, 2017, 2016 and 2015 was $14.8 million, $12.5 million and $10.1 million, respectively. As of December 31, 2017, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $14.4 million. Such cost is expected to be recognized over a weighted-average period of 1.5 years. Performance-Based Restricted Stock Units To provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three-year performance period. In February 2015, eligible employees received performance restricted stock unit awards totaling 90,249 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2014 to December 31, 2016 and vested at December 31, 2016. In February 2016, eligible employees received performance restricted stock unit awards totaling 174,325 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2017 and vested at December 31, 2017. Eligible employees received additional performance restricted stock unit awards totaling 87,163 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2018 and cliff vest at December 31, 2018. In February 2017, eligible employees received performance restricted stock unit awards totaling 37,440 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2017 to December 31, 2018 and cliff vest at December 31, 2018. Eligible employees received additional performance restricted stock unit awards totaling 74,880 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2017 to December 31, 2019 and cliff vest at December 31, 2019. The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period. The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions.
The following table presents the Company’s performance restricted stock unit activity under the 2012 Plan for the year ended December 31, 2017.
As of December 31, 2017, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $15.6 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years. Partnership Unit Options In accordance with the Viper LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the Viper LTIP will consist of new common units of the Partnership. On June 17, 2014, the Board of Directors of the General Partner granted 2,500,000 unit options to the executive officers of the General Partner. The unit options vest approximately 33% ratably on each of the first three anniversaries of the date of grant or earlier upon a change of control (as defined in the Viper LTIP). All outstanding unit options were amended effective November 29, 2016 to provide that vested unit options will become exercisable upon the earlier to occur of (i) the “Exercise Window Period” beginning on the third anniversary of the date of grant and ending on December 31, 2017, or (ii) the “Change of Control Exercise Period” beginning ten days before and ending on the date a change of control occurs (the earlier occurring of such events, the “Exercise Period”). At any time within the Exercise Period, if a participant attempts to exercise a vested unit option and the fair market value per unit as of such date is less than the exercise price per option unit, the vested unit option will not be exercisable. At the end of the Exercise Period, any vested unit option that is not exercisable or that has not been exercised will automatically terminate and become null and void. The fair value of the unit options on the date of grant is expensed over the applicable vesting period. The Partnership estimates the fair values of unit options granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant the Partnership did not have a history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership.
The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 2017.
Phantom Units Under the Viper LTIP, the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient one common unit of the Partnership for each phantom unit. The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2017.
The aggregate fair value of phantom units that vested during the year ended December 31, 2017 was $0.5 million. As of December 31, 2017, the unrecognized compensation cost related to unvested phantom units was $1.3 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years. |
Related Party Transactions |
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Related Party Transactions [Abstract] | ||||||||||||||||||||||
Related Party Transactions | RELATED PARTY TRANSACTIONS Immediately upon the completion of the Company’s initial public offering on October 17, 2012, Wexford beneficially owned approximately 44% of the Company’s outstanding common stock. As of December 31, 2016, Wexford beneficially owned less than 1% of the Company’s outstanding common stock. The Chairman of the Board of Directors of both the Company and the General Partner was a partner at Wexford until his retirement from Wexford effective December 31, 2016. Another partner at Wexford serves as a member of the Board of Directors of the General Partner. Beginning January 1, 2017, Wexford and entities affiliated with Wexford are no longer considered related parties of the Company and any expenses after December 31, 2016 are no longer classified as related party expenses. Related Party Revenue and Expenses During the year ended December 31, 2016, the Company paid $3.3 million in lease operating expenses and $2.2 million in general and administrative expenses to related parties. During the year ended December 31, 2016, the Company received $0.2 million in other income from related parties. During the year ended December 31, 2015, the Company paid $0.2 million in lease operating expenses, $0.2 million in production and ad valorem taxes, $1.0 million in gathering and transportation expenses and $2.3 million in general and administrative expenses to related parties. During the year ended December 31, 2015, the Company received $0.2 million in other income from related parties. Advisory Services Agreement - The Company The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement had an initial term of two years commencing on October 18, 2012, and continues for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Company terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’s independent directors for such services as may be provided by Wexford at the Company’s request in connection with acquisitions and divestitures, financings or other transactions in which the Company may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Company’s day-to-day business or operations. The Company has agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Company paid $0.5 million during both of the years ended December 31, 2016 and 2015 under the Advisory Services Agreement. Advisory Services Agreement - The Partnership In connection with the closing of the Viper Offering, the Partnership and the General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides the Partnership and the General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Viper Advisory Services Agreement had an initial term of two years commencing on June 23, 2014, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Partnership or the General Partner terminates such agreement, the Partnership is obligated to pay all amounts due through the remaining term. In addition, the Partnership and the General Partner have agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of the General Partner for such services as may be provided by Wexford at the Partnership’s or the General Partner’s request in connection with acquisitions and divestitures, financings or other transactions in which the Partnership may be involved. The services provided by Wexford under the Viper Advisory Services Agreement do not extend to the Partnership or the General Partner’s day-to-day business or operations. The Partnership and General Partner have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Viper Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Partnership did not pay any amounts during the years ended December 31, 2017 and 2016 under the Viper Advisory Services Agreement. The Partnership paid $0.5 million during the year ended December 31, 2015 under the Viper Advisory Services Agreement. Coronado Midstream The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC, formerly known as MidMar Gas LLC, an entity that was affiliated with Wexford, that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, Coronado Midstream LLC is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream LLC, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. An entity controlled by Wexford had owned approximately 28% equity interest in Coronado Midstream LLC until Coronado Midstream LLC was sold in March 2015. Coronado Midstream LLC is no longer a related party and any revenues, production and ad valorem taxes and gathering and transportation expense after March 2015 are not classified as those attributable to a related party. Midland Leases Effective May 15, 2011, the Company occupied corporate office space in the Fasken building in Midland, Texas under a lease with an initial term of five years. On November 10, 2014, the lease was amended to extend the term of the lease for an additional 10-year period and to increase the monthly base rent to $94,000 beginning in June 2016, with an increase of approximately 2% annually. The office space is owned by Fasken, which is an entity controlled by an affiliate of Wexford. The following table contains amendments made to lease additional office space in the Midland corporate office during the years ended December 31, 2016 and 2015:
Field Office Lease The Company leased field office space in Midland, Texas from an unrelated third party from March 1, 2011. On March 1, 2014, the building was purchased by WT Commercial Portfolio, LLC, which is controlled by an affiliate of Wexford. The term of the lease expires on February 28, 2018. The monthly base rent was $11,000 and increased 3% annually on March 1 of each year. During the third quarter of 2014, the Company entered into a sublease with Bison, in which Bison leased the field office space on the same terms as the Company’s lease for the remainder of the lease term. The Company paid rent of $0.2 million during both of the years ended December 31, 2016 and 2015. The Company received payments of $0.2 million from Bison in respect of this sublease during both of the years ended December 31, 2016 and 2015. During the second quarter of 2017, the sublease between the Company and Bison as well as the original lease between the Company and WT Commercial Portfolio, LLC were terminated. The Partnership - Lease Bonus During the year ended December 31, 2017, the Company paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre. During the year ended December 31, 2016, the Company paid the Partnership $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre. |
Income Taxes |
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Taxes | INCOME TAXES Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and the Texas margin tax. For certain reporting periods prior to the quarter ended December 31, 2017, the Company’s deferred tax assets exceeded its deferred tax liabilities. The resulting net deferred tax asset was subject to a full valuation allowance. The Company continually assesses its deferred tax assets for realizability and, as a result of such reassessment, in the quarter ended December 31, 2017 the Company determined that sufficient evidence existed to indicate that it is probable that its deferred tax assets will be realized primarily through the unfavorable reversal of deferred tax liabilities, which currently exceed the Company’s deferred tax assets. In the quarter ended December 31, 2017, the valuation allowance historically applied against the Company’s gross deferred tax assets was removed. The Company’s gross deferred tax assets were recorded based upon the 35% federal income tax rate that was in effect prior to the enactment of the Tax Cut and Jobs Act. Subsequently, but also in the quarter ended December 31, 2017, the Company’s deferred tax assets and deferred tax liabilities were revalued to reflect the federal income tax rate enacted by the Tax Cut and Jobs Act. The effects of the removal of the valuation allowance and the reduction to the federal income tax rate may both be seen in the reconciliation of our effective tax rate to the statutory rate below. The Tax Cuts and Jobs Act, a historic reform of the U.S. federal income tax statutes, was enacted on December 22, 2017. Among other significant features, the Tax Cut and Jobs Act reduces the maximum US federal corporate income tax rate from 35% to 21%, preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling costs, allows for immediate expensing of capital expenditures for tangible personal property for a period of time, modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations, and enacts new limitations regarding the deductibility of interest expense. As of the completion of the Company’s financial statements for its year ended December 31, 2017, the Company has substantially completed its accounting for the effects of the enactment of the Tax Cut and Jobs Act. With respect to those items for which the Company’s accounting is not complete, as described below, the Company has made reasonable estimates of the effects on its existing deferred tax balances. In all cases, the Company will continue to make and refine its calculations as additional analysis is completed. To account for the effects of the Tax Cut and Jobs Act, the Company remeasured its deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, which is generally a federal income tax rate of 21%. The enacted rate change resulted in a non-cash decrease of approximately $67.9 million to the Company’s income tax provision for the period ended December 31, 2017 and a corresponding reduction to the Company’s net noncurrent deferred tax liability balance as of December 31, 2017. The Company is still analyzing certain aspects of the Tax Cuts and Jobs Act, specifically the provisions related to limitations on the deductibility of certain executive compensation, including equity based compensation. The Company is refining its calculations, which could potentially affect the measurement of related deferred tax balances or potentially give rise to new deferred tax amounts. The Company does not expect that a material adjustment to its deferred tax position will result from the completion of its computations, which the Company expects to finalize by the fourth quarter of 2018. At December 31, 2017, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2014 through 2017 remain subject to examination by the major tax jurisdictions. The components of the provision for income taxes for the years ended December 31, 2017, 2016 and 2015 are as follows:
A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:
The components of the Company’s deferred tax assets and liabilities as of December 31, 2017 and 2016 are as follows:
The Company incurred a tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drilling and development costs under current law. There is no tax refund available to the Company, nor is there any current income tax payable. At December 31, 2017, the Company had approximately $357.0 million of federal NOLs expiring in 2032 through 2037. The Company principally operates in the state of Texas and is subject to Texas Margin Tax, which currently does not include an NOL carryover provision. The Company believes that Section 382 of the Internal Revenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period, will not have an adverse effect on future NOL usage. As of December 31, 2017, the Company has a remaining valuation allowance of $0.1 million for certain state NOL carryforwards which the Company does not believe are realizable as it does not anticipate future operations in those states. In the fourth quarter of 2017, the Company removed its valuation allowance against deferred tax assets for U.S. NOL carryforwards resulting in income tax benefit of $127.5 million. As discussed above, management’s assessment included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities. Management believes that the balance of the Company’s NOLs are realizable to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. As a result of management’s assessment, in the quarter ended December 31, 2017, the Company has removed its valuation allowance against its federal NOLs and other federal deferred tax assets in order to state its deferred assets and liabilities at the amount more likely than not to be realized. |
Derivatives |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives | DERIVATIVES All derivative financial instruments are recorded at fair value in the accompanying balance sheet. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.” The Company has used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its oil and natural gas sales. With respect to the Company’s fixed price swap and fixed price basis contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company has fixed price basis swaps for the spread between the WTI Midland price and the WTI Cushing price. Under the Company’s costless collar contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the put option price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the call option price. If the settlement price is between the put and the call price, there is no payment required. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing and Crude Oil Brent, and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing. By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk. As of December 31, 2017, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
Balance sheet offsetting of derivative assets and liabilities The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2017 and 2016.
The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:
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Fair Value Measurements |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities. Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s fixed price crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs. The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets.
The fair value of the revolving credit facility and the Partnership’s revolving credit facility approximates their carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the December 31, 2017 quoted market price, a Level 1 classification in the fair value hierarchy. |
Commitments and Contingencies |
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations. Lease Commitments The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2017:
The Company leases office space in Midland, Texas and in Oklahoma City, OK from unrelated third parties. The following table presents rent expense for the years ended December 31, 2017, 2016 and 2015.
Drilling contracts As of December 31, 2017, the Company had entered into drilling rig contracts with various third parties in the ordinary course of business to ensure rig availability to complete the Company’s drilling projects. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as of December 31, 2017 total approximately $32.0 million. Oil production purchase agreement On May 24, 2012, the Company entered into an oil purchase agreement with Shell Trading (US) Company, in which the Company is obligated to commence delivery of specified quantities of oil to Shell Trading (US) Company upon completion of the reversal of the Magellan Longhorn pipeline and its conversion for oil shipment, which occurred on October 1, 2013. The Company’s agreement with Shell Trading has an initial term of five years from the completion date. The Company’s maximum delivery obligation under this agreement is 8,000 gross barrels per day. The Company has a one-time right to elect to decrease the contract quantity by not more than 20% of the then-current quantity, which decreased contract quantity will be effective for the remainder of the term of the agreement. The Company will receive the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the one-month period, as adjusted based on adjustment formulas specified in the agreement. If the Company fails to deliver the required quantities of oil under the agreement during any three-month period following the service commencement date, the Company has agreed to pay Shell Trading (US) Company a deficiency payment, which is calculated by multiplying (i) the volume of oil that the Company failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect for transportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiency volume is calculated. The agreement may be terminated by Shell Trading (US) Company in the event that Shell Trading (US) Company’s contract for transportation on the pipeline is terminated. Defined contribution plan The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee’s compensation and may make additional discretionary contributions for eligible employees. Employer contributions vest immediately. For the years ended December 31, 2017, 2016 and 2015 the Company paid $1.8 million, $1.2 million and $1.4 million, respectively, in contributions to the plan. |
Subsequent Events |
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||
Subsequent Events [Abstract] | |||||||||||||||||||||||||||||||||||||||||||
Subsequent Events | SUBSEQUENT EVENTS Commodity Contracts Subsequent to December 31, 2017, the Company entered into new fixed price swaps and costless collars with corresponding put and call options. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing. The following tables present the derivative contracts entered into by the Company subsequent to December 31, 2017. When aggregating multiple contracts, the weighted average contract price is disclosed.
Fasken Building Purchase On January 31, 2018, the Company completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located. New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility On January 29, 2018, the Company closed on the private placement issuance of $300.0 million aggregate principal amount of 5.375% Senior Notes due 2025. In the offering, the Company received approximately $308.4 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest. The Company used all of the net proceeds from the offering to repay a portion of the outstanding borrowings under its revolving credit facility. In connection with the offering, the lenders under the Company’s revolving credit facility waived the borrowing base decrease that would have been triggered in connection with the offering. Immediately following the completion of the offering and the application of the net proceeds thereof, the Company’s borrowing base remained $1.8 billion, the Company’s elected commitment was $1.0 billion, and the Company had $911.4 million of available borrowing capacity under its revolving credit facility. |
Guarantor Financial Statements |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Guarantor Financial Statements | GUARANTOR FINANCIAL STATEMENTS As of December 31, 2017, Diamondback E&P LLC and Diamondback O&G LLC (the “Guarantor Subsidiaries”) are guarantors under the indentures relating to the 2024 Senior Notes and the 2025 Senior Notes. In connection with the issuance of the 2024 Senior Notes and the 2025 Senior Notes, the Partnership, the General Partner, Viper Energy Partners LLC and Rattler Midstream LLC were designated as Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 17 is referred to as the “Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries on a consolidated basis. Elimination entries presented are necessary to combine the entities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantor Subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries.
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Supplemental Information on Oil and Natural Gas Operations (Unaudited) |
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Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental information on oil and natural gas operations | SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) The Company’s oil and natural gas reserves are attributable solely to properties within the United States. Capitalized oil and natural gas costs Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
Costs incurred in oil and natural gas activities Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:
Results of Operations from Oil and Natural Gas Producing Activities The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and natural gas liquids operations.
Oil and Natural Gas Reserves Proved oil and natural gas reserve estimates as of December 31, 2017, 2016 and 2015 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The changes in estimated proved reserves are as follows:
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. During the year ended December 31, 2017, the Company’s extensions and discoveries of 138,977 MBOE resulted primarily from the drilling of 102 new wells and from 87 new proved undeveloped locations added. Partnership royalty interests accounted for 8% of the extension volumes. The Company’s revisions of previous estimates were primarily the result of 2,550 MBOE from reclassifying PUD locations due to anticipated timing, with the remaining 8,308 MBOE being technical revisions. Delaware Basin working interest purchases accounted for 87% of the total purchases and Partnership royalty interest purchases accounted for 10%, with working interest purchases contributing the remainder. During the year ended December 31, 2016, the Company’s extensions and discoveries of 69,042 MBOE resulted primarily from the drilling of 59 new wells and from 51 new proved undeveloped locations added. The Company owns the mineral interests associated with 30 of the 59 new wells and 30 of the 51 proved undeveloped locations through the Partnership. The Company’s negative revisions of previous estimates were primarily the result of 5,978 MBOE of pricing revisions and 7,253 MBOE from reclassifying 17 locations from proved undeveloped due to pricing. Purchases of reserves in place of 3,993 MBOE were primarily the result of the purchase of producing wells included with the Reeves and Ward county acreage purchase and reserves associated with multiple purchases made by the Partnership. During the year ended December 31, 2015, the Company made one large acquisition of oil and natural gas interests in 2015 located in western Howard and eastern Martin counties. Several small acquisitions were also made in various counties including Andrews, Midland, Martin, and Glasscock counties. The reserves from these acquisitions were primarily proved producing reserves from 136 vertical wells and four horizontal wells and three vertical wells where additional interest was acquired. All of the properties were acquired for horizontal exploitation. Although there were four producing horizontal wells on the properties no PUD’s were included in the acquired properties because of very limited production from the wells at the time of acquisition. Significant extensions occurred in 2015 as a result of continued horizontal development of the Lower Spraberry and Wolfcamp B horizons. There was also initial development of the Wolfcamp A and Middle Spraberry horizons in some locations. The extensions resulted from two vertical wells and 119 horizontal wells in which the Company has a working interest and from 16 horizontal wells in which the Company has a mineral interest through its ownership in Viper. Of the two vertical wells and 135 horizontal wells, one of the vertical wells and 89 of the horizontal wells are in the proved undeveloped category. The revisions are primarily the result of lower product pricing. As a result of lower pricing, 80 vertical wells and 22 horizontal wells in which the Company has a working interest and 22 vertical wells in which the Company has a mineral interest were downgraded from the proved undeveloped category to probable or possible reserves. Additional downward revisions resulted from shorter producing lives on existing wells as a result of the wells reaching their economic limit sooner due to lower revenues. At December 31, 2017, the Company’s estimated PUD reserves were approximately 126,904 MBOE, a 40,550 MBOE increase over the reserve estimate at December 31, 2016 of 86,354 MBOE. The following table includes the changes in PUD reserves for 2017:
The increase in proved undeveloped reserves was primarily attributable to extensions of 67,676 MBOE from 87 gross (75 net) wells in which the Company has a working interest and 3,004 MBOE from 40 gross wells in which the Partnership owns royalty interests. Of the 87 gross wells, 26 were in the Delaware Basin. Transfers of 31,666 MBOE were the result of drilling or participating in 44 gross (37 net) horizontal wells in which the Company has a working interest and 27 gross wells in which the Company has a royalty interest or mineral interest through the Partnership. The Company owns a working interest in 23 of the 27 gross Partnership wells. Net purchases of 6,246 MBOE were primarily from the Company’s purchase in Pecos and Reeves counties. Downward revisions of 4,710 MBOE resulted from reclassification of seven locations and technical revisions. As of December 31, 2017, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2017, approximately $145.4 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells. Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows is based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2017, 2016 and 2015.
In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.
Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:
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Quarterly Financial Data (Unaudited) |
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Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Quarterly Financial Data (Unaudited) | QUARTERLY FINANCIAL DATA (Unaudited) The Company’s unaudited quarterly financial data for 2017 and 2016 is summarized below.
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Summary of Significant Accounting Policies (Policies) |
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Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation. |
Use of Estimates | Use of Estimates Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes. |
Cash and Cash Equivalents and Restricted Cash | Cash and Cash Equivalents The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. Restricted Cash In 2014, a subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The subsidiary subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. |
Accounts Receivable | Accounts Receivable Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. |
Derivative Instruments | Derivative Instruments The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives and senior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 14–Fair Value Measurements). |
Oil and Natural Gas Properties | Oil and Natural Gas Properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 7–Equity Method Investments). Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. |
Other Property and Equipment | Other Property, Equipment and Land Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. |
Asset Retirement Obligations | Asset Retirement Obligations The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties. |
Impairment or Long-Lived Assets | Impairment of Long-Lived Assets Other property and equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. |
Capitalized Interest | The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. The Company capitalized interest of $22.1 million for the year ended December 31, 2017. The Company did not have any capitalized interest for the years ended December 31, 2016 and 2015. |
Inventories | The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. |
Debt Issuance Costs | The costs associated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior notes using the effective interest method. The costs associated with the Company’s credit facility that are included in other assets are being amortized over the term of the facility. |
Revenue and Royalties Payable | Revenue and Royalties Payable For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties. |
Revenue Recognition | Revenue Recognition Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. Revenues from oil and natural gas services are recognized when services are provided. |
Investments | Investments Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. |
Accounting for Stock-based Compensation | Accounting for Equity-Based Compensation The Company grants various types of stock-based awards including stock options and restricted stock units. The Partnership grants various unit-based awards including unit options and phantom units to employees, officers and directors of the General Partner and the Company who perform services for the Partnership. These plans and related accounting policies are defined and described more fully in Note 10–Equity-Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. |
Concentrations | Concentrations The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. |
Environmental Compliance and Remediation | Environmental Compliance and Remediation Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated. |
Income Taxes | Income Taxes Diamondback uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Recently Issued Pronouncements In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The Company will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company has reviewed various contracts that represent its material revenue streams and determined that there will be no impact to its financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, the Company will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, the Company will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Company. The Company does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams as compared to existing GAAP. In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment. In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company will adopt this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements. In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company will adopt this update retrospectively effective January 1, 2018. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements. In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard. In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses. |
Fair Value Measurement | Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities. Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. |
Summary of Significant Accounting Policies (Tables) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of other accrued liabilities | Other accrued liabilities consist of the following:
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Acquisitions (Tables) |
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Schedule of estimated fair values of assets acquired and liabilities assumed | The following represents the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5 billion, resulting in no goodwill or bargain purchase gain.
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Schedule of business acquisition pro forma | The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.
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Property and Equipment (Tables) |
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Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property and Equipment | Property and equipment includes the following:
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Asset Retirement Obligations (Tables) |
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Asset Retirement Obligation [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligations | The following table describes the changes to the Company’s asset retirement obligations liability for the following periods:
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Debt (Tables) |
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Schedule of long-term debt | Long-term debt consisted of the following as of the dates indicated:
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Schedule of interest expense | The following amounts have been incurred and charged to interest expense for the years ended December 31, 2017, 2016 and 2015:
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Company Credit Facility [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financial Covenants |
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Partnership Credit Facility [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financial Covenants |
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Capital Stock and Earnings Per Share (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Class of Stock [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of sale of stock [Table Text Block] | Diamondback completed the following equity offerings during the years ended December 31, 2017, 2016 and 2015:
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Schedule of reconciliation of basic and diluted net income per share | A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
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Equity-Based Compensation (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The effects of stock-based compensation plans and related costs | The following table presents the effects of the equity and stock based compensation plans and related costs:
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Schedule of stock/unit option activity | The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the year ended December 31, 2017.
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Summary of restricted stock awards and units | The following table presents the Company’s restricted stock units activity under the 2012 Plan during the year ended December 31, 2017.
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Summary of grant-date fair values of performance restricted stock units granted and related assumptions | The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions.
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Schedule of performance restricted stock units activity | The following table presents the Company’s performance restricted stock unit activity under the 2012 Plan for the year ended December 31, 2017.
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Viper LTIP [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of stock/unit option activity | The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 2017.
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Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block] |
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Schedule of phantom units activity | The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2017.
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Related Party Transactions (Tables) |
12 Months Ended | |||||||||||||||||||||
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Dec. 31, 2017 | ||||||||||||||||||||||
Related Party Transactions [Abstract] | ||||||||||||||||||||||
Schedule of Amendments to Corporate Office Leases [Table Text Block] | The following table contains amendments made to lease additional office space in the Midland corporate office during the years ended December 31, 2016 and 2015:
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Income Taxes (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | The components of the provision for income taxes for the years ended December 31, 2017, 2016 and 2015 are as follows:
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Reconciliation of Statutory Federal Income Tax Amount to Recorded Expense | A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:
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Schedule of Deferred Tax Assets and Liabilities | The components of the Company’s deferred tax assets and liabilities as of December 31, 2017 and 2016 are as follows:
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Derivatives (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of derivative instruments |
The following tables present the derivative contracts entered into by the Company subsequent to December 31, 2017. When aggregating multiple contracts, the weighted average contract price is disclosed.
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Schedule of netting offsets of derivative assets and liabilities | The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2017 and 2016.
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Schedule of derivative instruments included in the consolidated balance sheet | The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
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Summary of derivative contract gains and losses included in the consolidated statements of operations | The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:
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Fair Value Measurements (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value measurement information for financial instruments measured on a recurring basis | The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016.
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Fair value measurement information for financial instruments measured on a nonrecurring basis | The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets.
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Commitments and Contingencies (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of minimum future lease payments | The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2017:
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Schedule of rent expense | The following table presents rent expense for the years ended December 31, 2017, 2016 and 2015.
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Subsequent Events Subsequent Events (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Subsequent Events [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of derivative instruments |
The following tables present the derivative contracts entered into by the Company subsequent to December 31, 2017. When aggregating multiple contracts, the weighted average contract price is disclosed.
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Guarantor Financial Statements (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 |
Dec. 31, 2016 |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Condensed Consolidated Balance Sheet |
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Condensed Consolidated Statement of Operations |
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Condensed Consolidated Statement of Cash Flows |
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Supplemental Information on Oil and Natural Gas Operations (Unaudited) (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Aggregate capitalized costs related to oil and natural gas production activities | Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
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Costs incurred in oil and natural gas property acquisition, exploration, and development activities | Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:
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Results of operations from oil and natural gas producing activities | The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and natural gas liquids operations.
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Schedule of changes in estimated proved reserves | The changes in estimated proved reserves are as follows:
The following table includes the changes in PUD reserves for 2017:
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Standardized measure of discounted future net cash flows attributable to proved crude oil and natural gas reserves | The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2017, 2016 and 2015.
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Average first-day-of-the-month price for oil, natural gas and natural gas liquids | In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.
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Schedule of principal changes in the standardized measure of discounted future net cash flows attributable to proved reserves | Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:
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Quarterly Financial Data (Unaudited) (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Quarterly Financial Data | The Company’s unaudited quarterly financial data for 2017 and 2016 is summarized below.
|
Description of the Business and Basis of Presentation (Details) - shares |
1 Months Ended | ||||||
---|---|---|---|---|---|---|---|
Sep. 19, 2014 |
Jun. 23, 2014 |
Jul. 31, 2017 |
Jan. 31, 2017 |
Aug. 31, 2016 |
Dec. 31, 2017 |
Aug. 01, 2016 |
|
Noncontrolling Interest [Line Items] | |||||||
Interest in Viper Energy Partners LP | 64.00% | ||||||
Viper Energy Partners LP [Member] | |||||||
Noncontrolling Interest [Line Items] | |||||||
Interest in Viper Energy Partners LP | 88.00% | 92.00% | 64.00% | ||||
Viper Energy Partners LP [Member] | IPO [Member] | |||||||
Noncontrolling Interest [Line Items] | |||||||
Units issued by Viper Energy Partners LP | 5,750,000 | ||||||
Viper Energy Partners LP [Member] | Follow-on Public Offering [Member] | |||||||
Noncontrolling Interest [Line Items] | |||||||
Units issued by Viper Energy Partners LP | 3,500,000 | 16,100,000 | 9,775,000 | 8,050,000 | |||
Interest in Viper Energy Partners LP | 83.00% | ||||||
Viper Energy Partners LP [Member] | Diamondback Energy, Inc. [Member] | |||||||
Noncontrolling Interest [Line Items] | |||||||
Exchange of membership interests for common units | 70,450,000 |
Summary of Significant Accounting Policies - Other Accrued Liabilities (Details) - USD ($) $ in Thousands |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|---|
Accounting Policies [Abstract] | |||
Liability for drilling costs prepaid by joint interest partners | $ 30,320 | $ 21,595 | |
Interest payable | 6,770 | 5,445 | |
Lease operating expenses payable | 27,850 | 13,857 | |
Ad valorem taxes payable | 3,306 | 776 | |
Current portion of asset retirement obligations | 1,163 | 1,288 | $ 193 |
Other | 23,103 | 12,369 | |
Total other accrued liabilities | $ 92,512 | $ 55,330 |
Summary of Significant Accounting Policies - Concentrations (Details) - Customer Concentration Risk [Member] - Sales Revenue, Net [Member] |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Shell Trading US Company [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 31.00% | 45.00% | 59.00% |
Koch Supply & Trading LP [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 19.00% | 15.00% | |
Enterprise Crude Oil LLC [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 11.00% | 13.00% | 15.00% |
Acquisitions - 2017 Activity (Details) shares in Thousands, $ in Thousands |
12 Months Ended | ||||
---|---|---|---|---|---|
Feb. 28, 2017
USD ($)
a
shares
|
Dec. 31, 2017
USD ($)
|
Dec. 31, 2016
USD ($)
|
Dec. 31, 2015
USD ($)
|
Sep. 01, 2016
a
|
|
Business Acquisition [Line Items] | |||||
Acquisition of leasehold interests | $ 1,960,591 | $ 611,280 | $ 437,455 | ||
Additions to midstream assets | $ 68,139 | $ 1,188 | $ 0 | ||
Delaware Basin Interests [Member] | |||||
Business Acquisition [Line Items] | |||||
Payments to Acquire Businesses, Gross | $ 1,740,000 | ||||
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | shares | 7,690 | ||||
Shares Held in Escrow | shares | 1,150 | ||||
Oil and Gas Area, Gross | a | 100,306 | 26,797 | |||
Oil and Gas Area, Net | a | 80,339 | 19,262 | |||
Acquisition of leasehold interests | $ 2,500,000 | ||||
Additions to midstream assets | $ 47,600 |
Acquisitions - Estimated Fair Values of Assets Acquired and Liabilities Assumed (Details) - Delaware Basin Interests [Member] $ in Thousands |
10 Months Ended |
---|---|
Dec. 31, 2017
USD ($)
| |
Business Acquisition [Line Items] | |
Proved oil and gas properties | $ 386,308 |
Unevaluated oil and natural gas properties | 2,122,597 |
Midstream assets | 47,432 |
Prepaid capital costs | 3,460 |
Oil inventory | 839 |
Equipment | 163 |
Revenues and royalties payable | (9,650) |
Asset retirement obligations | (1,550) |
Total fair value of net assets | 2,549,599 |
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | 81,400 |
Business Combination, Pro Forma Information, Direct Operating Expenses since Acquisition Date, Actual | $ 23,500 |
Acquisitions - Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands |
12 Months Ended | |
---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Business Acquisition [Line Items] | ||
Revenues | $ 1,228,040 | $ 627,301 |
Income (loss) from operations | 619,369 | (12,812) |
Net income (loss) | $ 472,649 | $ (109,229) |
Basic earnings per common share | $ 4.85 | $ (1.45) |
Diluted earnings per common share | $ 4.84 | $ (1.45) |
Acquisitions - 2016 Activity (Details) - Delaware Basin Interests [Member] $ in Millions |
Sep. 01, 2016
USD ($)
a
|
Feb. 28, 2017
a
|
---|---|---|
Business Acquisition [Line Items] | ||
Business Combination, Consideration Transferred | $ | $ 558.5 | |
Oil and Gas Area, Gross | 26,797 | 100,306 |
Oil and Gas Area, Net | 19,262 | 80,339 |
Acquisitions - 2015 Activity (Details) - Howard County, Texas [Member] $ in Millions |
12 Months Ended | |
---|---|---|
Jul. 09, 2015
USD ($)
|
Dec. 31, 2015
USD ($)
a
|
|
Business Acquisition [Line Items] | ||
Gas and Oil Area, Developed, Gross | a | 16,940 | |
Gas and Oil Area, Developed, Net | a | 12,672 | |
Business Combination, Consideration Transferred | $ | $ 437.5 | |
Viper Energy Partners LP [Member] | ||
Business Acquisition [Line Items] | ||
Oil and Gas Property, Percent of Royalty Interest Sold | 1.50% | |
Proceeds from Sale of Oil and Gas Property and Equipment | $ | $ 31.1 |
Asset Retirement Obligations (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Changes in ARO liability | |||
Asset retirement obligations, beginning of period | $ 17,422 | $ 12,711 | $ 8,486 |
Additional liabilities incurred | 1,526 | 637 | 594 |
Liabilities acquired | 2,432 | 3,696 | 3,159 |
Liabilities settled | (1,555) | (711) | (292) |
Accretion expense | 1,391 | 1,064 | 833 |
Revisions in estimated liabilities | 69 | 25 | (69) |
Asset retirement obligations, end of period | 21,285 | 17,422 | 12,711 |
Less current portion | 1,163 | 1,288 | 193 |
Asset retirement obligations - long-term | $ 20,122 | $ 16,134 | $ 12,518 |
Equity Method Investments (Details) - USD ($) $ in Thousands |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Oct. 31, 2014 |
|
Schedule of Equity Method Investments | ||||
Payment to acquire equity method investment | $ 188 | $ 2,345 | $ 2,702 | |
Income (Loss) from Equity Method Investments | 657 | 676 | $ 0 | |
HMW Fluid Management LLC [Member] | ||||
Schedule of Equity Method Investments | ||||
Ownership interest | 25.00% | |||
Payment to acquire equity method investment | 188 | 2,345 | ||
Income (Loss) from Equity Method Investments | 657 | 676 | ||
Equity Method Investments | $ 7,195 | $ 6,349 |
Debt - Long-term Debt (Details) - USD ($) $ in Thousands |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Debt Instrument [Line Items] | ||
Unamortized debt issuance costs | $ (13,153) | $ (14,588) |
Total long-term debt | 1,477,347 | 1,105,912 |
Senior Unsecured Notes due 2024 [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | 500,000 | 500,000 |
Senior Unsecured Notes due 2025 [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | 500,000 | 500,000 |
Company Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | 397,000 | 0 |
Partnership Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | $ 93,500 | $ 120,500 |
Debt - Interest Expense (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Debt Disclosure [Abstract] | |||
Interest expense | $ 60,671 | $ 39,642 | $ 40,221 |
Interest Costs Capitalized Adjustment | (22,097) | 0 | 0 |
Other fees and expenses | 2,160 | 1,426 | 1,292 |
Total interest expense | $ 40,734 | $ 41,068 | $ 41,513 |
Capital Stock and Earnings Per Share - Capital Stock (Details) - USD ($) $ / shares in Units, $ in Thousands |
1 Months Ended | |||||
---|---|---|---|---|---|---|
Dec. 31, 2016 |
Jul. 31, 2016 |
Jan. 31, 2016 |
Aug. 31, 2015 |
May 31, 2015 |
Jan. 31, 2015 |
|
Follow-on Public Offering [Member] | ||||||
Class of Stock [Line Items] | ||||||
Shares issued upon public offering | 12,075,000 | 6,325,000 | 4,600,000 | 2,875,000 | 4,600,000 | 2,012,500 |
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions | $ 1,150,828 | $ 551,777 | $ 254,518 | $ 197,628 | $ 333,638 | $ 119,422 |
Stock price per share at public offering (in dollars per share) | $ 95.3025 | $ 87.24 | $ 55.33 | $ 68.74 | $ 72.53 | $ 59.34 |
Over-Allotment Option [Member] | ||||||
Class of Stock [Line Items] | ||||||
Shares issued upon public offering | 1,575,000 | 825,000 | 600,000 | 375,000 | 600,000 | 262,500 |
Capital Stock and Earnings Per Share - Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2016 |
Sep. 30, 2016 |
Jun. 30, 2016 |
Mar. 31, 2016 |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Basic: | |||||||||||
Net Income (loss) attributable to common stock | $ 114,559 | $ 73,024 | $ 158,405 | $ 136,273 | $ 25,598 | $ (2,230) | $ (155,490) | $ (32,912) | $ 482,261 | $ (165,034) | $ (550,628) |
Weighted Average Number of Shares Outstanding, Basic | 97,458,000 | 75,077,000 | 63,019,000 | ||||||||
Net income attributable to common stock, basic, (in dollars per share) | $ 1.17 | $ 0.74 | $ 1.61 | $ 1.46 | $ 0.32 | $ (0.03) | $ (2.17) | $ (0.46) | $ 4.95 | $ (2.20) | $ (8.74) |
Effect of Dilutive Securities: | |||||||||||
Dilutive effect of potential common shares issuable (in shares) | 230,000 | 0 | 0 | ||||||||
Diluted: | |||||||||||
Net income attributable to common stock, diluted (in shares) | 97,688,000 | 75,077,000 | 63,019,000 | ||||||||
Net income attributable to common stock, diluted (in dollars per share) | $ 1.16 | $ 0.74 | $ 1.61 | $ 1.46 | $ 0.32 | $ (0.03) | $ (2.17) | $ (0.46) | $ 4.94 | $ (2.20) | $ (8.74) |
Antidilutive securities excluded from earnings per share (in shares) | 45,690 | 243,654 | 100,924 |
Equity-Based Compensation - Phantom Units (Details) - Viper LTIP [Member] - Phantom Units [Member] $ / shares in Units, $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2017
USD ($)
$ / shares
shares
| |
Awards & Units (in shares) | |
Unvested at beginning of period | shares | 21,048 |
Granted | shares | 116,567 |
Vested | shares | (32,176) |
Unvested at end of period | shares | 105,439 |
Weighted Average Grant-Date Fair Value (in dollars per share) | |
Unvested at beginning of period | $ / shares | $ 16.23 |
Granted | $ / shares | 17.09 |
Vested | $ / shares | 16.49 |
Unvested at end of period | $ / shares | $ 17.10 |
Aggregate fair value of share-based awards that vested | $ | $ 0.5 |
Unrecognized compensation cost related to unvested awards | $ | $ 1.3 |
Unrecognized compensation cost, period of recognition | 1 year 4 months 17 days |
Related Party Transactions - Advisory Services Agreements (Details) - Advisory Services Agreement [Member] - Wexford [Member] - USD ($) |
12 Months Ended | ||||
---|---|---|---|---|---|
Jun. 23, 2014 |
Oct. 11, 2012 |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Related Party Transaction | |||||
Advisory services agreement, annual fee | $ 500,000 | ||||
Term of advisory services agreement | 2 years | ||||
Renewal term of advisory services agreement | 1 year | ||||
Minimum period for cancellation of additional one-year periods | 10 days | ||||
Agreement termination, written notice period | 30 days | ||||
Payments for Operating Activities | $ 500,000 | $ 500,000 | |||
Viper Energy Partners LP [Member] | |||||
Related Party Transaction | |||||
Advisory services agreement, annual fee | $ 500,000 | ||||
Term of advisory services agreement | 2 years | ||||
Renewal term of advisory services agreement | 1 year | ||||
Minimum period for cancellation of additional one-year periods | 10 days | ||||
Agreement termination, written notice period | 30 days | ||||
Payments for Operating Activities | $ 0 | $ 0 | $ 500,000 |
Related Party Transactions - Coronado Midstream (Details) |
Feb. 28, 2015 |
---|---|
Coronado Midstream [Member] | |
Related Party Transaction | |
Ownership interest | 28.00% |
Related Party Transactions - Lease Bonus (Details) - Viper Energy Partners LP [Member] |
12 Months Ended | |
---|---|---|
Dec. 31, 2017
USD ($)
|
Dec. 31, 2016
USD ($)
|
|
Related Party Transaction | ||
Payments for Operating Activities | $ 100,000 | $ 300,000 |
Number of leases extended | 2 | 6 |
Average price per acre | $ 7,459 | $ 1,371 |
Income Taxes - Components of Federal Income Tax (Details) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2016 |
Sep. 30, 2016 |
Jun. 30, 2016 |
Mar. 31, 2016 |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Operating Loss Carryforwards [Line Items] | |||||||||||
Change in valuation allowance | $ (127,485) | $ 53,336 | $ 61,056 | ||||||||
Income tax benefit relating to change in statutory tax rate | (67,938) | 0 | (1,145) | ||||||||
Current income tax provision (benefit): | |||||||||||
Federal | 0 | 0 | (33) | ||||||||
State | 999 | 192 | 268 | ||||||||
Total current income tax provision | 999 | 192 | 235 | ||||||||
Deferred income tax provision (benefit): | |||||||||||
Federal | (21,720) | (579) | (198,729) | ||||||||
State | 1,153 | 579 | (2,816) | ||||||||
Total deferred income tax provision (benefit) | (20,567) | 0 | (201,545) | ||||||||
Total provision for (benefit from) income taxes | $ (23,961) | $ 857 | $ 1,579 | $ 1,957 | $ (176) | $ 0 | $ 368 | $ 0 | $ (19,568) | $ 192 | $ (201,310) |
Income Taxes - Reconciliation of Statutory Federal Income Tax (Details) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2016 |
Sep. 30, 2016 |
Jun. 30, 2016 |
Mar. 31, 2016 |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Income Tax Disclosure [Abstract] | |||||||||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | 35.00% | 35.00% | ||||||||
Income tax expense (benefit) at the federal statutory rate (35%) | $ 174,016 | $ (57,694) | $ (263,179) | ||||||||
Impact of nontaxable noncontrolling interest | 12,073 | 0 | 0 | ||||||||
Income tax benefit relating to change in statutory tax rate | (67,938) | 0 | (1,145) | ||||||||
State income tax expense (benefit), net of federal tax effect | 3,413 | 770 | (2,548) | ||||||||
Non-deductible compensation | 13,492 | 3,990 | 1,354 | ||||||||
Change in valuation allowance | (127,485) | 53,336 | 61,056 | ||||||||
Other, net | (2,993) | (210) | 3,152 | ||||||||
Total provision for (benefit from) income taxes | $ (23,961) | $ 857 | $ 1,579 | $ 1,957 | $ (176) | $ 0 | $ 368 | $ 0 | $ (19,568) | $ 192 | $ (201,310) |
Income Taxes Net Operating Loss (Details) $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2017
USD ($)
| |
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration | $ 357.0 |
Minimum [Member] | |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2032 |
Maximum [Member] | |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2037 |
Derivatives - Offsetting Derivative Instruments (Details) - USD ($) $ in Thousands |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Gross amounts of assets presented in the Consolidated Balance Sheet | $ 531 | $ 709 |
Net amounts of assets presented in the Consolidated Balance Sheet | 531 | 709 |
Gross amounts of liabilities presented in the Consolidated Balance Sheet | 106,670 | 22,608 |
Net amounts of liabilities presented in the Consolidated Balance Sheet | $ 106,670 | $ 22,608 |
Derivatives - Balance Sheet Location (Details) - USD ($) $ in Thousands |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Current assets: derivative instruments | $ 531 | $ 0 |
Noncurrent assets: derivative instruments | 0 | 709 |
Total assets | 531 | 709 |
Current liabilities: derivative instruments | 100,367 | 22,608 |
Noncurrent liabilities: derivative instruments | 6,303 | 0 |
Total liabilities | $ 106,670 | $ 22,608 |
Derivatives - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Change in fair value of open non-hedge derivative instruments | $ (84,240) | $ (26,522) | $ (112,918) |
Gain on settlement of non-hedge derivative instruments | 6,728 | 1,177 | 144,869 |
Gain (loss) on derivative instruments | $ (77,512) | $ (25,345) | $ 31,951 |
Fair Value Measurements - Recurring Measurements (Details) - Recurring [Member] - USD ($) $ in Thousands |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Assets: | ||
Derivative Assets (Liabilities), at Fair Value, Net | $ (106,139) | $ 23,317 |
Fair Value, Inputs, Level 1 [Member] | ||
Assets: | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | ||
Assets: | ||
Derivative Assets (Liabilities), at Fair Value, Net | (106,139) | 23,317 |
Significant Unobservable Inputs Level 3 [Member] | ||
Assets: | ||
Derivative Assets (Liabilities), at Fair Value, Net | $ 0 | $ 0 |
Commitments and Contingencies - Lease Commitments (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Future minimum lease payments | |||
Rent Expense | $ 2,412 | $ 1,961 | $ 1,449 |
Drilling Rig [Member] | |||
Future minimum lease payments | |||
2018 | 21,882 | ||
2019 | 10,082 | ||
2020 | 0 | ||
2021 | 0 | ||
2022 | 0 | ||
Thereafter | 0 | ||
Total | 31,964 | ||
Office and Equipment [Member] | |||
Future minimum lease payments | |||
2018 | 3,581 | ||
2019 | 3,307 | ||
2020 | 2,927 | ||
2021 | 2,406 | ||
2022 | 2,242 | ||
Thereafter | 7,973 | ||
Total | $ 22,436 |
Commitments and Contingencies - Commitments and Obligations (Details) - Shell Trading US Company [Member] |
May 24, 2012
bbl
|
---|---|
Supply Commitment [Line Items] | |
Delivery contract, term | 5 years |
One-time right to decrease contract quantity, percent, not more than 20% | 20.00% |
Maximum [Member] | |
Supply Commitment [Line Items] | |
Maximum delivery obligation, barrels per day | 8,000 |
Commitments and Contingencies - Defined Contribution Plan (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Defined contribution plan | |||
Employee maximum annual contribution as percentage of annual compensation | 100.00% | ||
Employer matching contribution percentage, up to 6% | 6.00% | ||
Contributions by employer | $ 1.8 | $ 1.2 | $ 1.4 |
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Thousands |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Oil and Natural Gas Properties: | ||
Proved properties | $ 5,126,829 | $ 3,429,742 |
Unproved properties | 4,105,865 | 1,730,519 |
Total oil and natural gas properties | 9,232,694 | 5,160,261 |
Accumulated depreciation, depletion, amortization | (1,009,893) | (687,685) |
Accumulated impairment | (1,143,498) | (1,143,498) |
Oil and natural gas properties, net | $ 7,079,303 | $ 3,329,078 |
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Acquisition costs | |||
Proved properties | $ 452,661 | $ 72,044 | $ 64,340 |
Unproved properties | 2,692,000 | 752,117 | 448,638 |
Development costs | 145,362 | 47,575 | 42,749 |
Exploration costs | 779,728 | 329,122 | 319,102 |
Capitalized asset retirement costs | 2,682 | 4,030 | 3,458 |
Total | $ 4,072,433 | $ 1,204,888 | $ 878,287 |
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Results of Operations for Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Oil, natural gas and natural gas liquid sales | $ 1,186,275 | $ 527,107 | $ 446,733 |
Lease operating expenses | (126,524) | (82,428) | (82,625) |
Production and ad valorem taxes | (73,505) | (34,456) | (32,990) |
Gathering and transportation | (12,834) | (11,606) | (6,091) |
Depreciation, depletion, and amortization | (321,870) | (176,369) | (216,056) |
Impairment | 0 | (245,536) | (814,798) |
Asset retirement obligation accretion expense | (1,391) | (1,064) | (833) |
Income tax benefit (expense) | 19,568 | (192) | 201,310 |
Results of operations | $ 669,719 | $ (24,544) | $ (505,350) |
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows - Proved Crude Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|---|---|
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract] | ||||
Future cash inflows | $ 12,921,897 | $ 6,275,705 | $ 5,377,783 | |
Future development costs | (1,123,979) | (617,636) | (548,239) | |
Future production costs | (2,994,877) | (1,392,852) | (1,279,101) | |
Future production taxes | (928,891) | (459,244) | (363,129) | |
Future income tax expenses | (83,961) | (75,595) | (28,233) | |
Future net cash flows | 7,790,189 | 3,730,378 | 3,159,081 | |
10% discount to reflect timing of cash flows | (4,033,130) | (2,018,965) | (1,740,948) | |
Standardized measure of discounted future net cash flows | $ 3,757,059 | $ 1,711,413 | $ 1,418,133 | $ 2,045,224 |
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Average First Day of the Month Price for Oil, Natural Gas & Natural Gas Liquids (Details) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017
$ / bbl
$ / Mcf
|
Dec. 31, 2016
$ / bbl
$ / Mcf
|
Dec. 31, 2015
$ / bbl
$ / Mcf
|
|
Oil [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sales prices (dollars per unit) | 48.03 | 39.94 | 45.07 |
Natural Gas [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sales prices (dollars per unit) | $ / Mcf | 2.06 | 1.36 | 1.83 |
Natural Gas Liquids [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sales prices (dollars per unit) | 20.79 | 12.91 | 12.56 |
Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2016 |
Sep. 30, 2016 |
Jun. 30, 2016 |
Mar. 31, 2016 |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Revenues | $ 399,194 | $ 301,253 | $ 269,434 | $ 235,230 | $ 185,012 | $ 142,131 | $ 112,483 | $ 87,481 | $ 1,205,111 | $ 527,107 | $ 446,733 |
Income (loss) from operations | 213,663 | 142,639 | 132,308 | 116,410 | 87,079 | 6,693 | (134,786) | (27,603) | 605,020 | (68,617) | (740,269) |
Income tax expense (benefit) | (23,961) | 857 | 1,579 | 1,957 | (176) | 0 | 368 | 0 | (19,568) | 192 | (201,310) |
Net income (loss) | 129,607 | 81,948 | 164,128 | 141,074 | 28,440 | (600) | (157,121) | (35,627) | 516,757 | (164,908) | (547,790) |
Net income (loss) attributable to non-controlling interest | 15,048 | 8,924 | 5,723 | 4,801 | 2,842 | 1,630 | (1,631) | (2,715) | 34,496 | 126 | 2,838 |
Net income (loss) attributable to Diamondback Energy, Inc. | $ 114,559 | $ 73,024 | $ 158,405 | $ 136,273 | $ 25,598 | $ (2,230) | $ (155,490) | $ (32,912) | $ 482,261 | $ (165,034) | $ (550,628) |
Earnings per common share: | |||||||||||
Basic (in dollars per share) | $ 1.17 | $ 0.74 | $ 1.61 | $ 1.46 | $ 0.32 | $ (0.03) | $ (2.17) | $ (0.46) | $ 4.95 | $ (2.20) | $ (8.74) |
Diluted (in dollars per share) | $ 1.16 | $ 0.74 | $ 1.61 | $ 1.46 | $ 0.32 | $ (0.03) | $ (2.17) | $ (0.46) | $ 4.94 | $ (2.20) | $ (8.74) |
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