|
|
|
|
|
|
|
|
|
|
|
|
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.
|
Mb/d
|
Thousand barrels per day.
|
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.
|
Bison
|
Bison Drilling and Field Services, LLC.
|
Company
|
Diamondback Energy, Inc., a Delaware corporation, together with its subsidiaries.
|
EPA
|
U.S. Environmental Protection Agency.
|
Equity Plan
|
The Company’s Equity Incentive Plan.
|
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.
|
Operating Company
|
Viper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
|
OSHA
|
Federal Occupational Safety and Health Act.
|
Partnership
|
Viper Energy Partners LP, a Delaware limited partnership.
|
Partnership agreement
|
The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018.
|
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 $1,250 million.
|
2025 Senior Notes
|
The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 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, including our recent acquisition of certain leasehold acres and other assets from Ajax Resources, LLC and our recent acquisition of Energen Corporation discussed elsewhere in this report;
|
•
|
our ability to achieve the anticipated synergies, operational efficiencies and returns from our recent acquisition of Energen Corporation;
|
•
|
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 development of stacked horizons.
We have been developing multiple pay intervals in the Permian Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. Our initial horizontal wells were completed in
2012
, and since then we have been an active horizontal driller in the basin. As of
December 31, 2018
, we are the operator of
1,193
producing horizontal wells and have a non-operated working interest in
253
additional wells. Of these
1,446
total horizontal wells,
952
wells are in the Midland Basin,
493
wells are in the Delaware Basin and
one
well is in the Central Basin platform. We believe that our significant experience drilling, completing and operating horizontal wells will allow us to efficiently develop our remaining inventory and ultimately target other horizons that have limited development to date. During the year ended
December 31, 2018
, 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
13
days, we drilled approximately
10,000
foot lateral wells in
15
days and we drilled approximately
13,000
foot wells in
23
days. During the year ended
December 31, 2018
, we were able to drill our horizontal wells in the Delaware Basin with approximately
7,500
foot lateral lengths to total depth in an average of
24
days and we drilled approximately
10,000
foot lateral wells in
31
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
89%
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
76%
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, 2018
, we completed multiple acquisitions in the Midland Basin through our acquisitions of Ajax, ExL and EnergyQuest, as well as Energen. As a result, our Midland Basin acreage footprint increased from approximately
101,941
net acres to approximately
194,661
net acres as of
December 31, 2018
, with our Delaware Basin acreage increasing from approximately
104,719
net acres to approximately
170,205
net acres over the same period.
|
•
|
Maintain financial flexibility.
We seek to maintain a conservative financial position. In connection with our fall 2018 borrowing base redetermination, our borrowing base was set at
$2.65 billion
, and we elected a commitment amount of
$2.0 billion
, of which
$0.5 billion
was available for borrowing as of
December 31, 2018
. As of
December 31, 2018
, Viper had
$411.0 million
in outstanding borrowings, and
$144.0 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, 2018
was approximately
72%
oil,
16%
natural gas liquids and
12%
natural gas. As of
December 31, 2018
, our estimated net proved reserves were comprised of approximately
63%
oil,
18%
natural gas liquids and
19%
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
11,868
gross (
7,633
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
7,200
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
11,868
locations,
6,479
are in the Midland Basin and
5,389
are in the Delaware Basin. In the Midland Basin,
2,465
are in the Lower Spraberry or Wolfcamp B horizons where we have drilled a large number of wells,
2,200
are in the Wolfcamp A or Middle Spraberry horizons where we have drilled a limited number of wells and
1,814
are in the Clearfork, Jo Mill or Cline horizons where we have drilled very few wells. Our current location count for the Lower Spraberry horizon is based on
660
foot to 880 foot spacing in Midland, Martin, northeast Andrews, Howard and Glasscock counties, depending on the prospect area and
880
foot spacing in all other counties. For the Wolfcamp B horizon, the horizontal location count is based on
660
foot to 880 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 to 880 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 and Jo Mill horizons, the horizontal location count is based on 880 foot to
1,320
foot spacing. In the Delaware Basin,
2,219
locations are in the Wolfcamp A or Wolfcamp B horizons, and
1,789
locations are in the 2nd Bone Spring or 3rd Bone Spring horizon and
1,381
locations are in other horizons including the Brushy Canyon, Avalon, 1st Bone Spring and Wolfcamp C. 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. In addition, we have approximately
2,617
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
|
•
|
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
89%
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,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Estimated proved developed reserves:
|
|
|
|
|
|
|||
Oil (MBbls)
|
403,051
|
|
|
141,246
|
|
|
79,457
|
|
Natural gas (MMcf)
|
705,084
|
|
|
190,740
|
|
|
105,399
|
|
Natural gas liquids (MBbls)
|
125,509
|
|
|
35,412
|
|
|
22,080
|
|
Total (MBOE)
|
646,074
|
|
|
208,447
|
|
|
119,104
|
|
Estimated proved undeveloped reserves:
|
|
|
|
|
|
|||
Oil (MBbls)
|
223,885
|
|
|
91,935
|
|
|
59,717
|
|
Natural gas (MMcf)
|
343,565
|
|
|
94,629
|
|
|
69,497
|
|
Natural gas liquids (MBbls)
|
64,782
|
|
|
19,198
|
|
|
15,054
|
|
Total (MBOE)
|
345,928
|
|
|
126,905
|
|
|
86,354
|
|
Estimated Net Proved Reserves:
|
|
|
|
|
|
|||
Oil (MBbls)
|
626,936
|
|
|
233,181
|
|
|
139,174
|
|
Natural gas (MMcf)
|
1,048,649
|
|
|
285,369
|
|
|
174,896
|
|
Natural gas liquids (MBbls)
|
190,291
|
|
|
54,609
|
|
|
37,134
|
|
Total (MBOE)
(1)
|
992,001
|
|
|
335,352
|
|
|
205,458
|
|
Percent proved developed
|
65
|
%
|
|
62
|
%
|
|
58
|
%
|
(1)
|
Estimates of reserves as of
December 31, 2018
,
2017
and
2016
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, 2018
,
2017
and
2016
, 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, 2017
|
126,905
|
|
Undeveloped reserves transferred to developed
|
(71,435
|
)
|
Revisions
|
338
|
|
Net purchases
|
165,426
|
|
Extensions and discoveries
|
124,694
|
|
Ending proved undeveloped reserves at December 31, 2018
|
345,928
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Production Data:
|
|
|
|
|
|
||||||
Oil (MBbls)
|
34,367
|
|
|
21,418
|
|
|
11,562
|
|
|||
Natural gas (MMcf)
|
34,669
|
|
|
20,660
|
|
|
10,728
|
|
|||
Natural gas liquids (MBbls)
|
7,465
|
|
|
4,056
|
|
|
2,399
|
|
|||
Combined volumes (MBOE)
|
47,610
|
|
|
28,917
|
|
|
15,749
|
|
|||
Daily combined volumes (BOE/d)
|
130,439
|
|
|
79,224
|
|
|
43,031
|
|
|||
|
|
|
|
|
|
||||||
Average Prices:
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
54.66
|
|
|
$
|
48.75
|
|
|
$
|
40.70
|
|
Natural gas (per Mcf)
|
1.76
|
|
|
2.53
|
|
|
2.10
|
|
|||
Natural gas liquids (per Bbl)
|
25.47
|
|
|
22.20
|
|
|
14.20
|
|
|||
Combined (per BOE)
|
44.73
|
|
|
41.02
|
|
|
33.47
|
|
|||
Oil, hedged ($ per Bbl)
(1)
|
51.20
|
|
|
48.94
|
|
|
40.80
|
|
|||
Natural gas, hedged ($ per MMbtu)
(1)
|
1.72
|
|
|
2.65
|
|
|
2.06
|
|
|||
Average price, hedged ($ per BOE)
(1)
|
42.20
|
|
|
41.26
|
|
|
33.54
|
|
|||
|
|
|
|
|
|
||||||
Average Costs per BOE:
|
|
|
|
|
|
||||||
Lease operating expense
|
$
|
4.31
|
|
|
$
|
4.38
|
|
|
$
|
5.23
|
|
Production and ad valorem taxes
|
2.79
|
|
|
2.54
|
|
|
2.19
|
|
|||
Gathering and transportation expense
|
0.55
|
|
|
0.44
|
|
|
0.74
|
|
|||
General and administrative - cash component
|
0.79
|
|
|
0.80
|
|
|
1.03
|
|
|||
Total operating expense - cash
|
$
|
8.44
|
|
|
$
|
8.16
|
|
|
$
|
9.19
|
|
|
|
|
|
|
|
||||||
General and administrative - non-cash component
|
$
|
0.57
|
|
|
$
|
0.88
|
|
|
$
|
1.68
|
|
Depreciation, depletion and amortization
|
13.09
|
|
|
11.30
|
|
|
11.30
|
|
|||
Interest expense, net
|
1.83
|
|
|
1.40
|
|
|
2.58
|
|
|||
Merger and integration expense
|
0.77
|
|
|
—
|
|
|
—
|
|
|||
Total expenses
|
$
|
16.26
|
|
|
$
|
13.58
|
|
|
$
|
15.56
|
|
(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)
|
||||||
Conventional Permian
|
103,155
|
|
|
70,410
|
|
|
14,795
|
|
|
4,178
|
|
|
117,950
|
|
|
74,588
|
|
Delaware
|
127,819
|
|
|
90,554
|
|
|
104,324
|
|
|
79,651
|
|
|
232,143
|
|
|
170,205
|
|
Exploration
|
—
|
|
|
—
|
|
|
23,174
|
|
|
21,764
|
|
|
23,174
|
|
|
21,764
|
|
Midland
|
198,408
|
|
|
162,370
|
|
|
32,692
|
|
|
32,291
|
|
|
231,100
|
|
|
194,661
|
|
Total
|
429,382
|
|
|
323,334
|
|
|
174,985
|
|
|
137,884
|
|
|
604,367
|
|
|
461,218
|
|
(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.
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
||||||||||||||||||||
Basin
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||||
Delaware
|
43,963
|
|
|
31,130
|
|
|
13,779
|
|
|
6,474
|
|
|
7,447
|
|
|
3,447
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploration
|
—
|
|
|
—
|
|
|
18,713
|
|
|
18,713
|
|
|
4,405
|
|
|
3,035
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Midland
|
9,246
|
|
|
6,406
|
|
|
4,443
|
|
|
2,503
|
|
|
172
|
|
|
385
|
|
|
308
|
|
|
254
|
|
|
—
|
|
|
—
|
|
Total
|
53,209
|
|
|
37,536
|
|
|
36,935
|
|
|
27,690
|
|
|
12,024
|
|
|
6,867
|
|
|
308
|
|
|
254
|
|
|
—
|
|
|
—
|
|
|
Midland Basin
|
|
Delaware Basin
|
|
Total
|
|||
% of produced oil sold by pipeline
|
94
|
%
|
|
68
|
%
|
|
88
|
%
|
% of produced water connected to pipeline
|
94
|
%
|
|
92
|
%
|
|
93
|
%
|
•
|
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 inability to successfully integrate the businesses of Energen into our business, operationally and culturally;
|
•
|
complexities associated with managing the larger, more complex, integrated business;
|
•
|
complexities resulting from the different accounting methods of our company and Energen;
|
•
|
not realizing anticipated operating synergies;
|
•
|
integrating personnel from the two companies and the loss of key employees;
|
•
|
potential unknown liabilities and unforeseen expenses associated with the merger or integration;
|
•
|
integrating relationships with customers, vendors and business partners;
|
•
|
performance shortfalls as a result of the diversion of management’s attention caused by integrating Energen’s operations into operations; and
|
•
|
the disruption of, or the loss of momentum in, our business or inconsistencies in standards, controls, procedures and policies encountered during integration of our business with that of Energen.
|
•
|
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
$61.07
WTI Cushing for
10,638,000
aggregate Bbls;
|
•
|
crude oil swap contracts priced at a weighted average price of
$72.39
WTI Magellan East Houston for
1,270,000
aggregate Bbls;
|
•
|
crude oil swap contracts priced at a weighted average price of
$68.02
Brent for
2,005,000
aggregate Bbls;
|
•
|
crude oil basis swap contracts priced at a weighted average price of
$(5.56)
for
17,012,000
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
$3.06
Henry Hub for
25,550,000
aggregate MMBtu;
|
•
|
natural gas basis swap contracts priced at a weighted average price of
$(1.60)
Waha Hub for
18,250,000
aggregate MMBtu;
|
•
|
natural gas liquid swaps priced at a weighted average price of
$27.30
Mont Belvieu for
2,760,000
aggregate Bbls;
|
•
|
crude oil three-way collars contracts with a WTI Cushing short put price of
$38.10
, floor price of
$48.10
and a ceiling price of
$63.70
for
7,570,000
aggregate Bbls;
|
•
|
crude oil three-way collars contracts with a WTI Magellan East Houston short put price of
$56.82
, floor price of
$66.82
and a ceiling price of
$77.60
for
994,000
aggregate Bbls; and
|
•
|
crude oil three-way collars contracts with a Brent short put price of
$55.00
, floor price of
$65.00
and a ceiling price of
$82.47
for
2,000,000
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
|
|
Cash Dividends per Share of Common Stock
|
||||||
2018
|
|
|
|
|
|
||||||
1st Quarter
|
$
|
134.60
|
|
|
$
|
105.66
|
|
|
$
|
0.125
|
|
2nd Quarter
|
$
|
138.14
|
|
|
$
|
107.78
|
|
|
$
|
0.125
|
|
3rd Quarter
|
$
|
138.25
|
|
|
$
|
111.31
|
|
|
$
|
0.125
|
|
4th Quarter
(2)
|
$
|
140.78
|
|
|
$
|
85.19
|
|
|
$
|
0.125
|
|
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
|
|
|
$
|
—
|
|
(1)
|
The Q4 2018 distribution is payable on February 28, 2918 to unitholders of record at the close of business on February 21, 2019.
|
|
Year Ended December 31,
|
||||||||||||||||||
(In thousands, except per share amounts)
|
2018
(1)
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
2,176,256
|
|
|
$
|
1,205,111
|
|
|
$
|
527,107
|
|
|
$
|
446,733
|
|
|
$
|
495,718
|
|
Total costs and expenses
|
1,165,468
|
|
|
600,091
|
|
|
595,724
|
|
|
1,187,002
|
|
|
283,048
|
|
|||||
Income (loss) from operations
|
1,010,788
|
|
|
605,020
|
|
|
(68,617
|
)
|
|
(740,269
|
)
|
|
212,670
|
|
|||||
Other income (expense)
|
102,469
|
|
|
(107,831
|
)
|
|
(96,099
|
)
|
|
(8,831
|
)
|
|
92,286
|
|
|||||
Income (loss) before income taxes
|
1,113,257
|
|
|
497,189
|
|
|
(164,716
|
)
|
|
(749,100
|
)
|
|
304,956
|
|
|||||
Provision for (benefit from) income taxes
|
168,362
|
|
|
(19,568
|
)
|
|
192
|
|
|
(201,310
|
)
|
|
108,985
|
|
|||||
Net income (loss)
|
944,895
|
|
|
516,757
|
|
|
(164,908
|
)
|
|
(547,790
|
)
|
|
195,971
|
|
|||||
Less: Net income attributable to non-controlling interest
|
99,223
|
|
|
34,496
|
|
|
126
|
|
|
2,838
|
|
|
2,216
|
|
|||||
Net income (loss) attributable to Diamondback Energy, Inc.
|
$
|
845,672
|
|
|
$
|
482,261
|
|
|
$
|
(165,034
|
)
|
|
$
|
(550,628
|
)
|
|
$
|
193,755
|
|
Earnings per common share
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
8.09
|
|
|
$
|
4.95
|
|
|
$
|
(2.20
|
)
|
|
$
|
(8.74
|
)
|
|
$
|
3.67
|
|
Diluted
|
$
|
8.06
|
|
|
$
|
4.94
|
|
|
$
|
(2.20
|
)
|
|
$
|
(8.74
|
)
|
|
$
|
3.64
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
104,622
|
|
|
97,458
|
|
|
75,077
|
|
|
63,019
|
|
|
52,826
|
|
|||||
Diluted
|
104,929
|
|
|
97,688
|
|
|
75,077
|
|
|
63,019
|
|
|
53,297
|
|
|||||
Cash dividends declared per common share
|
$
|
0.500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Our results of operations for 2018 include those of Energen and its subsidiaries acquired by us in the merger from the period of November 29, 2018, the closing date of the merger, through
December 31, 2018
.
|
|
As of December 31,
|
||||||||||||||||||
(In thousands)
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
214,516
|
|
|
$
|
112,446
|
|
|
$
|
1,666,574
|
|
|
$
|
20,115
|
|
|
$
|
30,183
|
|
Net property and equipment
|
20,371,975
|
|
|
7,343,617
|
|
|
3,390,857
|
|
|
2,597,625
|
|
|
2,791,807
|
|
|||||
Total assets
|
21,595,687
|
|
|
7,770,985
|
|
|
5,349,680
|
|
|
2,750,719
|
|
|
3,095,481
|
|
|||||
Current liabilities
|
1,019,612
|
|
|
577,428
|
|
|
209,342
|
|
|
141,421
|
|
|
266,729
|
|
|||||
Long-term debt
|
4,464,338
|
|
|
1,477,347
|
|
|
1,105,912
|
|
|
487,807
|
|
|
673,500
|
|
|||||
Total stockholders’/ members’ equity
(1)
|
13,699,287
|
|
|
5,254,860
|
|
|
3,697,462
|
|
|
1,875,972
|
|
|
1,751,011
|
|
|||||
Total equity
|
14,166,262
|
|
|
5,581,737
|
|
|
4,018,292
|
|
|
2,108,973
|
|
|
1,985,213
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(In thousands)
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
$
|
1,564,505
|
|
|
$
|
888,625
|
|
|
$
|
332,080
|
|
|
$
|
416,501
|
|
|
$
|
356,389
|
|
Net cash used in investing activities
|
(3,503,043
|
)
|
|
(3,132,282
|
)
|
|
(1,310,242
|
)
|
|
(895,050
|
)
|
|
(1,481,997
|
)
|
|||||
Net cash provided by financing activities
|
2,040,608
|
|
|
689,529
|
|
|
2,624,621
|
|
|
468,481
|
|
|
1,140,236
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(In thousands)
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Consolidated Adjusted EBITDA
(2)
|
$
|
1,539,031
|
|
|
$
|
928,039
|
|
|
$
|
387,535
|
|
|
$
|
449,245
|
|
|
$
|
398,334
|
|
(1)
|
For the years ended
December 31, 2018
,
2017
,
2016
,
2015
and
2014
, total stockholders’ equity excludes
$467.0 million
,
$326.9 million
,
$320.8 million
$233.0 million
and
$234.2 million
, respectively, of non-controlling interest related to Viper Energy Partners LP.
|
(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)
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Net income (loss)
|
$
|
944,895
|
|
|
$
|
516,757
|
|
|
$
|
(164,908
|
)
|
|
$
|
(547,790
|
)
|
|
$
|
195,971
|
|
Non-cash loss (gain) on derivative instruments, net
|
(221,732
|
)
|
|
84,240
|
|
|
26,522
|
|
|
112,918
|
|
|
(117,109
|
)
|
|||||
Interest expense, net
|
87,276
|
|
|
40,554
|
|
|
40,684
|
|
|
41,510
|
|
|
34,515
|
|
|||||
Depreciation, depletion and amortization
|
623,039
|
|
|
326,759
|
|
|
178,015
|
|
|
217,697
|
|
|
170,005
|
|
|||||
Impairment of oil and natural gas properties
|
—
|
|
|
—
|
|
|
245,536
|
|
|
814,798
|
|
|
—
|
|
|||||
Non-cash equity-based compensation expense
|
36,798
|
|
|
34,178
|
|
|
33,532
|
|
|
24,572
|
|
|
14,253
|
|
|||||
Capitalized equity-based compensation expense
|
(10,034
|
)
|
|
(8,641
|
)
|
|
(7,079
|
)
|
|
(6,043
|
)
|
|
(4,437
|
)
|
|||||
Asset retirement obligation accretion expense
|
2,132
|
|
|
1,391
|
|
|
1,064
|
|
|
833
|
|
|
467
|
|
|||||
Loss on revaluation of investment
|
550
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
33,134
|
|
|
—
|
|
|
—
|
|
|||||
Merger and integration expense
|
36,831
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Income tax (benefit) provision
|
168,362
|
|
|
(19,568
|
)
|
|
192
|
|
|
(201,310
|
)
|
|
108,985
|
|
|||||
Non-controlling interest in net (income) loss
|
(129,086
|
)
|
|
(47,631
|
)
|
|
843
|
|
|
(7,940
|
)
|
|
(4,316
|
)
|
|||||
Consolidated Adjusted EBITDA
|
$
|
1,539,031
|
|
|
$
|
928,039
|
|
|
$
|
387,535
|
|
|
$
|
449,245
|
|
|
$
|
398,334
|
|
|
Year Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Oil (MBbls)
|
72
|
%
|
|
74
|
%
|
|
73
|
%
|
Natural gas (MMcf)
|
12
|
%
|
|
12
|
%
|
|
11
|
%
|
Natural gas liquids (MBbls)
|
16
|
%
|
|
14
|
%
|
|
16
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
Year Ended December 31,
|
||||
|
2018
|
|
2017
|
|
2016
|
Oil (Bbls)/d
|
94,156
|
|
58,678
|
|
31,590
|
Natural gas (Mcf)/d
|
94,983
|
|
56,602
|
|
29,313
|
Natural gas liquids (Bbls)/d
|
20,453
|
|
11,112
|
|
6,556
|
Total average production per day
|
130,439
|
|
79,224
|
|
43,031
|
|
2018
|
|
2017
|
|
2016
|
|||
Estimated Net Proved Reserves:
|
|
|
|
|
|
|||
Oil (MBbls)
|
626,936
|
|
|
233,181
|
|
|
139,174
|
|
Natural gas (MMcf)
|
1,048,649
|
|
|
285,369
|
|
|
174,896
|
|
Natural gas liquids (MBbls)
|
190,291
|
|
|
54,609
|
|
|
37,134
|
|
Total (MBOE)
|
992,001
|
|
|
335,352
|
|
|
205,458
|
|
|
Unweighted Arithmetic Average
|
||||||||||
|
First-Day-of-the-Month Prices
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Oil (per Bbl)
|
$
|
59.63
|
|
|
$
|
48.03
|
|
|
$
|
39.94
|
|
Natural gas (per Mcf)
|
$
|
1.47
|
|
|
$
|
2.06
|
|
|
$
|
1.36
|
|
Natural gas liquids (per Bbl)
|
$
|
24.43
|
|
|
$
|
20.79
|
|
|
$
|
12.91
|
|
|
Year Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Revenues:
|
|
|
|
|
|
|||
Oil sales
|
88
|
%
|
|
88
|
%
|
|
89
|
%
|
Natural gas sales
|
3
|
%
|
|
4
|
%
|
|
4
|
%
|
Natural gas liquid sales
|
9
|
%
|
|
8
|
%
|
|
7
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Oil, natural gas and natural gas liquids
|
$
|
2,129,780
|
|
|
$
|
1,186,275
|
|
|
$
|
527,107
|
|
Lease bonus
|
2,920
|
|
|
11,764
|
|
|
—
|
|
|||
Midstream services
|
34,254
|
|
|
7,072
|
|
|
—
|
|
|||
Other operating income
|
9,302
|
|
|
—
|
|
|
—
|
|
|||
Total revenues
|
2,176,256
|
|
|
1,205,111
|
|
|
527,107
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Lease operating expenses
|
204,975
|
|
|
126,524
|
|
|
82,428
|
|
|||
Production and ad valorem taxes
|
132,661
|
|
|
73,505
|
|
|
34,456
|
|
|||
Gathering and transportation
|
26,113
|
|
|
12,834
|
|
|
11,606
|
|
|||
Midstream services
|
71,878
|
|
|
10,409
|
|
|
—
|
|
|||
Depreciation, depletion and amortization
|
623,039
|
|
|
326,759
|
|
|
178,015
|
|
|||
Impairment of oil and natural gas properties
|
—
|
|
|
—
|
|
|
245,536
|
|
|||
General and administrative expenses
|
64,554
|
|
|
48,669
|
|
|
42,619
|
|
|||
Asset retirement obligation accretion
|
2,132
|
|
|
1,391
|
|
|
1,064
|
|
|||
Merger & integration expense
|
36,831
|
|
|
—
|
|
|
—
|
|
|||
Other operating expense
|
3,285
|
|
|
—
|
|
|
—
|
|
|||
Total expenses
|
1,165,468
|
|
|
600,091
|
|
|
595,724
|
|
|||
Income (loss) from operations
|
1,010,788
|
|
|
605,020
|
|
|
(68,617
|
)
|
|||
Interest expense, net
|
(87,276
|
)
|
|
(40,554
|
)
|
|
(40,684
|
)
|
|||
Other income, net
|
88,996
|
|
|
10,235
|
|
|
3,064
|
|
|||
Gain (loss) on derivative instruments, net
|
101,299
|
|
|
(77,512
|
)
|
|
(25,345
|
)
|
|||
Loss on revaluation of investment
|
(550
|
)
|
|
—
|
|
|
—
|
|
|||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
(33,134
|
)
|
|||
Total other income (expense), net
|
102,469
|
|
|
(107,831
|
)
|
|
(96,099
|
)
|
|||
Income (loss) before income taxes
|
1,113,257
|
|
|
497,189
|
|
|
(164,716
|
)
|
|||
Provision for (benefit from) income taxes
|
168,362
|
|
|
(19,568
|
)
|
|
192
|
|
|||
Net income (loss)
|
944,895
|
|
|
516,757
|
|
|
(164,908
|
)
|
|||
Net income attributable to non-controlling interest
|
99,223
|
|
|
34,496
|
|
|
126
|
|
|||
Net income (loss) attributable to Diamondback Energy, Inc.
|
$
|
845,672
|
|
|
$
|
482,261
|
|
|
$
|
(165,034
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Production Data:
|
|
|
|
|
|
||||||
Oil (MBbls)
|
34,367
|
|
|
21,418
|
|
|
11,562
|
|
|||
Natural gas (MMcf)
|
34,669
|
|
|
20,660
|
|
|
10,728
|
|
|||
Natural gas liquids (MBbls)
|
7,465
|
|
|
4,056
|
|
|
2,399
|
|
|||
Combined volumes (MBOE)
|
47,610
|
|
|
28,917
|
|
|
15,749
|
|
|||
Daily combined volumes (BOE/d)
|
130,439
|
|
|
79,224
|
|
|
43,031
|
|
|||
|
|
|
|
|
|
||||||
Average Prices:
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
54.66
|
|
|
$
|
48.75
|
|
|
$
|
40.70
|
|
Natural gas (per Mcf)
|
1.76
|
|
|
2.53
|
|
|
2.10
|
|
|||
Natural gas liquids (per Bbl)
|
25.47
|
|
|
22.20
|
|
|
14.20
|
|
|||
Combined (per BOE)
|
44.73
|
|
|
41.02
|
|
|
33.47
|
|
|||
Oil, hedged ($ per Bbl)
(1)
|
51.20
|
|
|
48.94
|
|
|
40.80
|
|
|||
Natural gas, hedged ($ per MMbtu)
(1)
|
1.72
|
|
|
2.65
|
|
|
2.06
|
|
|||
Natural gas liquids, hedged ($ per Bbl)
(1)
|
25.46
|
|
|
—
|
|
|
—
|
|
|||
Average price, hedged ($ per BOE)
(1)
|
42.20
|
|
|
41.26
|
|
|
33.54
|
|
|||
|
|
|
|
|
|
||||||
Average Costs per BOE:
|
|
|
|
|
|
||||||
Lease operating expense
|
$
|
4.31
|
|
|
$
|
4.38
|
|
|
$
|
5.23
|
|
Production and ad valorem taxes
|
2.79
|
|
|
2.54
|
|
|
2.19
|
|
|||
Gathering and transportation expense
|
0.55
|
|
|
0.44
|
|
|
0.74
|
|
|||
General and administrative - cash component
|
0.79
|
|
|
0.80
|
|
|
1.03
|
|
|||
Total operating expense - cash
|
$
|
8.44
|
|
|
$
|
8.16
|
|
|
$
|
9.19
|
|
|
|
|
|
|
|
||||||
General and administrative - non-cash component
|
$
|
0.57
|
|
|
$
|
0.88
|
|
|
$
|
1.68
|
|
Depreciation, depletion and amortization
|
13.09
|
|
|
11.30
|
|
|
11.30
|
|
|||
Interest expense, net
|
1.83
|
|
|
1.40
|
|
|
2.58
|
|
|||
Merger and integration expense
|
0.77
|
|
|
—
|
|
|
—
|
|
|||
Total expenses
|
$
|
16.26
|
|
|
$
|
13.58
|
|
|
$
|
15.56
|
|
|
|
|
|
|
|
||||||
Average realized oil price ($/Bbl)
|
$
|
54.66
|
|
|
$
|
48.75
|
|
|
$
|
40.70
|
|
Average NYMEX ($/Bbl)
|
$
|
65.23
|
|
|
$
|
50.80
|
|
|
$
|
43.29
|
|
Differential to NYMEX
|
$
|
(10.57
|
)
|
|
$
|
(2.05
|
)
|
|
$
|
(2.59
|
)
|
Average realized oil price to NYMEX
|
84
|
%
|
|
96
|
%
|
|
94
|
%
|
|||
|
|
|
|
|
|
||||||
Average realized natural gas price ($/Mcf)
|
$
|
1.76
|
|
|
$
|
2.53
|
|
|
$
|
2.10
|
|
Average NYMEX ($/Mcf)
|
$
|
3.17
|
|
|
$
|
2.99
|
|
|
$
|
2.52
|
|
Differential to NYMEX
|
$
|
(1.41
|
)
|
|
$
|
(0.46
|
)
|
|
$
|
(0.42
|
)
|
Average realized natural gas price to NYMEX
|
56
|
%
|
|
85
|
%
|
|
83
|
%
|
|||
|
|
|
|
|
|
||||||
Average realized natural gas liquids price ($/Bbl)
|
$
|
25.47
|
|
|
$
|
22.20
|
|
|
$
|
14.20
|
|
Average NYMEX oil price ($/Bbl)
|
$
|
65.23
|
|
|
$
|
50.80
|
|
|
$
|
43.29
|
|
Average realized natural gas liquids price to NYMEX oil price
|
39
|
%
|
|
44
|
%
|
|
33
|
%
|
(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
|
$
|
5.92
|
|
|
34,367
|
|
|
$
|
203,383
|
|
|
Natural gas
|
$
|
(0.77
|
)
|
|
34,669
|
|
|
$
|
(26,567
|
)
|
|
Natural gas liquids
|
$
|
3.26
|
|
|
7,465
|
|
|
$
|
24,362
|
|
|
Total revenues due to change in price
|
|
|
|
|
$
|
201,178
|
|
||||
|
|
|
|
|
|
||||||
|
Change in production volumes
(1)
|
|
Prior period average prices
|
|
Total net dollar effect of change
|
||||||
|
|
|
|
|
(in thousands)
|
||||||
Effect of changes in production volumes:
|
|
|
|
|
|
||||||
Oil
|
12,949
|
|
|
$
|
48.75
|
|
|
$
|
631,225
|
|
|
Natural gas
|
14,009
|
|
|
$
|
2.53
|
|
|
$
|
35,403
|
|
|
Natural gas liquids
|
3,409
|
|
|
$
|
22.20
|
|
|
$
|
75,699
|
|
|
Total change in revenues
|
|
|
|
|
$
|
742,327
|
|
||||
|
|
|
|
|
$
|
943,505
|
|
(1)
|
Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands, except BOE amounts)
|
||||||
Depletion of proved oil and natural gas properties
|
$
|
594,750
|
|
|
$
|
321,870
|
|
Depreciation of midstream assets
|
18,803
|
|
|
3,451
|
|
||
Depreciation of other property and equipment
|
9,486
|
|
|
1,438
|
|
||
Depreciation, depletion and amortization expense
|
$
|
623,039
|
|
|
$
|
326,759
|
|
Oil and natural gas properties depreciation, depletion and amortization expense per BOE
|
$
|
12.62
|
|
|
$
|
11.11
|
|
|
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
|
$
|
0.43
|
|
|
20,660
|
|
|
$
|
8,884
|
|
|
Natural gas liquids
|
$
|
8.00
|
|
|
4,056
|
|
|
$
|
32,446
|
|
|
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
|
9,931
|
|
|
$
|
2.10
|
|
|
$
|
20,834
|
|
|
Natural gas liquids
|
1,656
|
|
|
$
|
14.20
|
|
|
$
|
23,521
|
|
|
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
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Net cash provided by operating activities
|
$
|
1,564,505
|
|
|
$
|
888,625
|
|
|
$
|
332,080
|
|
Net cash used in investing activities
|
(3,503,043
|
)
|
|
(3,132,282
|
)
|
|
(1,310,242
|
)
|
|||
Net cash provided by financing activities
|
2,040,608
|
|
|
689,529
|
|
|
2,624,621
|
|
|||
Net change in cash
|
$
|
102,070
|
|
|
$
|
(1,554,128
|
)
|
|
$
|
1,646,459
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Drilling, completion and infrastructure
|
$
|
(1,460,509
|
)
|
|
$
|
(792,599
|
)
|
|
$
|
(363,087
|
)
|
Additions to midstream assets
|
(204,222
|
)
|
|
(68,139
|
)
|
|
(1,188
|
)
|
|||
Acquisition of leasehold interests
|
(1,370,951
|
)
|
|
(1,960,591
|
)
|
|
(611,280
|
)
|
|||
Acquisition of mineral interests
|
(440,303
|
)
|
|
(407,450
|
)
|
|
(205,721
|
)
|
|||
Acquisition of midstream assets
|
—
|
|
|
(50,279
|
)
|
|
—
|
|
|||
Purchase of other property, equipment and land
|
(6,840
|
)
|
|
(22,779
|
)
|
|
(9,891
|
)
|
|||
Investment in real estate
|
(110,685
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from sale of assets
|
80,098
|
|
|
65,656
|
|
|
4,661
|
|
|||
Funds held in escrow
|
10,989
|
|
|
104,087
|
|
|
(121,391
|
)
|
|||
Equity investments
|
(612
|
)
|
|
(188
|
)
|
|
(2,345
|
)
|
|||
Purchase of other investments
|
(8
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash used in investing activities
|
$
|
(3,503,043
|
)
|
|
$
|
(3,132,282
|
)
|
|
$
|
(1,310,242
|
)
|
Financial Covenant
|
Required Ratio
|
Ratio of total net debt to EBITDAX, as defined in the credit agreement
|
Not greater than 4.0 to 1.0
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
Financial Covenant
|
Required Ratio
|
Ratio of total net debt to EBITDAX, as defined in the credit agreement
|
Not greater than 4.0 to 1.0
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
•
|
$2.3 billion
to
$2.55 billion
will be spent on drilling and completing
290
to
320
gross (
255
to
280
net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 9,400 feet;
|
•
|
$400.0 million
to
$450.0 million
will be spent on midstream infrastructure; and
|
•
|
$175.0 million
to
$200.0 million
will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.
|
|
Payments Due by Period
|
||||||||||||||||||
|
2019
|
|
2020-2021
|
|
2022-2023
|
|
Thereafter
|
|
Total
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Secured revolving credit facility
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,489,500
|
|
|
$
|
—
|
|
|
$
|
1,489,500
|
|
Interest expense related to the secured revolving credit facility
|
1,914
|
|
|
3,829
|
|
|
1,594
|
|
|
—
|
|
|
7,337
|
|
|||||
Senior notes
|
—
|
|
|
—
|
|
|
—
|
|
|
2,050,000
|
|
|
2,050,000
|
|
|||||
Interest expense related to
the senior notes
(2)
|
102,375
|
|
|
204,750
|
|
|
204,750
|
|
|
212,805
|
|
|
724,680
|
|
|||||
Viper's secured revolving credit facility
(1)
|
—
|
|
|
—
|
|
|
411,000
|
|
|
—
|
|
|
411,000
|
|
|||||
Interest and commitment fees under Viper's credit agreement
(3)
|
540
|
|
|
1,080
|
|
|
450
|
|
|
—
|
|
|
2,070
|
|
|||||
Asset retirement obligations
(4)
|
60
|
|
|
—
|
|
|
—
|
|
|
136,181
|
|
|
136,241
|
|
|||||
Drilling commitments
(5)
|
18,976
|
|
|
414
|
|
|
—
|
|
|
—
|
|
|
19,390
|
|
|||||
Sand supply agreements
|
9,000
|
|
|
18,000
|
|
|
11,250
|
|
|
—
|
|
|
38,250
|
|
|||||
Operating lease obligations
(6)
|
9,019
|
|
|
5,279
|
|
|
583
|
|
|
—
|
|
|
14,881
|
|
|||||
|
$
|
141,884
|
|
|
$
|
233,352
|
|
|
$
|
2,119,127
|
|
|
$
|
2,398,986
|
|
|
$
|
4,893,349
|
|
(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 and Energen Notes.
|
(3)
|
Includes only the minimum amount of interest and commitment fees due which, as of
December 31, 2018
, 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 future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note
7
—Asset Retirement Obligations of the Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.
|
(5)
|
Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on
December 31, 2018
.
|
(6)
|
Operating lease obligations represent future commitments for building, equipment and vehicle leases.
|
(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#
|
|
|
3.1
|
|
|
3.2
|
|
|
3.3
|
|
|
3.4
|
|
|
4.1
|
|
|
4.2
|
|
|
4.3
|
|
|
4.4*
|
|
|
4.5*
|
|
|
4.6
|
|
|
4.7
|
|
|
4.8*
|
|
|
4.9*
|
|
|
4.10
|
|
|
4.11
|
|
3. Exhibits
|
||
Exhibit Number
|
|
Description
|
4.12
|
|
|
4.13
|
|
|
10.1
|
|
|
10.2+
|
|
|
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
|
|
3. Exhibits
|
||
Exhibit Number
|
|
Description
|
10.17
|
|
|
10.18
|
|
|
10.19
|
|
|
10.20
|
|
|
10.21
|
|
|
10.22
|
|
|
10.23
|
|
|
10.24
|
|
|
10.25+
|
|
|
10.26+
|
|
|
10.27+
|
|
|
10.28+
|
|
|
10.29+
|
|
|
10.30+
|
|
|
21.1*
|
|
|
23.1*
|
|
3. Exhibits
|
||
Exhibit Number
|
|
Description
|
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 22, 2019
|
|
|
|
|
|
/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 22, 2019
|
Steven E. West
|
|
|
|
|
|
|
|
|
|
/s/ Travis D. Stice
|
|
Chief Executive Officer and Director
|
|
February 22, 2019
|
Travis D. Stice
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Michael P. Cross
|
|
Director
|
|
February 22, 2019
|
Michael P. Cross
|
|
|
|
|
|
|
|
|
|
/s/ Michael L. Hollis
|
|
President, Chief Operating Officer and Director
|
|
February 22, 2019
|
Michael L. Hollis
|
|
|
|
|
|
|
|
|
|
/s/ David L. Houston
|
|
Director
|
|
February 22, 2019
|
David L. Houston
|
|
|
|
|
|
|
|
|
|
/s/ Mark L. Plaumann
|
|
Director
|
|
February 22, 2019
|
Mark L. Plaumann
|
|
|
|
|
|
|
|
|
|
/s/ Melanie M. Trent
|
|
Director
|
|
February 22, 2019
|
Melanie M. Trent
|
|
|
|
|
|
|
|
|
|
/s/ Teresa L. Dick
|
|
Chief Financial Officer, Senior Vice President, and Assistant Secretary
|
|
February 22, 2019
|
Teresa L. Dick
|
|
(Principal Financial and Accounting Officer)
|
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands, except share amounts)
|
||||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
214,516
|
|
|
$
|
112,446
|
|
Accounts receivable:
|
|
|
|
||||
Joint interest and other, net
|
95,536
|
|
|
73,038
|
|
||
Oil and natural gas sales
|
296,525
|
|
|
158,575
|
|
||
Inventories
|
37,570
|
|
|
9,108
|
|
||
Derivative instruments
|
230,527
|
|
|
531
|
|
||
Prepaid expenses and other
|
50,347
|
|
|
4,903
|
|
||
Total current assets
|
925,021
|
|
|
358,601
|
|
||
Property and equipment:
|
|
|
|
||||
Oil and natural gas properties, full cost method of accounting ($9,669,977 and $4,105,865 excluded from amortization at December 31, 2018 and 2017, respectively)
|
22,299,182
|
|
|
9,232,694
|
|
||
Midstream assets
|
700,295
|
|
|
191,519
|
|
||
Other property, equipment and land
|
146,963
|
|
|
80,776
|
|
||
Accumulated depletion, depreciation, amortization and impairment
|
(2,774,465
|
)
|
|
(2,161,372
|
)
|
||
Net property and equipment
|
20,371,975
|
|
|
7,343,617
|
|
||
Funds held in escrow
|
—
|
|
|
6,304
|
|
||
Deferred tax asset
|
96,670
|
|
|
—
|
|
||
Investment in real estate, net
|
115,625
|
|
|
—
|
|
||
Other assets
|
86,396
|
|
|
62,463
|
|
||
Total assets
|
$
|
21,595,687
|
|
|
$
|
7,770,985
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable-trade
|
$
|
127,979
|
|
|
$
|
94,590
|
|
Accrued capital expenditures
|
495,089
|
|
|
221,256
|
|
||
Other accrued liabilities
|
253,272
|
|
|
92,512
|
|
||
Revenues and royalties payable
|
143,272
|
|
|
68,703
|
|
||
Derivative instruments
|
—
|
|
|
100,367
|
|
||
Total current liabilities
|
1,019,612
|
|
|
577,428
|
|
||
Long-term debt
|
4,464,338
|
|
|
1,477,347
|
|
||
Derivative instruments
|
15,192
|
|
|
6,303
|
|
||
Asset retirement obligations
|
136,181
|
|
|
20,122
|
|
||
Deferred income taxes
|
1,784,532
|
|
|
108,048
|
|
||
Other long-term liabilities
|
9,570
|
|
|
—
|
|
||
Total liabilities
|
7,429,425
|
|
|
2,189,248
|
|
||
Commitments and contingencies (Note 17)
|
|
|
|
|
|
||
Stockholders’ equity:
|
|
|
|
||||
Common stock, $0.01 par value, 200,000,000 shares authorized, 164,273,447 issued and outstanding at December 31, 2018; 200,000,000 shares authorized, 98,167,289 issued and outstanding at December 31, 2017
|
1,643
|
|
|
982
|
|
||
Additional paid-in capital
|
12,935,885
|
|
|
5,291,011
|
|
||
Retained earnings (accumulated deficit)
|
761,833
|
|
|
(37,133
|
)
|
||
Accumulated other comprehensive income
|
(74
|
)
|
|
—
|
|
||
Total Diamondback Energy, Inc. stockholders’ equity
|
13,699,287
|
|
|
5,254,860
|
|
||
Non-controlling interest
|
466,975
|
|
|
326,877
|
|
||
Total equity
|
14,166,262
|
|
|
5,581,737
|
|
||
Total liabilities and equity
|
$
|
21,595,687
|
|
|
$
|
7,770,985
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands, except per share amounts)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Oil sales
|
$
|
1,878,625
|
|
|
$
|
1,044,017
|
|
|
$
|
470,528
|
|
Natural gas sales
|
61,046
|
|
|
52,210
|
|
|
22,506
|
|
|||
Natural gas liquid sales
|
190,109
|
|
|
90,048
|
|
|
34,073
|
|
|||
Lease bonus
|
2,920
|
|
|
11,764
|
|
|
—
|
|
|||
Midstream services
|
34,254
|
|
|
7,072
|
|
|
—
|
|
|||
Other operating income
|
9,302
|
|
|
—
|
|
|
—
|
|
|||
Total revenues
|
2,176,256
|
|
|
1,205,111
|
|
|
527,107
|
|
|||
Costs and expenses:
|
|
|
|
|
|
||||||
Lease operating expenses
|
204,975
|
|
|
126,524
|
|
|
82,428
|
|
|||
Production and ad valorem taxes
|
132,661
|
|
|
73,505
|
|
|
34,456
|
|
|||
Gathering and transportation
|
26,113
|
|
|
12,834
|
|
|
11,606
|
|
|||
Midstream services
|
71,878
|
|
|
10,409
|
|
|
—
|
|
|||
Depreciation, depletion and amortization
|
623,039
|
|
|
326,759
|
|
|
178,015
|
|
|||
Impairment of oil and natural gas properties
|
—
|
|
|
—
|
|
|
245,536
|
|
|||
General and administrative expenses
|
64,554
|
|
|
48,669
|
|
|
42,619
|
|
|||
Asset retirement obligation accretion
|
2,132
|
|
|
1,391
|
|
|
1,064
|
|
|||
Merger and integration expense
|
36,831
|
|
|
—
|
|
|
—
|
|
|||
Other operating expense
|
3,285
|
|
|
—
|
|
|
—
|
|
|||
Total costs and expenses
|
1,165,468
|
|
|
600,091
|
|
|
595,724
|
|
|||
Income (loss) from operations
|
1,010,788
|
|
|
605,020
|
|
|
(68,617
|
)
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest expense, net
|
(87,276
|
)
|
|
(40,554
|
)
|
|
(40,684
|
)
|
|||
Other income, net
|
88,996
|
|
|
10,235
|
|
|
3,064
|
|
|||
Gain (loss) on derivative instruments, net
|
101,299
|
|
|
(77,512
|
)
|
|
(25,345
|
)
|
|||
Loss on revaluation of investment
|
(550
|
)
|
|
—
|
|
|
—
|
|
|||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
(33,134
|
)
|
|||
Total other income (expense), net
|
102,469
|
|
|
(107,831
|
)
|
|
(96,099
|
)
|
|||
Income (loss) before income taxes
|
1,113,257
|
|
|
497,189
|
|
|
(164,716
|
)
|
|||
Provision for (benefit from) income taxes
|
168,362
|
|
|
(19,568
|
)
|
|
192
|
|
|||
Net income (loss)
|
944,895
|
|
|
516,757
|
|
|
(164,908
|
)
|
|||
Net income attributable to non-controlling interest
|
99,223
|
|
|
34,496
|
|
|
126
|
|
|||
Net income (loss) attributable to Diamondback Energy, Inc.
|
$
|
845,672
|
|
|
$
|
482,261
|
|
|
$
|
(165,034
|
)
|
|
|
|
|
|
|
||||||
Earnings per common share:
|
|
|
|
|
|
||||||
Basic
|
$
|
8.09
|
|
|
$
|
4.95
|
|
|
$
|
(2.20
|
)
|
Diluted
|
$
|
8.06
|
|
|
$
|
4.94
|
|
|
$
|
(2.20
|
)
|
Weighted average common shares outstanding:
|
|
|
|
|
|
||||||
Basic
|
104,622
|
|
|
97,458
|
|
|
75,077
|
|
|||
Diluted
|
104,929
|
|
|
97,688
|
|
|
75,077
|
|
|
Year Ended December 31, 2018
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Net income
|
$
|
944,895
|
|
|
$
|
516,757
|
|
|
$
|
(164,908
|
)
|
Other comprehensive income:
|
|
|
|
|
|
||||||
Postretirement plans:
|
|
|
|
|
|
||||||
Current period change in fair value of postretirement plans, net of tax of $0, $0 and $0, respectively
|
(74
|
)
|
|
—
|
|
|
—
|
|
|||
Total other comprehensive income, net of tax
|
(74
|
)
|
|
—
|
|
|
—
|
|
|||
Comprehensive income (loss)
|
944,821
|
|
|
516,757
|
|
|
(164,908
|
)
|
|||
Comprehensive income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|||
Comprehensive income (loss) attributable to Diamondback Energy, Inc.
|
$
|
944,821
|
|
|
$
|
516,757
|
|
|
$
|
(164,908
|
)
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Retained Earnings (Accumulated Deficit)
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Non-Controlling Interest
|
|
|
||||||||||||||
|
Shares
|
Amount
|
|
|
|
|
|
Total
|
|||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||
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 vesting of restricted stock units
|
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 Brigham
|
7,686
|
|
77
|
|
|
809,096
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
809,173
|
|
||||||
Exercise of stock options and vesting of restricted stock units
|
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
|
|
||||||
Impact of adoption of ASU 2016-01, net of tax
|
|
—
|
|
|
—
|
|
|
(9,393
|
)
|
|
—
|
|
|
(6,671
|
)
|
|
(16,064
|
)
|
|||||||
Net proceeds from issuance of common units - Viper Energy Partners LP
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
303,121
|
|
|
303,121
|
|
|||||||
Unit-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,763
|
|
|
2,763
|
|
|||||||
Common shares issued for business combination
|
63,126
|
|
631
|
|
|
7,069,489
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,070,120
|
|
||||||
Stock options assumed in business combination
|
|
—
|
|
|
14,088
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,088
|
|
|||||||
Restricted stock units assumed in business combination
|
|
—
|
|
|
51,829
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
51,829
|
|
|||||||
Repurchased shares for tax withholding
|
(140
|
)
|
—
|
|
|
(14,460
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(14,460
|
)
|
||||||
Stock-based compensation
|
|
—
|
|
|
34,035
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
34,035
|
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Retained Earnings (Accumulated Deficit)
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Non-Controlling Interest
|
|
|
||||||||||||||
|
Shares
|
Amount
|
|
|
|
|
|
Total
|
|||||||||||||||||
Distribution to non-controlling interest
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(98,345
|
)
|
|
(98,345
|
)
|
|||||||
Common shares issued for Ajax
|
2,584
|
|
25
|
|
|
339,975
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
340,000
|
|
||||||
Dividend paid
|
|
—
|
|
|
—
|
|
|
(37,313
|
)
|
|
—
|
|
|
—
|
|
|
(37,313
|
)
|
|||||||
Exercise of unit options and awards of restricted stock
|
536
|
|
5
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
140
|
|
|
140
|
|
||||||
Other comprehensive income, net of tax
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(74
|
)
|
|
—
|
|
|
(74
|
)
|
|||||||
Change in ownership of consolidated subsidiaries, net
|
|
—
|
|
|
149,923
|
|
|
—
|
|
|
—
|
|
|
(160,133
|
)
|
|
(10,210
|
)
|
|||||||
Net income
|
|
—
|
|
|
—
|
|
|
845,672
|
|
|
—
|
|
|
99,223
|
|
|
944,895
|
|
|||||||
Balance December 31, 2018
|
164,273
|
|
$
|
1,643
|
|
|
$
|
12,935,885
|
|
|
$
|
761,833
|
|
|
$
|
(74
|
)
|
|
$
|
466,975
|
|
|
$
|
14,166,262
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
944,895
|
|
|
$
|
516,757
|
|
|
$
|
(164,908
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Provision for (benefit from) deferred income taxes
|
169,357
|
|
|
(20,567
|
)
|
|
—
|
|
|||
Impairment of oil and natural gas properties
|
—
|
|
|
—
|
|
|
245,536
|
|
|||
Asset retirement obligation accretion
|
2,132
|
|
|
1,391
|
|
|
1,064
|
|
|||
Depreciation, depletion and amortization
|
623,039
|
|
|
326,759
|
|
|
178,015
|
|
|||
Amortization of debt issuance costs
|
11,613
|
|
|
3,943
|
|
|
2,717
|
|
|||
Loss on early extinguishment of debt
|
—
|
|
|
—
|
|
|
33,134
|
|
|||
Change in fair value of derivative instruments
|
(221,732
|
)
|
|
84,240
|
|
|
26,522
|
|
|||
Income from equity investment
|
—
|
|
|
(657
|
)
|
|
(676
|
)
|
|||
Loss on revaluation of investment
|
550
|
|
|
—
|
|
|
—
|
|
|||
Equity-based compensation expense
|
26,764
|
|
|
25,537
|
|
|
26,453
|
|
|||
Loss (gain) on sale of assets, net
|
3,081
|
|
|
(455
|
)
|
|
(61
|
)
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
13,160
|
|
|
(97,611
|
)
|
|
(35,030
|
)
|
|||
Accounts receivable-related party
|
—
|
|
|
297
|
|
|
1,294
|
|
|||
Restricted cash
|
—
|
|
|
500
|
|
|
—
|
|
|||
Inventories
|
(14,774
|
)
|
|
(2,245
|
)
|
|
(255
|
)
|
|||
Prepaid expenses and other
|
24,688
|
|
|
(11,362
|
)
|
|
(709
|
)
|
|||
Accounts payable and accrued liabilities
|
(6,846
|
)
|
|
36,762
|
|
|
15,922
|
|
|||
Accounts payable and accrued liabilities-related party
|
—
|
|
|
(2
|
)
|
|
(216
|
)
|
|||
Income tax payable
|
(814
|
)
|
|
814
|
|
|
—
|
|
|||
Accrued interest
|
(22,203
|
)
|
|
(20,774
|
)
|
|
(3,161
|
)
|
|||
Revenues and royalties payable
|
11,595
|
|
|
45,298
|
|
|
6,439
|
|
|||
Net cash provided by operating activities
|
1,564,505
|
|
|
888,625
|
|
|
332,080
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Additions to oil and natural gas properties
|
(1,460,509
|
)
|
|
(792,599
|
)
|
|
(362,450
|
)
|
|||
Additions to oil and natural gas properties-related party
|
—
|
|
|
—
|
|
|
(637
|
)
|
|||
Additions to midstream assets
|
(204,222
|
)
|
|
(68,139
|
)
|
|
(1,188
|
)
|
|||
Purchase of other property, equipment and land
|
(6,840
|
)
|
|
(22,779
|
)
|
|
(9,891
|
)
|
|||
Acquisition of leasehold interests
|
(1,370,951
|
)
|
|
(1,960,591
|
)
|
|
(611,280
|
)
|
|||
Acquisition of mineral interests
|
(440,303
|
)
|
|
(407,450
|
)
|
|
(205,721
|
)
|
|||
Acquisition of midstream assets
|
—
|
|
|
(50,279
|
)
|
|
—
|
|
|||
Proceeds from sale of assets
|
80,098
|
|
|
65,656
|
|
|
4,661
|
|
|||
Investment in real estate
|
(110,685
|
)
|
|
—
|
|
|
—
|
|
|||
Funds held in escrow
|
10,989
|
|
|
104,087
|
|
|
(121,391
|
)
|
|||
Purchase of other investments
|
(8
|
)
|
|
—
|
|
|
—
|
|
|||
Equity investments
|
(612
|
)
|
|
(188
|
)
|
|
(2,345
|
)
|
|||
Net cash used in investing activities
|
(3,503,043
|
)
|
|
(3,132,282
|
)
|
|
(1,310,242
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from borrowings under credit facility
|
2,651,500
|
|
|
753,500
|
|
|
164,000
|
|
|||
Repayment under credit facility
|
(1,241,500
|
)
|
|
(383,500
|
)
|
|
(89,000
|
)
|
|||
Repayment on Energen's credit facility
|
(559,000
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from senior notes
|
1,062,000
|
|
|
—
|
|
|
1,000,000
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Repayment of senior notes
|
—
|
|
|
—
|
|
|
(450,000
|
)
|
|||
Premium on extinguishment of debt
|
—
|
|
|
—
|
|
|
(26,561
|
)
|
|||
Debt issuance costs
|
(25,461
|
)
|
|
(9,296
|
)
|
|
(15,063
|
)
|
|||
Public offering costs
|
(2,652
|
)
|
|
(510
|
)
|
|
(1,182
|
)
|
|||
Proceeds from public offerings
|
305,773
|
|
|
370,344
|
|
|
2,051,503
|
|
|||
Proceeds from exercise of unit options
|
140
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from exercise of stock options
|
—
|
|
|
358
|
|
|
498
|
|
|||
Repurchased shares for tax withholdings
|
(14,460
|
)
|
|
—
|
|
|
—
|
|
|||
Dividends to stockholders
|
(37,313
|
)
|
|
—
|
|
|
—
|
|
|||
Other postemployment benefit changes
|
(74
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions to non-controlling interest
|
(98,345
|
)
|
|
(41,367
|
)
|
|
(9,574
|
)
|
|||
Net cash provided by financing activities
|
2,040,608
|
|
|
689,529
|
|
|
2,624,621
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
102,070
|
|
|
(1,554,128
|
)
|
|
1,646,459
|
|
|||
Cash and cash equivalents at beginning of period
|
112,446
|
|
|
1,666,574
|
|
|
20,115
|
|
|||
Cash and cash equivalents at end of period
|
$
|
214,516
|
|
|
$
|
112,446
|
|
|
$
|
1,666,574
|
|
|
|
|
|
|
|
||||||
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
||||||
Interest paid, net of capitalized interest
|
$
|
113,932
|
|
|
$
|
57,668
|
|
|
$
|
38,177
|
|
Cash paid for income taxes
|
$
|
689
|
|
|
$
|
—
|
|
|
$
|
192
|
|
Supplemental disclosure of non-cash transactions:
|
|
|
|
|
|
||||||
Change in accrued capital expenditures
|
$
|
273,833
|
|
|
$
|
160,906
|
|
|
$
|
413
|
|
Capitalized stock-based compensation
|
$
|
10,034
|
|
|
$
|
8,641
|
|
|
$
|
7,079
|
|
Common stock issued for Ajax
|
$
|
340,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Common stock issued for Brigham
|
$
|
—
|
|
|
$
|
809,173
|
|
|
$
|
—
|
|
Common stock issued for business combination
(1)
|
$
|
7,136,037
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Asset retirement obligations acquired
|
$
|
111,197
|
|
|
$
|
2,432
|
|
|
$
|
3,696
|
|
(1)
|
Includes
$7,070,120
Common stock issued for business combination,
$14,088
for stock options assumed and
$51,829
for restricted stock units assumed.
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Prepaid insurance
|
$
|
4,303
|
|
|
$
|
1,273
|
|
Prepaid fees and licenses
|
2,944
|
|
|
2,250
|
|
||
Income tax receivable
|
37,858
|
|
|
—
|
|
||
Other
|
5,242
|
|
|
1,380
|
|
||
Total prepaid expenses and other
|
$
|
50,347
|
|
|
$
|
4,903
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
Liability for drilling costs prepaid by joint interest partners
|
$
|
16,182
|
|
|
$
|
30,320
|
|
Interest payable
|
25,748
|
|
|
6,770
|
|
||
Lease operating expenses payable
|
59,455
|
|
|
27,850
|
|
||
Ad valorem taxes payable
|
49,160
|
|
|
3,306
|
|
||
Current portion of asset retirement obligations
|
60
|
|
|
1,163
|
|
||
Other
|
102,667
|
|
|
23,103
|
|
||
Total other accrued liabilities
|
$
|
253,272
|
|
|
$
|
92,512
|
|
|
(In thousands)
|
||
Balance as of December 1, 2018
|
$
|
—
|
|
Other comprehensive loss before reclassifications
|
(74
|
)
|
|
Change in accumulated other comprehensive income
|
(74
|
)
|
|
Balance as of December 31, 2018
|
$
|
(74
|
)
|
|
(In thousands)
|
||
Consideration:
|
|
||
Fair value of the Company's common stock issued
|
$
|
7,136,037
|
|
Total consideration
|
$
|
7,136,037
|
|
|
|
||
Fair value of liabilities assumed:
|
|
||
Current liabilities
|
$
|
349,254
|
|
Asset retirement obligation
|
104,907
|
|
|
Long-term debt
|
1,087,244
|
|
|
Noncurrent derivative instruments
|
17,308
|
|
|
Deferred income taxes
|
1,402,834
|
|
|
Other long-term liabilities
|
6,087
|
|
|
Amount attributable to liabilities assumed
|
$
|
2,967,634
|
|
|
|
||
Fair value of assets acquired:
|
|
||
Total current assets
|
305,086
|
|
|
Oil and natural gas properties
|
9,270,692
|
|
|
Midstream assets
|
262,752
|
|
|
Investment in real estate
|
10,700
|
|
|
Other property, equipment and land
|
58,388
|
|
|
Asset retirement obligation
|
104,907
|
|
|
Other postretirement assets
|
2,944
|
|
|
Noncurrent income tax receivable, net
|
75,713
|
|
|
Other long term assets
|
12,489
|
|
|
Amount attributable to assets acquired
|
$
|
10,103,671
|
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands, except per share amounts)
|
||||||
Revenues
|
$
|
3,531,609
|
|
|
$
|
2,195,726
|
|
Income from operations
|
1,559,141
|
|
|
900,435
|
|
||
Net income
|
1,319,967
|
|
|
875,382
|
|
||
Basic earnings per common share
|
7.54
|
|
|
5.26
|
|
||
Diluted earnings per common share
|
7.53
|
|
|
5.24
|
|
|
Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands, except per share amounts)
|
||||||
Revenues
|
$
|
1,228,040
|
|
|
$
|
627,301
|
|
Income from operations
|
619,369
|
|
|
(12,812
|
)
|
||
Net income
|
472,649
|
|
|
(109,229
|
)
|
||
Basic earnings per common share
|
4.85
|
|
|
(1.45
|
)
|
||
Diluted earnings per common share
|
4.84
|
|
|
(1.45
|
)
|
|
Estimated Useful Lives
|
|
December 31, 2018
|
||
|
(Years)
|
|
(in thousands)
|
||
Buildings
|
30
|
|
$
|
92,349
|
|
Tenant improvements
|
15
|
|
4,160
|
|
|
Land
|
N/A
|
|
947
|
|
|
Land improvements
|
15
|
|
484
|
|
|
Total real estate assets
|
|
|
97,940
|
|
|
Less: accumulated depreciation
|
|
|
(3,970
|
)
|
|
Total investment in land and buildings, net
|
|
|
$
|
93,970
|
|
|
Weighted Average Useful Lives
|
|
December 31, 2018
|
||
|
(Months)
|
|
(in thousands)
|
||
In-place lease intangibles
|
45
|
|
$
|
10,866
|
|
Less: accumulated amortization
|
|
|
(3,076
|
)
|
|
In-place lease intangibles, net
|
|
|
7,790
|
|
|
Above-market lease intangibles
|
45
|
|
3,623
|
|
|
Less: accumulated amortization
|
|
|
(459
|
)
|
|
Above-market lease intangibles, net
|
|
|
3,164
|
|
|
Total intangible lease assets, net
|
|
|
$
|
10,954
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
Oil and natural gas properties:
|
|
|
|
||||
Subject to depletion
|
$
|
12,629,205
|
|
|
$
|
5,126,829
|
|
Not subject to depletion
|
9,669,977
|
|
|
4,105,865
|
|
||
Gross oil and natural gas properties
|
22,299,182
|
|
|
9,232,694
|
|
||
Accumulated depletion
|
(1,599,111
|
)
|
|
(1,009,893
|
)
|
||
Accumulated impairment
|
(1,143,498
|
)
|
|
(1,143,498
|
)
|
||
Oil and natural gas properties, net
|
19,556,573
|
|
|
7,079,303
|
|
||
Midstream assets
|
700,295
|
|
|
191,519
|
|
||
Other property, equipment and land
|
146,963
|
|
|
80,776
|
|
||
Accumulated depreciation
|
(31,856
|
)
|
|
(7,981
|
)
|
||
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment
|
$
|
20,371,975
|
|
|
$
|
7,343,617
|
|
|
|
|
|
||||
Balance of costs not subject to depletion:
|
|
|
|
||||
Incurred in 2018
|
$
|
6,223,817
|
|
|
|
||
Incurred in 2017
|
2,500,003
|
|
|
|
|||
Incurred in 2016
|
696,751
|
|
|
|
|||
Incurred in 2015
|
182,194
|
|
|
|
|||
Incurred in 2014
|
67,212
|
|
|
|
|||
Total not subject to depletion
|
$
|
9,669,977
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Asset retirement obligations, beginning of period
|
$
|
21,285
|
|
|
$
|
17,422
|
|
|
$
|
12,711
|
|
Additional liabilities incurred
|
2,843
|
|
|
1,526
|
|
|
637
|
|
|||
Liabilities acquired
|
111,197
|
|
|
2,432
|
|
|
3,696
|
|
|||
Liabilities settled
|
(1,788
|
)
|
|
(1,555
|
)
|
|
(711
|
)
|
|||
Accretion expense
|
2,132
|
|
|
1,391
|
|
|
1,064
|
|
|||
Revisions in estimated liabilities
|
572
|
|
|
69
|
|
|
25
|
|
|||
Asset retirement obligations, end of period
|
136,241
|
|
|
21,285
|
|
|
17,422
|
|
|||
Less current portion
|
60
|
|
|
1,163
|
|
|
1,288
|
|
|||
Asset retirement obligations - long-term
|
$
|
136,181
|
|
|
$
|
20,122
|
|
|
$
|
16,134
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
4.625% Notes due 2021
(1)
|
400,000
|
|
|
—
|
|
||
7.320% Medium-term Notes, Series A, due 2022
(1)
|
20,000
|
|
|
—
|
|
||
4.750 % Senior Notes due 2024
|
1,250,000
|
|
|
500,000
|
|
||
5.375 % Senior Notes due 2025
|
800,000
|
|
|
500,000
|
|
||
7.350% Medium-term Notes, Series A, due 2027
(1)
|
10,000
|
|
|
—
|
|
||
7.125% Medium-term Notes, Series B, due 2028
(1)
|
100,000
|
|
|
—
|
|
||
Unamortized debt issuance costs
|
(26,645
|
)
|
|
(13,153
|
)
|
||
Unamortized premium costs
|
10,483
|
|
|
—
|
|
||
Revolving credit facility
|
1,489,500
|
|
|
397,000
|
|
||
Partnership revolving credit facility
|
411,000
|
|
|
93,500
|
|
||
Total long-term debt
|
$
|
4,464,338
|
|
|
$
|
1,477,347
|
|
(1)
|
At the effective time of the Merger, Energen became a wholly owned subsidiary of the Company and remained the issuer of these notes (the “Energen Notes”).
|
Financial Covenant
|
Required Ratio
|
Ratio of total net debt to EBITDAX, as defined in the credit agreement
|
Not greater than 4.0 to 1.0
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
Financial Covenant
|
Required Ratio
|
Ratio of total net debt to EBITDAX, as defined in the credit agreement
|
Not greater than 4.0 to 1.0
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Interest expense
|
$
|
110,252
|
|
|
$
|
60,671
|
|
|
$
|
39,642
|
|
Less capitalized interest
|
(32,812
|
)
|
|
(22,097
|
)
|
|
—
|
|
|||
Other fees and expenses
|
10,403
|
|
|
2,160
|
|
|
1,426
|
|
|||
Total interest expense
|
$
|
87,843
|
|
|
$
|
40,734
|
|
|
$
|
41,068
|
|
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 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,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands, except per share amount)
|
||||||||||
Net income (loss) attributable to common stock
|
$
|
845,672
|
|
|
$
|
482,261
|
|
|
$
|
(165,034
|
)
|
Weighted average common shares outstanding
|
|
|
|
|
|
||||||
Basic weighted average common units outstanding
|
104,622
|
|
|
97,458
|
|
|
75,077
|
|
|||
Effect of dilutive securities:
|
|
|
|
|
|
||||||
Potential common shares issuable
|
307
|
|
|
230
|
|
|
—
|
|
|||
Diluted weighted average common shares outstanding
|
104,929
|
|
|
97,688
|
|
|
75,077
|
|
|||
Basic net income attributable to common stock
|
$
|
8.09
|
|
|
$
|
4.95
|
|
|
$
|
(2.20
|
)
|
Diluted net income attributable to common stock
|
$
|
8.06
|
|
|
$
|
4.94
|
|
|
$
|
(2.20
|
)
|
|
Year Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
|
(in thousands)
|
|||||||
Restricted stock units
|
14
|
|
|
46
|
|
|
244
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
General and administrative expenses
|
$
|
26,764
|
|
|
$
|
25,537
|
|
|
$
|
26,453
|
|
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties
|
10,034
|
|
|
8,641
|
|
|
7,079
|
|
|
Restricted Stock
Awards & Units |
|
Weighted Average Grant-Date
Fair Value |
|||
Unvested at December 31, 2017
|
243,577
|
|
|
$
|
90.88
|
|
Granted
(1)
|
292,842
|
|
|
$
|
120.30
|
|
Vested
|
(199,827
|
)
|
|
$
|
92.50
|
|
Forfeited
|
(12,368
|
)
|
|
$
|
102.41
|
|
Unvested at December 31, 2018
|
324,224
|
|
|
$
|
116.01
|
|
(1)
|
Includes
107,472
replacement awards granted in connection with the closing of the Energen merger on November 29, 2018.
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||||
|
Three-Year Performance Period
|
|
Two-Year Performance Period
|
|
Three-Year Performance Period
|
|
Two-Year Performance Period
|
|
Three-Year Performance Period
|
||||||||||
Grant-date fair value
|
$
|
170.45
|
|
|
$
|
162.13
|
|
|
$
|
168.73
|
|
|
$
|
103.41
|
|
|
$
|
102.35
|
|
Risk-free rate
|
1.99
|
%
|
|
1.27
|
%
|
|
1.59
|
%
|
|
0.86
|
%
|
|
1.10
|
%
|
|||||
Company volatility
|
35.90
|
%
|
|
39.32
|
%
|
|
41.14
|
%
|
|
41.91
|
%
|
|
42.16
|
%
|
|
Performance Restricted Stock Units
|
|
Weighted Average Grant-Date Fair Value
|
|||
Unvested at December 31, 2017
|
202,326
|
|
|
$
|
139.83
|
|
Granted
|
285,737
|
|
|
$
|
130.96
|
|
Vested
|
(291,860
|
)
|
|
$
|
81.21
|
|
Unvested at December 31, 2018
(1)
|
196,203
|
|
|
$
|
169.76
|
|
(1)
|
A maximum of
392,406
units could be awarded based upon the Company’s final TSR ranking.
|
|
Shares
|
|
Weighted Average Exercise Price
|
|||
Outstanding at November 29,2018
|
—
|
|
|
$
|
—
|
|
Granted
|
57,721
|
|
|
22.12
|
|
|
Outstanding at December 31, 2018
|
57,721
|
|
|
$
|
22.12
|
|
|
|
|
Weighted Average
|
|
|
|||||||
|
|
|
Exercise
|
|
Remaining
|
|
Intrinsic
|
|||||
|
Options
|
|
Price
|
|
Term
|
|
Value
|
|||||
|
|
|
|
|
(in years)
|
|
(in thousands)
|
|||||
Outstanding at November 29, 2018
|
—
|
|
|
$
|
—
|
|
|
|
|
|
||
Granted
(1)
|
332,387
|
|
|
$
|
95.04
|
|
|
|
|
|
||
Outstanding at December 31, 2018
|
332,387
|
|
|
$
|
95.04
|
|
|
2.82
|
|
$
|
14,088
|
|
|
|
|
|
|
|
|
|
|||||
Vested and Expected to vest at December 31, 2018
|
332,387
|
|
|
$
|
95.04
|
|
|
2.82
|
|
$
|
14,088
|
|
Exercisable at December 31, 2018
|
332,387
|
|
|
$
|
95.04
|
|
|
2.82
|
|
$
|
14,088
|
|
|
Phantom Units
|
|
Weighted Average Grant-Date
Fair Value |
|||
Unvested at December 31, 2017
|
105,439
|
|
|
$
|
17.10
|
|
Granted
|
127,402
|
|
|
$
|
25.54
|
|
Vested
|
(102,811
|
)
|
|
$
|
19.23
|
|
Forfeited
|
(4,977
|
)
|
|
$
|
29.71
|
|
Unvested at December 31, 2018
|
125,053
|
|
|
$
|
23.44
|
|
|
2014
|
||
Grant-date fair value
|
$
|
4.24
|
|
Expected volatility
|
36.0
|
%
|
|
Expected dividend yield
|
5.9
|
%
|
|
Expected term (in years)
|
3.0
|
|
|
Risk-free rate
|
0.99
|
%
|
|
|
|
Weighted Average
|
|
|
|||||||
|
Unit Options
|
|
Exercise Price
|
|
Remaining Term
|
|
Intrinsic Value
|
|||||
|
|
|
|
|
(in years)
|
|
(in thousands)
|
|||||
Outstanding at December 31, 2017
|
7,600
|
|
|
$
|
18.49
|
|
|
|
|
|
||
Exercised
|
(7,600
|
)
|
|
$
|
18.49
|
|
|
|
|
|
||
Outstanding at December 31, 2018
|
—
|
|
|
$
|
—
|
|
|
0.00
|
|
$
|
—
|
|
|
One Month Ended December 31, 2018
|
||
|
(in thousands)
|
||
Change in Benefit Obligation
|
|
||
Balance as of November 29, 2018
|
$
|
5,373
|
|
Service cost
|
1
|
|
|
Interest cost
|
19
|
|
|
Actuarial gain
|
(35
|
)
|
|
Plan amendments
|
—
|
|
|
Curtailment gain
|
—
|
|
|
Benefits paid
|
(7
|
)
|
|
Balance at December 31, 2018
|
$
|
5,351
|
|
|
|
||
Change in Plans' Assets
|
|
||
Fair value of plan assets at November 29, 2018
|
$
|
8,317
|
|
Actual return (loss) on plan assets
|
(90
|
)
|
|
Benefits paid
|
(7
|
)
|
|
Fair value of plan assets at December 31, 2018
|
$
|
8,220
|
|
Funded status of plans
|
$
|
2,869
|
|
|
One Month Ended December 31, 2018
|
||
|
(in thousands)
|
||
Amounts recognized on consolidated balance sheets:
|
|
||
Noncurrent assets recognized
|
$
|
2,869
|
|
Amounts recognized to accumulated other comprehensive income:
|
|
||
Prior service credit, net of taxes
|
$
|
—
|
|
Net actuarial loss, net of taxes
|
74
|
|
|
Total accumulated other comprehensive income
|
$
|
74
|
|
|
One Month Ended December 31, 2018
|
||
|
(in thousands)
|
||
Postretirement Benefit Plans
|
|
||
Components of net periodic benefit cost:
|
|
||
Service cost
|
$
|
1
|
|
Interest cost
|
19
|
|
|
Expected long-term return on assets
|
(19
|
)
|
|
Prior service cost amortization
|
—
|
|
|
Actuarial gain amortization
|
—
|
|
|
Settlement charge
|
—
|
|
|
Curtailment gain
|
—
|
|
|
Net periodic (income) expense
|
$
|
1
|
|
|
One Month Ended December 31, 2018
|
||
|
(in thousands)
|
||
Postretirement Benefit Plans
|
|
||
Net actuarial (gain) loss experienced during the year
|
$
|
74
|
|
Net actuarial loss recognized as expense
|
—
|
|
|
Prior service cost recognized as income
|
—
|
|
|
Prior service credit during the year
|
—
|
|
|
Prior service cost amortization
|
—
|
|
|
Total recognized in other comprehensive income
|
$
|
74
|
|
|
One Month Ended December 31, 2018
|
|
Postretirement Benefit Plans
|
|
|
Discount rate
|
4.55
|
%
|
Expected long-term return on plan assets
|
4.55
|
%
|
|
One Month Ended December 31, 2018
|
|
Discount rate
|
4.55
|
%
|
|
Target
|
As of
December 31, 2018 |
||
Asset category:
|
|
|
||
Equity securities
|
21
|
%
|
20
|
%
|
Debt securities
|
74
|
%
|
76
|
%
|
Other
|
5
|
%
|
4
|
%
|
Total
|
100
|
%
|
100
|
%
|
|
December 31, 2018
|
||||||||
(in thousands)
|
Level 1
|
Level 2
|
Total
|
||||||
United States equities
|
$
|
146
|
|
$
|
—
|
|
$
|
146
|
|
Global equities
|
1,461
|
|
—
|
|
1,461
|
|
|||
Fixed income
|
6,256
|
|
—
|
|
6,256
|
|
|||
Other
|
357
|
|
—
|
|
357
|
|
|||
Total
|
$
|
8,220
|
|
$
|
—
|
|
$
|
8,220
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Current income tax provision (benefit):
|
|
|
|
|
|
||||||
Federal
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
(999
|
)
|
|
999
|
|
|
192
|
|
|||
Total current income tax provision
|
(995
|
)
|
|
999
|
|
|
192
|
|
|||
Deferred income tax provision (benefit):
|
|
|
|
|
|
||||||
Federal
|
161,354
|
|
|
(21,720
|
)
|
|
(579
|
)
|
|||
State
|
8,003
|
|
|
1,153
|
|
|
579
|
|
|||
Total deferred income tax provision (benefit)
|
169,357
|
|
|
(20,567
|
)
|
|
—
|
|
|||
Total provision for (benefit from) income taxes
|
$
|
168,362
|
|
|
$
|
(19,568
|
)
|
|
$
|
192
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Income tax expense (benefit) at the federal statutory rate
(1)
|
$
|
233,784
|
|
|
$
|
174,016
|
|
|
$
|
(57,694
|
)
|
Impact of nontaxable noncontrolling interest
|
(5,107
|
)
|
|
(12,073
|
)
|
|
—
|
|
|||
Income tax benefit relating to change in statutory tax rate
|
—
|
|
|
(67,938
|
)
|
|
—
|
|
|||
State income tax expense (benefit), net of federal tax effect
|
7,769
|
|
|
3,413
|
|
|
770
|
|
|||
Non-deductible compensation
|
4,887
|
|
|
13,492
|
|
|
3,990
|
|
|||
Change in valuation allowance
|
150
|
|
|
(127,485
|
)
|
|
53,336
|
|
|||
Deferred taxes related to change in the Partnership's tax status
|
(72,787
|
)
|
|
—
|
|
|
—
|
|
|||
Other, net
|
(334
|
)
|
|
(2,993
|
)
|
|
(210
|
)
|
|||
Provision for (benefit from) income taxes
|
$
|
168,362
|
|
|
$
|
(19,568
|
)
|
|
$
|
192
|
|
(1)
|
The federal statutory rates for the
years ended December 31, 2018
,
2017
and
2016
were
21%
,
35%
and
35%
, respectively.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
Deferred tax assets
|
|
|
|
||||
Net operating loss and other carryforwards
|
154,408
|
|
|
74,997
|
|
||
Derivative instruments
|
—
|
|
|
22,918
|
|
||
Stock based compensation
|
7,021
|
|
|
942
|
|
||
The Partnership's investment in the Operating Company
|
94,468
|
|
|
—
|
|
||
Other
|
8,634
|
|
|
2,464
|
|
||
Deferred tax assets
|
264,531
|
|
|
101,321
|
|
||
Valuation allowance
|
(13,932
|
)
|
|
(104
|
)
|
||
Deferred tax assets, net of valuation allowance
|
250,599
|
|
|
101,217
|
|
||
Deferred tax liabilities
|
|
|
|
||||
Oil and natural gas properties and equipment
|
1,825,237
|
|
|
202,997
|
|
||
Midstream assets
|
66,728
|
|
|
6,268
|
|
||
Derivative instruments
|
46,496
|
|
|
—
|
|
||
Total deferred tax liabilities
|
1,938,461
|
|
|
209,265
|
|
||
Net deferred tax liabilities
|
$
|
1,687,862
|
|
|
$
|
108,048
|
|
|
December 31, 2018
|
|
|
(in thousands)
|
|
Balance at beginning of year
|
—
|
|
Increase resulting from tax positions acquired
|
7,111
|
|
Increase resulting from prior period tax positions
|
4
|
|
Increase resulting from current period tax positions
|
—
|
|
Balance at end of year
|
7,115
|
|
Less: Effects of temporary items
|
(4,666
|
)
|
Total that, if recognized, would impact the effective income tax rate as of the end of the year
|
2,449
|
|
|
2019
|
|
2020
|
||||||||
|
Volume (Bbls/MMBtu)
|
|
Fixed Price Swap (per Bbl/MMBtu)
|
|
Volume (Bbls/MMBtu)
|
|
Fixed Price Swap (per Bbl/MMBtu)
|
||||
Oil Swaps - WTI Cushing
|
10,638,000
|
|
$
|
61.07
|
|
|
0
|
|
$
|
—
|
|
Oil Swaps - WTI Magellan East Houston
|
1,270,000
|
|
$
|
72.39
|
|
|
0
|
|
$
|
—
|
|
Oil Swaps - BRENT
|
2,005,000
|
|
$
|
68.02
|
|
|
0
|
|
$
|
—
|
|
Oil Basis Swaps - WTI Cushing
|
17,012,000
|
|
$
|
(5.56
|
)
|
|
15,120,000
|
|
$
|
(1.21
|
)
|
Natural Gas Swaps - Henry Hub
|
25,550,000
|
|
$
|
3.06
|
|
|
0
|
|
$
|
—
|
|
Natural Gas Basis Swaps - Waha Hub
|
18,250,000
|
|
$
|
(1.60
|
)
|
|
0
|
|
$
|
—
|
|
Natural Gas Liquid Swaps - Mont Belvieu
|
2,760,000
|
|
$
|
27.30
|
|
|
0
|
|
$
|
—
|
|
|
January 2019 - December 2019
|
||||||||||
Oil Three-Way Collars
|
WTI Cushing
|
|
Brent
|
|
WTI Magellan East Houston
|
||||||
Volume (Bbls)
|
7,570,000
|
|
2,000,000
|
|
994,000
|
||||||
Short put price (per Bbl)
|
$
|
38.10
|
|
|
$
|
55.00
|
|
|
$
|
56.82
|
|
Floor price (per Bbl)
|
$
|
48.10
|
|
|
$
|
65.00
|
|
|
$
|
66.82
|
|
Ceiling price (per Bbl)
|
$
|
63.70
|
|
|
$
|
82.47
|
|
|
$
|
77.60
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
Gross amounts of assets presented in the Consolidated Balance Sheet
|
$
|
230,527
|
|
|
$
|
531
|
|
Net amounts of assets presented in the Consolidated Balance Sheet
|
230,527
|
|
|
531
|
|
||
|
|
|
|
||||
Gross amounts of liabilities presented in the Consolidated Balance Sheet
|
15,192
|
|
|
106,670
|
|
||
Net amounts of liabilities presented in the Consolidated Balance Sheet
|
$
|
15,192
|
|
|
$
|
106,670
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
Current assets: derivative instruments
|
$
|
230,527
|
|
|
$
|
531
|
|
Noncurrent assets: derivative instruments
|
—
|
|
|
—
|
|
||
Total assets
|
$
|
230,527
|
|
|
$
|
531
|
|
Current liabilities: derivative instruments
|
$
|
—
|
|
|
$
|
100,367
|
|
Noncurrent liabilities: derivative instruments
|
15,192
|
|
|
6,303
|
|
||
Total liabilities
|
$
|
15,192
|
|
|
$
|
106,670
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Change in fair value of open non-hedge derivative instruments
|
$
|
221,732
|
|
|
$
|
(84,240
|
)
|
|
$
|
(26,522
|
)
|
Gain (loss) on settlement of non-hedge derivative instruments
|
(120,433
|
)
|
|
6,728
|
|
|
1,177
|
|
|||
Gain (loss) on derivative instruments
|
$
|
101,299
|
|
|
$
|
(77,512
|
)
|
|
$
|
(25,345
|
)
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||
|
Level 1
|
Level 2
|
Level 3
|
|
Level 1
|
Level 2
|
Level 3
|
||||||||||||
|
(in thousands)
|
||||||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||||||
Investment
|
$
|
14,525
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Fixed price swaps
|
$
|
—
|
|
$
|
215,335
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
||||||||||||
Fixed price swaps
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
(106,139
|
)
|
$
|
—
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Carrying
|
|
|
|
Carrying
|
|
|
||||||||
|
Amount
|
|
Fair Value
|
|
Amount
|
|
Fair Value
|
||||||||
|
(in thousands)
|
||||||||||||||
Debt:
|
|
|
|
|
|
|
|
||||||||
Revolving credit facility
|
$
|
1,489,500
|
|
|
$
|
1,489,500
|
|
|
$
|
397,000
|
|
|
$
|
397,000
|
|
4.625% Notes due 2021
(1)
|
400,000
|
|
|
393,240
|
|
|
—
|
|
|
—
|
|
||||
7.320% Medium-term Notes, Series A, due 2022
(1)
|
20,000
|
|
|
20,780
|
|
|
—
|
|
|
—
|
|
||||
4.750% Senior Notes due 2024
|
1,250,000
|
|
|
1,203,900
|
|
|
500,000
|
|
|
501,855
|
|
||||
5.375% Senior Notes due 2025
|
800,000
|
|
|
782,000
|
|
|
500,000
|
|
|
515,000
|
|
||||
7.350% Medium-term Notes, Series A, due 2027
(1)
|
10,000
|
|
|
10,479
|
|
|
—
|
|
|
—
|
|
||||
7.125% Medium-term Notes, Series B, due 2028
(1)
|
100,000
|
|
|
102,329
|
|
|
—
|
|
|
—
|
|
||||
Partnership revolving credit facility
|
411,000
|
|
|
411,000
|
|
|
93,500
|
|
|
93,500
|
|
Year Ending December 31,
|
Drilling Rig Commitments
|
|
Sand Supply Agreement
|
|
Office and Equipment Leases
|
||||||
|
(in thousands)
|
||||||||||
2019
|
$
|
18,976
|
|
|
9,000
|
|
|
$
|
9,019
|
|
|
2020
|
414
|
|
|
9,000
|
|
|
3,827
|
|
|||
2021
|
—
|
|
|
9,000
|
|
|
1,452
|
|
|||
2022
|
—
|
|
|
9,000
|
|
|
583
|
|
|||
2023
|
—
|
|
|
2,250
|
|
|
—
|
|
|||
Thereafter
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total
|
$
|
19,390
|
|
|
$
|
38,250
|
|
|
$
|
14,881
|
|
|
Year ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Rent Expense
|
$
|
751
|
|
|
$
|
2,412
|
|
|
$
|
1,961
|
|
|
Volume (Bbls/MMBtu)
|
|
Fixed Price Swap (per Bbl/MMBtu)
|
||
January 2019 - December 2019
|
|
|
|
||
Oil Swaps - WTI Magellan East Houston
|
368,000
|
|
$
|
59.15
|
|
Oil Swaps - BRENT
|
275,000
|
|
$
|
61.90
|
|
Oil Basis Swaps - WTI Cushing
|
182,000
|
|
$
|
(4.15
|
)
|
Oil Basis Swaps - WTI Midland
|
364,000
|
|
$
|
(2.68
|
)
|
Natural Gas Swaps - Waha Hub
|
6,680,000
|
|
$
|
(1.47
|
)
|
|
January 2019 - June 2019
|
|
January 2020 - June 2020
|
||||
Oil Three-Way Collars
|
Brent
|
|
Brent
|
||||
Volume (Bbls)
|
368,000
|
|
732,000
|
||||
Short put price (per Bbl)
|
$
|
50.00
|
|
|
$
|
50.00
|
|
Floor price (per Bbl)
|
$
|
60.00
|
|
|
$
|
60.00
|
|
Ceiling price (per Bbl)
|
$
|
69.43
|
|
|
$
|
73.90
|
|
Condensed Consolidated Balance Sheet
|
|||||||||||||||||||
December 31, 2018
|
|||||||||||||||||||
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
83,791
|
|
|
$
|
108,049
|
|
|
$
|
22,676
|
|
|
$
|
—
|
|
|
$
|
214,516
|
|
Accounts receivable, net
|
—
|
|
|
353,238
|
|
|
38,823
|
|
|
—
|
|
|
392,061
|
|
|||||
Accounts receivable - related party
|
—
|
|
|
—
|
|
|
3,489
|
|
|
(3,489
|
)
|
|
—
|
|
|||||
Intercompany receivable
|
4,468,813
|
|
|
200,795
|
|
|
—
|
|
|
(4,669,608
|
)
|
|
—
|
|
|||||
Inventories
|
—
|
|
|
37,570
|
|
|
—
|
|
|
—
|
|
|
37,570
|
|
|||||
Other current assets
|
2,583
|
|
|
278,034
|
|
|
257
|
|
|
—
|
|
|
280,874
|
|
|||||
Total current assets
|
4,555,187
|
|
|
977,686
|
|
|
65,245
|
|
|
(4,673,097
|
)
|
|
925,021
|
|
|||||
Property and equipment:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas properties, at cost, full cost method of accounting
|
—
|
|
|
20,585,766
|
|
|
1,716,713
|
|
|
(3,297
|
)
|
|
22,299,182
|
|
|||||
Midstream assets
|
—
|
|
|
700,295
|
|
|
—
|
|
|
—
|
|
|
700,295
|
|
|||||
Other property, equipment and land
|
—
|
|
|
141,275
|
|
|
5,688
|
|
|
—
|
|
|
146,963
|
|
|||||
Accumulated depletion, depreciation, amortization and impairment
|
—
|
|
|
(2,513,893
|
)
|
|
(248,296
|
)
|
|
(12,276
|
)
|
|
(2,774,465
|
)
|
|||||
Net property and equipment
|
—
|
|
|
18,913,443
|
|
|
1,474,105
|
|
|
(15,573
|
)
|
|
20,371,975
|
|
|||||
Investment in subsidiaries
|
11,575,513
|
|
|
112,434
|
|
|
—
|
|
|
(11,687,947
|
)
|
|
—
|
|
|||||
Investment in real estate, net
|
—
|
|
|
115,625
|
|
|
—
|
|
|
—
|
|
|
115,625
|
|
|||||
Deferred tax asset
|
(213
|
)
|
|
—
|
|
|
96,883
|
|
|
—
|
|
|
96,670
|
|
|||||
Other assets
|
344
|
|
|
68,221
|
|
|
17,831
|
|
|
—
|
|
|
86,396
|
|
|||||
Total assets
|
$
|
16,130,831
|
|
|
$
|
20,187,409
|
|
|
$
|
1,654,064
|
|
|
$
|
(16,376,617
|
)
|
|
$
|
21,595,687
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Accounts payable-trade
|
$
|
—
|
|
|
$
|
127,979
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
127,979
|
|
Intercompany payable
|
—
|
|
|
4,673,097
|
|
|
—
|
|
|
(4,673,097
|
)
|
|
—
|
|
|||||
Other current liabilities
|
14,292
|
|
|
871,319
|
|
|
6,022
|
|
|
—
|
|
|
891,633
|
|
|||||
Total current liabilities
|
14,292
|
|
|
5,672,395
|
|
|
6,022
|
|
|
(4,673,097
|
)
|
|
1,019,612
|
|
|||||
Long-term debt
|
2,035,554
|
|
|
2,017,784
|
|
|
411,000
|
|
|
—
|
|
|
4,464,338
|
|
|||||
Derivative instruments
|
—
|
|
|
15,192
|
|
|
—
|
|
|
—
|
|
|
15,192
|
|
|||||
Asset retirement obligations
|
—
|
|
|
136,181
|
|
|
—
|
|
|
—
|
|
|
136,181
|
|
|||||
Deferred income taxes
|
381,698
|
|
|
1,402,834
|
|
|
—
|
|
|
—
|
|
|
1,784,532
|
|
|||||
Other long-term liabilities
|
—
|
|
|
9,570
|
|
|
—
|
|
|
—
|
|
|
9,570
|
|
|||||
Total liabilities
|
2,431,544
|
|
|
9,253,956
|
|
|
417,022
|
|
|
(4,673,097
|
)
|
|
7,429,425
|
|
|||||
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
||||||||||
Stockholders’ equity
|
13,699,287
|
|
|
10,933,453
|
|
|
542,102
|
|
|
(11,475,555
|
)
|
|
13,699,287
|
|
|||||
Non-controlling interest
|
—
|
|
|
—
|
|
|
694,940
|
|
|
(227,965
|
)
|
|
466,975
|
|
|||||
Total equity
|
13,699,287
|
|
|
10,933,453
|
|
|
1,237,042
|
|
|
(11,703,520
|
)
|
|
14,166,262
|
|
|||||
Total liabilities and equity
|
$
|
16,130,831
|
|
|
$
|
20,187,409
|
|
|
$
|
1,654,064
|
|
|
$
|
(16,376,617
|
)
|
|
$
|
21,595,687
|
|
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
|
|
|||||
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 Statement of Operations
|
||||||||||||||||||||
Year Ended December 31, 2018
|
||||||||||||||||||||
(In thousands)
|
||||||||||||||||||||
|
|
|
|
|
Non–
|
|
|
|
|
|||||||||||
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
|||||||||||
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|||||||||||
Oil sales
|
$
|
—
|
|
|
$
|
1,631,703
|
|
|
$
|
—
|
|
|
$
|
246,922
|
|
|
$
|
1,878,625
|
|
|
Natural gas sales
|
—
|
|
|
48,070
|
|
|
—
|
|
|
12,976
|
|
|
61,046
|
|
||||||
Natural gas liquid sales
|
—
|
|
|
167,346
|
|
|
—
|
|
|
22,763
|
|
|
190,109
|
|
||||||
Royalty income
|
—
|
|
|
—
|
|
|
282,661
|
|
|
(282,661
|
)
|
|
—
|
|
||||||
Lease bonus
|
—
|
|
|
—
|
|
|
6,029
|
|
|
(3,109
|
)
|
|
2,920
|
|
||||||
Midstream services
|
—
|
|
|
34,254
|
|
|
—
|
|
|
—
|
|
|
34,254
|
|
||||||
Other operating income
|
—
|
|
|
9,172
|
|
|
130
|
|
|
—
|
|
|
9,302
|
|
||||||
Total revenues
|
—
|
|
|
1,890,545
|
|
|
288,820
|
|
|
(3,109
|
)
|
|
2,176,256
|
|
||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|||||||||||
Lease operating expenses
|
—
|
|
|
204,975
|
|
|
—
|
|
|
—
|
|
|
204,975
|
|
||||||
Production and ad valorem taxes
|
—
|
|
|
113,613
|
|
|
19,048
|
|
|
—
|
|
|
132,661
|
|
||||||
Gathering and transportation
|
—
|
|
|
26,113
|
|
|
—
|
|
|
—
|
|
|
26,113
|
|
||||||
Midstream services
|
—
|
|
|
71,878
|
|
|
—
|
|
|
—
|
|
|
71,878
|
|
||||||
Depreciation, depletion and amortization
|
—
|
|
|
547,592
|
|
|
58,830
|
|
|
16,617
|
|
|
623,039
|
|
||||||
General and administrative expenses
|
28,490
|
|
|
30,569
|
|
|
7,955
|
|
|
(2,460
|
)
|
|
64,554
|
|
||||||
Merger & integration
|
18,476
|
|
|
18,355
|
|
|
—
|
|
|
—
|
|
|
36,831
|
|
||||||
Asset retirement obligation accretion
|
—
|
|
|
2,132
|
|
|
—
|
|
|
—
|
|
|
2,132
|
|
||||||
Other operating expense
|
—
|
|
|
3,285
|
|
|
—
|
|
|
—
|
|
|
3,285
|
|
||||||
Total costs and expenses
|
46,966
|
|
|
1,018,512
|
|
|
85,833
|
|
|
14,157
|
|
|
1,165,468
|
|
||||||
Income (loss) from operations
|
(46,966
|
)
|
|
872,033
|
|
|
202,987
|
|
|
(17,266
|
)
|
|
1,010,788
|
|
||||||
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|||||||||||
Interest expense, net
|
(43,482
|
)
|
|
(29,945
|
)
|
|
(13,849
|
)
|
|
—
|
|
|
(87,276
|
)
|
||||||
Other income (expense), net
|
1,463
|
|
|
88,069
|
|
|
1,924
|
|
|
(2,460
|
)
|
|
88,996
|
|
||||||
Loss on derivative instruments, net
|
—
|
|
|
101,299
|
|
|
—
|
|
|
—
|
|
|
101,299
|
|
||||||
Gain on revaluation of investment
|
—
|
|
—
|
|
—
|
|
|
(550
|
)
|
|
—
|
|
|
(550
|
)
|
|||||
Total other income (expense), net
|
(42,019
|
)
|
|
159,423
|
|
|
(12,475
|
)
|
|
(2,460
|
)
|
|
102,469
|
|
||||||
Income (loss) before income taxes
|
(88,985
|
)
|
|
1,031,456
|
|
|
190,512
|
|
|
(19,726
|
)
|
|
1,113,257
|
|
||||||
Provision for (benefit from) income taxes
|
240,727
|
|
|
—
|
|
|
(72,365
|
)
|
|
—
|
|
|
168,362
|
|
||||||
Net income (loss)
|
(329,712
|
)
|
|
1,031,456
|
|
|
262,877
|
|
|
(19,726
|
)
|
|
944,895
|
|
||||||
Net income attributable to non-controlling interest
|
—
|
|
|
—
|
|
|
118,919
|
|
|
(19,696
|
)
|
|
99,223
|
|
||||||
Net income (loss) attributable to Diamondback Energy, Inc.
|
$
|
(329,712
|
)
|
|
$
|
1,031,456
|
|
|
$
|
143,958
|
|
|
$
|
(30
|
)
|
|
$
|
845,672
|
|
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
|
—
|
|
|
—
|
|
|
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 (expense), 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 expense
|
—
|
|
|
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 Cash Flows
|
|||||||||||||||||||
Year Ended December 31, 2018
|
|||||||||||||||||||
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net cash provided by operating activities
|
$
|
(57,960
|
)
|
|
$
|
1,377,972
|
|
|
$
|
244,493
|
|
|
$
|
—
|
|
|
$
|
1,564,505
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Additions to oil and natural gas properties
|
—
|
|
|
(1,460,509
|
)
|
|
—
|
|
|
—
|
|
|
(1,460,509
|
)
|
|||||
Additions to midstream assets
|
—
|
|
|
(204,222
|
)
|
|
—
|
|
|
—
|
|
|
(204,222
|
)
|
|||||
Purchase of other property, equipment and land
|
—
|
|
|
(2,153
|
)
|
|
(4,687
|
)
|
|
—
|
|
|
(6,840
|
)
|
|||||
Acquisition of leasehold interests
|
—
|
|
|
(1,370,951
|
)
|
|
—
|
|
|
—
|
|
|
(1,370,951
|
)
|
|||||
Acquisition of mineral interests
|
—
|
|
|
169,828
|
|
|
(610,131
|
)
|
|
—
|
|
|
(440,303
|
)
|
|||||
Proceeds from sale of assets
|
—
|
|
|
79,533
|
|
|
565
|
|
|
—
|
|
|
80,098
|
|
|||||
Funds held in escrow
|
—
|
|
|
10,989
|
|
|
—
|
|
|
—
|
|
|
10,989
|
|
|||||
Purchase of other investments
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|||||
Equity investments
|
—
|
|
|
(612
|
)
|
|
—
|
|
|
—
|
|
|
(612
|
)
|
|||||
Intercompany transfers
|
(366,634
|
)
|
|
366,634
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Investment in real estate
|
—
|
|
|
(110,685
|
)
|
|
—
|
|
|
—
|
|
|
(110,685
|
)
|
|||||
Net cash used in investing activities
|
(366,634
|
)
|
|
(2,522,156
|
)
|
|
(614,253
|
)
|
|
—
|
|
|
(3,503,043
|
)
|
|||||
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Proceeds from borrowing under credit facility
|
—
|
|
|
1,960,000
|
|
|
691,500
|
|
|
—
|
|
|
2,651,500
|
|
|||||
Repayment under credit facility
|
—
|
|
|
(867,500
|
)
|
|
(374,000
|
)
|
|
—
|
|
|
(1,241,500
|
)
|
|||||
Repayment of Energen credit facility
|
—
|
|
|
(559,000
|
)
|
|
—
|
|
|
—
|
|
|
(559,000
|
)
|
|||||
Proceeds from senior notes
|
1,062,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,062,000
|
|
|||||
Debt issuance costs
|
(13,926
|
)
|
|
(10,496
|
)
|
|
(1,039
|
)
|
|
—
|
|
|
(25,461
|
)
|
|||||
Public offering costs
|
—
|
|
|
—
|
|
|
(2,652
|
)
|
|
—
|
|
|
(2,652
|
)
|
|||||
Proceeds from public offerings
|
—
|
|
|
—
|
|
|
305,773
|
|
|
—
|
|
|
305,773
|
|
|||||
Contributions to subsidiaries
|
(1,000
|
)
|
|
—
|
|
|
(1,000
|
)
|
|
2,000
|
|
|
—
|
|
|||||
Contributions by members
|
—
|
|
|
—
|
|
|
2,000
|
|
|
(2,000
|
)
|
|
—
|
|
|||||
Distributions from subsidiary
|
155,138
|
|
|
—
|
|
|
—
|
|
|
(155,138
|
)
|
|
—
|
|
|||||
Unit options exercised
|
—
|
|
|
—
|
|
|
140
|
|
|
—
|
|
|
140
|
|
|||||
Repurchased for tax withholdings
|
(14,460
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(14,460
|
)
|
|||||
Dividends to stockholders
|
(37,313
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(37,313
|
)
|
|||||
Other postemployment benefit changes
|
—
|
|
|
(74
|
)
|
|
—
|
|
|
—
|
|
|
(74
|
)
|
|||||
Distributions to non-controlling interest
|
—
|
|
|
—
|
|
|
(253,483
|
)
|
|
155,138
|
|
|
(98,345
|
)
|
|||||
Intercompany transfers
|
(696,128
|
)
|
|
695,128
|
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|||||
Net cash provided by financing activities
|
454,311
|
|
|
1,218,058
|
|
|
368,239
|
|
|
—
|
|
|
2,040,608
|
|
|||||
Net increase (decrease) in cash and cash equivalents
|
29,717
|
|
|
73,874
|
|
|
(1,521
|
)
|
|
—
|
|
|
102,070
|
|
|||||
Cash and cash equivalents at beginning of period
|
54,074
|
|
|
34,175
|
|
|
24,197
|
|
|
—
|
|
|
112,446
|
|
|||||
Cash and cash equivalents at end of period
|
$
|
83,791
|
|
|
$
|
108,049
|
|
|
$
|
22,676
|
|
|
$
|
—
|
|
|
$
|
214,516
|
|
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 under credit facility
|
—
|
|
|
475,000
|
|
|
278,500
|
|
|
—
|
|
|
753,500
|
|
|||||
Repayment under 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
|
|
|||||
Distributions from subsidiary
|
89,509
|
|
|
—
|
|
|
—
|
|
|
(89,509
|
)
|
|
—
|
|
|||||
Exercise of stock options
|
358
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
358
|
|
|||||
Distributions 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 under credit facility
|
—
|
|
|
—
|
|
|
164,000
|
|
|
—
|
|
|
164,000
|
|
|||||
Repayment under 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
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
Oil and natural gas properties:
|
|
|
|
||||
Proved properties
|
$
|
12,629,205
|
|
|
$
|
5,126,829
|
|
Unproved properties
|
9,669,977
|
|
|
4,105,865
|
|
||
Total oil and natural gas properties
|
22,299,182
|
|
|
9,232,694
|
|
||
Accumulated depreciation, depletion, amortization
|
(1,599,111
|
)
|
|
(1,009,893
|
)
|
||
Accumulated impairment
|
(1,143,498
|
)
|
|
(1,143,498
|
)
|
||
Net oil and natural gas properties capitalized
|
$
|
19,556,573
|
|
|
$
|
7,079,303
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Acquisition costs:
|
|
|
|
|
|
||||||
Proved properties
|
$
|
5,551,400
|
|
|
$
|
452,661
|
|
|
$
|
72,044
|
|
Unproved properties
|
5,818,006
|
|
|
2,692,000
|
|
|
752,117
|
|
|||
Development costs
|
493,084
|
|
|
145,362
|
|
|
47,575
|
|
|||
Exploration costs
|
1,090,281
|
|
|
779,728
|
|
|
329,122
|
|
|||
Capitalized asset retirement costs
|
113,717
|
|
|
2,682
|
|
|
4,030
|
|
|||
Total
|
$
|
13,066,488
|
|
|
$
|
4,072,433
|
|
|
$
|
1,204,888
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Oil, natural gas and natural gas liquid sales
|
$
|
2,129,780
|
|
|
$
|
1,186,275
|
|
|
$
|
527,107
|
|
Lease operating expenses
|
(204,975
|
)
|
|
(126,524
|
)
|
|
(82,428
|
)
|
|||
Production and ad valorem taxes
|
(132,661
|
)
|
|
(73,505
|
)
|
|
(34,456
|
)
|
|||
Gathering and transportation
|
(26,113
|
)
|
|
(12,834
|
)
|
|
(11,606
|
)
|
|||
Depreciation, depletion, and amortization
|
(594,750
|
)
|
|
(321,870
|
)
|
|
(176,369
|
)
|
|||
Impairment
|
—
|
|
|
—
|
|
|
(245,536
|
)
|
|||
Asset retirement obligation accretion expense
|
(2,132
|
)
|
|
(1,391
|
)
|
|
(1,064
|
)
|
|||
Income tax benefit (expense)
|
(241,149
|
)
|
|
19,568
|
|
|
(192
|
)
|
|||
Results of operations
|
$
|
928,000
|
|
|
$
|
669,719
|
|
|
$
|
(24,544
|
)
|
|
Oil
(MBbls) |
|
Natural Gas
Liquids (MBbls) |
|
Natural Gas
(MMcf) |
|||
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|||
As of January 1, 2016
|
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
|
|
Extensions and discoveries
|
143,256
|
|
|
33,152
|
|
|
154,088
|
|
Revisions of previous estimates
|
3,689
|
|
|
11,138
|
|
|
3,642
|
|
Purchase of reserves in place
|
281,333
|
|
|
98,865
|
|
|
640,761
|
|
Divestitures
|
(156
|
)
|
|
(8
|
)
|
|
(543
|
)
|
Production
|
(34,367
|
)
|
|
(7,465
|
)
|
|
(34,668
|
)
|
As of December 31, 2018
|
626,936
|
|
|
190,291
|
|
|
1,048,649
|
|
|
|
|
|
|
|
|||
Proved Developed Reserves:
|
|
|
|
|
|
|||
January 1, 2016
|
60,569
|
|
|
15,418
|
|
|
96,871
|
|
December 31, 2016
|
79,457
|
|
|
22,080
|
|
|
105,399
|
|
December 31, 2017
|
141,246
|
|
|
35,412
|
|
|
190,740
|
|
December 31, 2018
|
403,051
|
|
|
125,509
|
|
|
705,084
|
|
|
|
|
|
|
|
|||
Proved Undeveloped Reserves:
|
|
|
|
|
|
|||
January 1, 2016
|
45,409
|
|
|
10,586
|
|
|
52,632
|
|
December 31, 2016
|
59,717
|
|
|
15,054
|
|
|
69,497
|
|
December 31, 2017
|
91,935
|
|
|
19,198
|
|
|
94,629
|
|
December 31, 2018
|
223,885
|
|
|
64,782
|
|
|
343,565
|
|
|
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Future cash inflows
|
$
|
43,578,469
|
|
|
$
|
12,921,897
|
|
|
$
|
6,275,705
|
|
Future development costs
|
(3,560,142
|
)
|
|
(1,123,979
|
)
|
|
(617,636
|
)
|
|||
Future production costs
|
(7,727,257
|
)
|
|
(2,994,877
|
)
|
|
(1,392,852
|
)
|
|||
Future production taxes
|
(2,934,521
|
)
|
|
(928,891
|
)
|
|
(459,244
|
)
|
|||
Future income tax expenses
|
(3,913,024
|
)
|
|
(83,961
|
)
|
|
(75,595
|
)
|
|||
Future net cash flows
|
25,443,525
|
|
|
7,790,189
|
|
|
3,730,378
|
|
|||
10% discount to reflect timing of cash flows
|
(13,767,064
|
)
|
|
(4,033,130
|
)
|
|
(2,018,965
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
11,676,461
|
|
|
$
|
3,757,059
|
|
|
$
|
1,711,413
|
|
|
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
Unweighted Arithmetic Average
|
||||||||||
|
First-Day-of-the-Month Prices
|
||||||||||
Oil (per Bbl)
|
$
|
59.63
|
|
|
$
|
48.03
|
|
|
$
|
39.94
|
|
Natural gas (per Mcf)
|
$
|
1.47
|
|
|
$
|
2.06
|
|
|
$
|
1.36
|
|
Natural gas liquids (per Bbl)
|
$
|
24.43
|
|
|
$
|
20.79
|
|
|
$
|
12.91
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Standardized measure of discounted future net cash flows at the beginning of the period
|
$
|
3,757,059
|
|
|
$
|
1,711,413
|
|
|
$
|
1,418,133
|
|
Sales of oil and natural gas, net of production costs
|
(1,786,106
|
)
|
|
(986,246
|
)
|
|
(411,558
|
)
|
|||
Acquisition of reserves
|
5,520,438
|
|
|
439,396
|
|
|
43,142
|
|
|||
Divestiture of reserves
|
(2,036
|
)
|
|
(11,072
|
)
|
|
(5,481
|
)
|
|||
Extensions and discoveries, net of future development costs
|
3,287,043
|
|
|
1,791,686
|
|
|
779,359
|
|
|||
Previously estimated development costs incurred during the period
|
534,768
|
|
|
190,121
|
|
|
85,696
|
|
|||
Net changes in prices and production costs
|
1,805,428
|
|
|
577,781
|
|
|
(150,509
|
)
|
|||
Changes in estimated future development costs
|
(81,062
|
)
|
|
(52,908
|
)
|
|
20,647
|
|
|||
Revisions of previous quantity estimates
|
270,959
|
|
|
(98,857
|
)
|
|
(123,795
|
)
|
|||
Accretion of discount
|
379,659
|
|
|
174,185
|
|
|
143,134
|
|
|||
Net change in income taxes
|
(1,727,907
|
)
|
|
(9,074
|
)
|
|
(30,530
|
)
|
|||
Net changes in timing of production and other
|
(281,782
|
)
|
|
30,634
|
|
|
(56,825
|
)
|
|||
Standardized measure of discounted future net cash flows at the end of the period
|
$
|
11,676,461
|
|
|
$
|
3,757,059
|
|
|
$
|
1,711,413
|
|
|
2018
|
||||||||||||||
|
First
Quarter |
|
Second
Quarter |
|
Third
Quarter |
|
Fourth
Quarter |
||||||||
Revenues
|
$
|
480,195
|
|
|
$
|
526,273
|
|
|
$
|
538,029
|
|
|
$
|
631,759
|
|
Income from operations
|
267,646
|
|
|
281,303
|
|
|
266,851
|
|
|
194,988
|
|
||||
Income tax expense (benefit)
|
47,081
|
|
|
(6,607
|
)
|
|
42,276
|
|
|
85,612
|
|
||||
Net income
|
178,154
|
|
|
301,164
|
|
|
159,417
|
|
|
306,160
|
|
||||
Net income (loss) attributable to non-controlling interest
|
15,342
|
|
|
82,018
|
|
|
2,363
|
|
|
(500
|
)
|
||||
Net income attributable to Diamondback Energy, Inc.
|
$
|
162,812
|
|
|
$
|
219,146
|
|
|
$
|
157,054
|
|
|
$
|
306,660
|
|
Earnings per common share
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
1.65
|
|
|
$
|
2.22
|
|
|
$
|
1.59
|
|
|
$
|
2.50
|
|
Diluted
|
$
|
1.65
|
|
|
$
|
2.22
|
|
|
$
|
1.59
|
|
|
$
|
2.50
|
|
|
|
|
|
|
|
|
|
||||||||
|
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
|
|
SIDEWINDER MERGER SUB INC.
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
|
|
DIAMONDBACK ENERGY, INC.
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Chief Financial Officer, Executive Vice
|
|
President and Assistant Secretary
|
|
|
DIAMONDBACK O&G LLC
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
|
|
|
|
DIAMONDBACK E&P LLC
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
WELLS FARGO BANK, NATIONAL
|
|
ASSOCIATION, as Trustee
|
|
|
|
|
|
By:
|
/s/ John C. Stohlmann
|
Name:
|
John C. Stohlmann
|
Title:
|
Vice President
|
GUARANTEEING SUBSIDIARIES:
|
|
|
|
ENERGEN CORPORATION
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Treasurer and
|
|
Assistant Secretary
|
|
|
ENERGEN RESOURCES CORPORATION
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Chief Financial Officer, Executive Vice
|
|
President, Treasurer and Assistant Secretary
|
|
|
EGN SERVICES, INC.
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Chief Financial Officer, Executive Vice
|
|
President, Treasurer and Assistant Secretary
|
|
|
|
|
ISSUER:
|
|
|
|
DIAMONDBACK ENERGY, INC.
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Chief Financial Officer, Executive Vice
|
|
President and Assistant Secretary
|
OTHER GUARANTORS:
|
|
|
|
DIAMONDBACK O&G LLC
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
|
|
|
|
DIAMONDBACK E&P LLC
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
TRUSTEE:
|
|
|
|
WELLS FARGO BANK, NATIONAL
|
|
ASSOCIATION, as Trustee
|
|
|
|
|
|
By:
|
/s/ Tina D. Gonzalez
|
|
Authorized Signatory
|
SIDEWINDER MERGER SUB INC.
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
|
|
DIAMONDBACK ENERGY, INC.
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Chief Financial Officer, Executive Vice
|
|
President and Assistant Secretary
|
|
|
DIAMONDBACK O&G LLC
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
|
|
|
|
DIAMONDBACK E&P LLC
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
WELLS FARGO BANK, NATIONAL
|
|
ASSOCIATION, as Trustee
|
|
|
|
|
|
By:
|
/s/ John C. Stohlmann
|
Name:
|
John C. Stohlmann
|
Title:
|
Vice President
|
GUARANTEEING SUBSIDIARIES:
|
|
|
|
ENERGEN CORPORATION
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Treasurer and
|
|
Assistant Secretary
|
|
|
ENERGEN RESOURCES CORPORATION
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Chief Financial Officer, Executive Vice
|
|
President, Treasurer and Assistant Secretary
|
|
|
EGN SERVICES, INC.
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Chief Financial Officer, Executive Vice
|
|
President, Treasurer and Assistant Secretary
|
|
|
|
|
ISSUER:
|
|
|
|
DIAMONDBACK ENERGY, INC.
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Chief Financial Officer, Executive Vice
|
|
President and Assistant Secretary
|
OTHER GUARANTORS:
|
|
|
|
DIAMONDBACK O&G LLC
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
|
|
|
|
DIAMONDBACK E&P LLC
|
|
|
|
|
|
By:
|
/s/ Teresa L. Dick
|
Name:
|
Teresa L. Dick
|
Title:
|
Executive Vice President, Chief Financial
|
|
Officer and Assistant Secretary
|
TRUSTEE:
|
|
|
|
WELLS FARGO BANK, NATIONAL
|
|
ASSOCIATION, as Trustee
|
|
|
|
|
|
By:
|
/s/ Tina D. Gonzalez
|
|
Authorized Signatory
|
Name of Subsidiary
|
Jurisdiction of Incorporation
|
Diamondback E&P LLC
|
Delaware
|
Diamondback O&G LLC
|
Delaware
|
Energen Corporation
|
Delaware
|
Energen Resources Corporation
|
Delaware
|
EGN Services, Inc.
|
Delaware
|
Rattler Midstream GP LLC
|
Delaware
|
Rattler Midstream Operating LLC
|
Delaware
|
Rattler Midstream LP
|
Delaware
|
Tall City Towers 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 22, 2019
|
|
/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 22, 2019
|
|
/s/ Teresa L. Dick
|
|
|
|
Teresa L. Dick
|
|
|
|
Chief Financial Officer
|
|
|
|
|
Date:
|
February 22, 2019
|
|
/s/ Travis D. Stice
|
|
|
|
Travis D. Stice
|
|
|
|
Chief Executive Officer
|
|
|
|
|
Date:
|
February 22, 2019
|
|
/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, 2018
|
|
|
Proved
|
||||||||||
|
|
Developed
|
|
|
|
Total
|
||||||
|
|
Producing
|
|
Undeveloped
|
|
Proved
|
||||||
Net Reserves
|
|
|
|
|
|
|
||||||
Oil/Condensate – Mbbl
|
|
205,996
|
|
|
115,733
|
|
|
321,729
|
|
|||
Plant Products – Mbbl
|
|
52,441
|
|
|
27,510
|
|
|
79,951
|
|
|||
Gas – MMcf
|
|
242,413
|
|
|
122,388
|
|
|
364,801
|
|
|||
MBOE
|
|
298,839
|
|
|
163,641
|
|
|
462,480
|
|
|||
|
|
|
|
|
|
|
||||||
Income Data ($M)
|
|
|
|
|
|
|
||||||
Future Gross Revenue
|
|
|
$13,707,999
|
|
|
|
$7,621,094
|
|
|
|
$21,329,093
|
|
Deductions
|
|
3,139,769
|
|
|
2,571,423
|
|
|
5,711,192
|
|
|||
Future Net Income (FNI)
|
|
|
$10,568,230
|
|
|
|
$5,049,671
|
|
|
|
$15,617,901
|
|
|
|
|
|
|
|
|
||||||
Discounted FNI @ 10%
|
|
$
|
5,148,700
|
|
|
|
$1,963,704
|
|
|
$
|
7,112,404
|
|
Geographic Area
|
Product
|
Price
Reference
|
Average
Benchmark
Prices
|
Average Realized
Prices
|
North America
|
|
|
|
|
|
Oil/Condensate
|
WTI Cushing
|
$65.56/bbl
|
$61.55/bbl
|
United States
|
NGLs
|
WTI Cushing
|
$65.56/bbl
|
$26.58/bbl
|
|
Gas
|
Henry Hub
|
$3.10/MMBTU
|
$1.39/Mcf
|
(1)
|
completion intervals that are open at the time of the estimate but which have not yet started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
\s\ Val Rick Robinson
|
Val Rick Robinson, P.E.
|
TBPE License No. 105137
|
Managing Senior Vice President
|
As of December 31, 2018
|
|
|
Proved
|
||||||||||
|
|
Developed
|
|
Total
|
||||||||
|
|
Producing
|
|
Undeveloped
|
|
Proved
|
||||||
Net Reserves
|
|
|
|
|
|
|
||||||
Oil/Condensate – Mbbl
|
|
29,526
|
|
|
12,352
|
|
|
41,878
|
|
|||
Plant Products – Mbbl
|
|
7,965
|
|
|
3,027
|
|
|
10,992
|
|
|||
Gas – MMcf
|
|
49,681
|
|
|
11,916
|
|
|
61,597
|
|
|||
MBOE
|
|
45,771
|
|
|
17,365
|
|
|
63,136
|
|
|||
|
|
|
|
|
|
|
||||||
Income Data ($M)
|
|
|
|
|
|
|
||||||
Future Gross Revenue
|
|
|
$2,005,348
|
|
|
|
$809,368
|
|
|
|
$2,814,716
|
|
Deductions
|
|
38,298
|
|
|
14,111
|
|
|
52,409
|
|
|||
Future Net Income (FNI)
|
|
|
$1,967,050
|
|
|
|
$795,257
|
|
|
|
$2,762,307
|
|
|
|
|
|
|
|
|
||||||
Discounted FNI @ 10%
|
|
$
|
888,590
|
|
|
|
$377,914
|
|
|
|
$1,266,504
|
|
|
|
Discounted Future Net Income ($M)
|
||
|
|
As of December 31, 2018
|
||
Discount Rate
|
|
Total
|
|
|
Percent
|
|
Proved
|
|
|
|
|
|
|
|
5
|
|
$1,696,282
|
|
|
15
|
|
$1,034,055
|
|
|
20
|
|
$885,987
|
|
|
30
|
|
$704,359
|
|
Geographic Area
|
Product
|
Price
Reference
|
Average
Benchmark
Prices
|
Average Realized
Prices
|
North America
|
|
|
|
|
|
Oil/Condensate
|
WTI Cushing
|
$65.56/bbl
|
$61.46/bbl
|
United States
|
NGLs
|
WTI Cushing
|
$65.56/bbl
|
$25.04/bbl
|
|
Gas
|
Henry Hub
|
$3.10/MMBTU
|
$1.84/Mcf
|
(1)
|
completion intervals that are open at the time of the estimate but which have not yet started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|