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FANG Diamondback Energy

Filed: 26 Feb 20, 7:00pm

     
     
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
    
OR
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-35700 
 
Diamondback Energy, Inc.
(Exact Name of Registrant As Specified in Its Charter)
 
DE 45-4502447
(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification Number)
   
500 West Texas  
Suite 1200  
Midland,TX 79701
(Address of principal executive offices) (Zip code)

(Registrant Telephone Number, Including Area Code): (432) 221-7400
  Securities registered pursuant to Section 12(b) of the Act:  
 Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered 
 Common Stock, par value $0.01 per share FANG The Nasdaq Stock Market LLC 
     (NASDAQ Global Select Market) 
  Securities registered pursuant to Section 12(g) of the Act: None  

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes     No  
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes      No  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes      No  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
Large Accelerated Filer  Accelerated Filer 
Non-Accelerated Filer  Smaller Reporting Company 
    Emerging Growth Company 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No  
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 28, 2019 was approximately $15.9 billion.
As of February 14, 2020, 158,284,486 shares of the registrant’s common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2020 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K
     
     




DIAMONDBACK ENERGY, INC.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2019
TABLE OF CONTENTS
 







GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a glossary of certain oil and natural gas industry terms used in this report:
3-D seismicGeophysical 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.
BasinA large depression on the earth’s surface in which sediments accumulate.
BblStock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
Bbls/dBarrels per day.
BOEBarrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/dBarrels of oil equivalent per day.
BrentBrent sweet light crude oil.
British Thermal Unit or BTUThe quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
CompletionThe 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.
CondensateLiquid hydrocarbons associated with the production that is primarily natural gas.
Crude oilLiquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Developed acreageAcreage assignable to productive wells.
Development costsCapital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
DifferentialAn 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 wellA 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 EUREstimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
ExploitationA 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.
FieldAn 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 costsCapital 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.
FracturingThe 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 wellsThe total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drillingA 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 wellsWells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
Mb/dThousand barrels per day.
MBblsThousand barrels of crude oil or other liquid hydrocarbons.
MBOEOne 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.
McfThousand cubic feet of natural gas.
Mcf/dThousand cubic feet of natural gas per day.
Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtuMillion British Thermal Units.

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MMcfMillion cubic feet of natural gas.
Net acres or net wellsThe sum of the fractional working interest owned in gross acres.
Net revenue interestAn owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
Net royalty acresGross acreage multiplied by the average royalty interest.
Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.
OperatorThe individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
PlayA 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 abandonmentRefers 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.
PUDProved undeveloped.
Productive wellA 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.
ProspectA 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 reservesReserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reservesThe 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 reservesProved 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.
RecompletionThe 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.
ReservesReserves 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).
ReservoirA 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 playA 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 interestAn 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.
SpacingThe 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.
Tight formationA formation with low permeability that produces natural gas with very low flow rates for long periods of time.
Undeveloped acreageLease 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.

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Working interestAn 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.
WTIWest Texas Intermediate.
WTI MEHWest Texas Intermediate Magellan East Houston.
WTLWest Texas Light


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GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this report.
ASUAccounting Standards Update
CompanyDiamondback Energy, Inc., a Delaware corporation, together with its subsidiaries.
Dodd-Frank ActDodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173).
EPAU.S. Environmental Protection Agency.
Equity PlanThe Company’s Equity Incentive Plan.
Exchange ActThe Securities Exchange Act of 1934, as amended.
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission.
GAAPAccounting principles generally accepted in the United States.
2024 IndentureThe 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 IndentureThe 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.
December 2019 Notes IndentureThe indenture relating to the December 2019 Notes dated as of December 5, 2019, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
NYMEXNew York Mercantile Exchange.
OSHAFederal Occupational Safety and Health Act.
RattlerRattler Midstream LP, a Delaware limited partnership.
Rattler’s general partnerRattler Midstream GP LLC, a Delaware limited liability company; the general partner of Rattler Midstream LP and a wholly-owned subsidiary of the Company.
Rattler LLCRattler Midstream Operating LLC, a Delaware limited liability company and a subsidiary of Rattler.
Rattler LTIPRattler Midstream LP Long-Term Incentive Plan.
Rattler OfferingRattler’s initial public offering.
Rattler’s Partnership AgreementThe first amended and restated agreement of limited partnership, dated May 28, 2019.
Ryder ScottRyder Scott Company, L.P.
SECSecurities and Exchange Commission.
Securities ActThe Securities Act of 1933, as amended.
2024 Senior NotesThe Company’s 4.750% senior unsecured notes due 2024 in the aggregate principal amount of $1,250 million.
2025 Senior NotesThe Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 million.
Senior NotesThe 2024 Senior Notes, the 2025 Senior Notes and the Series of Senior Notes
December 2019 NotesThe Company’s 2.875% senior unsecured notes due 2024 in the aggregate principal amount of $1.0 billion, the Company’s 3.250% senior unsecured notes due 2026 in the aggregate principal amount of $800 million and the Company’s 3.500% senior unsecured notes due 2029 in the aggregate principal amount of $1.2 billion.
ViperViper Energy Partners LP, a Delaware limited partnership.
Viper’s general partnerViper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
Viper LLCViper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
Viper LTIPViper Energy Partners LP Long Term Incentive Plan.
Viper OfferingViper’s initial public offering.
Viper’s Partnership AgreementThe second amended and restated agreement of limited partnership, dated May 9, 2018, as amended as of May 10, 2018.
Wells FargoWells Fargo Bank, National Association.
WexfordWexford Capital LP


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this Annual Report on Form 10–K, including under Part I, Item 1A. “Risk Factors” in this report, could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about our:

business strategy;
exploration and development drilling prospects, inventories, projects and programs;
oil and natural gas reserves;
competition in the oil and natural gas industry;
acquisitions;
our recently completed drop-down transaction with our subsidiary Viper Energy Partners LP, or Viper;
identified drilling locations;
ability to obtain permits and governmental approvals;
technology;
financial strategy;
realized oil and natural gas prices and effects of hedging arrangements;
levels of production;
the impact of reduced drilling activity;
regional supply and demand factors, delays or interruptions of production;
lease operating expenses, general and administrative costs and finding and development costs;
future operating results;
conditions in the capital markets and our ability to obtain capital on favorable terms or at all;
general economic business or industry conditions;
capital expenditure plans; and
other plans, objectives, expectations and intentions.

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All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.


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PART I
Except as noted, in this Annual Report on Form 10-K, we refer to Diamondback, together with its consolidated subsidiaries, as “we,” “us,” “our,” or “the Company”. This report includes certain terms commonly used in the oil and gas industry, which are defined above in the “Glossary of Oil and Natural Gas Terms.”

ITEM 1. BUSINESS AND PROPERTIES

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators.

We began operations in December 2007 with our acquisition of 4,174 net acres in the Permian Basin. At December 31, 2019, our total acreage position in the Permian Basin was approximately 455,378 gross (382,337 net) acres, which consisted primarily of approximately 218,138 gross (195,461 net) acres in the Midland Basin and approximately 196,171 gross (155,296 net) acres in the Delaware Basin. In addition, our publicly traded subsidiary Viper Energy Partners LP, which we refer to as Viper, owns mineral interests underlying approximately 814,224 gross acres and 24,304 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 50% of these net royalty acres are operated by us. We own Viper Energy Partners GP LLC, the general partner of Viper, which we refer to as Viper’s general partner, and we own approximately 58% of the limited partner interest in Viper. Further, our publicly traded subsidiary Rattler Midstream Partners LP, which we refer to as Rattler, is focused on ownership, operation, development and acquisition of midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. We own Rattler Midstream GP LLC, the general partner of Rattler, which we refer to as Rattler’s general partner, and we own approximately 71% of the limited partner interest in Rattler. As of December 31, 2019, Rattler owned and operated 867 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays our seven core Midland and Delaware Basin development areas. To facilitate the transportation of produced water and hydrocarbon volumes away from the producing wellhead to ensuring the efficient operations of a crude oil or natural gas well, Rattler’s midstream infrastructure includes a network of gathering pipelines that collect and transport crude oil, natural gas and produced water from our operations in the Midland and Delaware Basins.

Our activities are primarily focused on horizontal development of the Spraberry and Wolfcamp formations of the Midland Basin and the Wolfcamp and Bone Spring formations of the Delaware Basin, both of which are part of the larger Permian Basin in West Texas and New Mexico. The Permian Basin is characterized by high oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates.

As of December 31, 2019, our estimated proved oil and natural gas reserves were 1,127,575 MBOE (which includes estimated reserves of 88,946 MBOE attributable to the mineral interests owned by Viper), based on reserve reports prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers. Of these reserves, approximately 67% are classified as proved developed producing. Proved undeveloped, or PUD, reserves included in this estimate are from 477 gross (434 net) horizontal well locations in which we have a working interest, and 22 horizontal wells in which we own only a mineral interest through our subsidiary, Viper. As of December 31, 2019, our estimated proved reserves were approximately 63% oil, 20% natural gas liquids and 17% natural gas.

Based on our evaluation of applicable geologic and engineering data, we currently have approximately 12,310 gross (8,141 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $60.00 per Bbl WTI. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through additional acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

Significant 2019 Transactions

Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen

On May 23, 2019, we completed our divestiture of 6,589 net acres of certain non-core Permian assets, which we acquired in our November 2018 merger with Energen Corporation, which we refer to as the Energen merger, for an aggregate sale price of $37 million.


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On July 1, 2019, we completed our divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which we acquired in the Energen merger, for an aggregate sale price of $285 million.

Drop-Down
On October 1, 2019, we completed a transaction to divest certain mineral and royalty interests to Viper for approximately 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits, which we refer to as the Drop-Down. The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by us, and have an average net royalty interest of approximately 3.2%.
Rattler’s Initial Public Offering

In May 2019, Rattler completed its initial public offering, which we refer to as the Rattler Offering, of an aggregate 43,700,000 common units at a price to the public of $17.50 per share, which common units are traded on the Nasdaq Global Select Market under the symbol “RTLR.” Rattler received aggregate net proceeds of approximately $720 million from the sale of these common units, after deducting the underwriting discount and offering expenses.

Our Business Strategy

Our business strategy is to continue to profitably grow our business through the following:

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. 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. The following table presents horizontal wells in which we have an interest in as of December 31, 2019:
BasinNumber of Horizontal Wells
Midland1,125
Delaware645
Total(1)
1,770
(1) Of these 1,770 total horizontal wells, we are the operator of 1,489 producing wells and have a non-operated working interest in 281 additional wells.


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The following table presents the average number of days in which we were able to drill our horizontal wells to total depth specified below during the year ended December 31, 2019:
 Average Days to Total Depth
Midland Basin 
7,500 foot lateral14
10,000 foot lateral15
13,000 foot lateral17
Delaware Basin 
7,500 foot lateral20
10,000 foot lateral25
13,000 foot lateral27

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 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 97% of our acreage. This operational control allows us to manage more efficiently the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development. Our average 84% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies.

Pursue strategic acquisitions with substantial resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential. Our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We regularly review acquisition opportunities and intend to pursue acquisitions that meet our strategic and financial targets.

Maintain financial flexibility. We seek to maintain a conservative financial position. As of December 31, 2019, our borrowing base was set at $2.0 billion and we had $1.99 billion available for borrowing. As of December 31, 2019, Viper LLC had $97 million in outstanding borrowings, and $678 million available for borrowing, under its revolving credit facility. As of December 31, 2019, Rattler LLC had $424 million in outstanding borrowings, and $176 million available for borrowing, under its revolving credit facility.

Our Strengths

We believe that the following strengths will help us achieve our business goals:

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, 2019 was approximately 66% oil, 18% natural gas liquids and 16% natural gas. As of December 31, 2019, our

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estimated net proved reserves were comprised of approximately 63% oil, 20% natural gas liquids and 17% 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 12,310 gross (8,141 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 7,975 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. 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 3,413 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.

The following table presents the number of identified economic potential horizontal drilling locations by basin:
 Number of Identified Economic Potential Horizontal Drilling Locations
Midland Basin 
Lower Spraberry(1)
1,231
Middle Spraberry(2)
1,151
Wolfcamp A(3)
1,205
Wolfcamp B(4)
1,213
Other2,237
Total Midland Basin7,037
Delaware Basin 
2nd Bone Springs(5)
957
3rd Bone Springs(5)
1,177
Wolfcamp A(6)
944
Wolfcamp B(6)
1,050
Other1,145
Total Delaware Basin5,273
Total12,310
(1)Our current location count 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.
(2)Our current location count is based on 660 foot spacing in Midland, Martin and northeast Andrews counties, depending on the prospect area and 880 foot spacing in all other counties.
(3)Our current location count 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.
(4)Our current location count in 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.
(5)Our current location count is based on 880 foot to 1,320 foot spacing.
(6)Our current location count is based on 880 foot to 1,056 foot spacing.

Experienced, incentivized and proven management team. Our executive team has an average of over 25 years of industry experience per person, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with both drilling and completing horizontal wells in addition to horizontal well reservoir and geologic expertise, which is of strategic importance as we expand our horizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.


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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 97% 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.

Access to Midstream Infrastructure and Gathering and Transportation Pipelines. Through our publicly traded subsidiary Rattler, we have secured access to midstream infrastructure and crude oil gathering and transportation pipelines tailored to our expected production growth ramp in order to allow us the operational flexibility to execute on our growth plan. Rattler is the primary provider of midstream services to us with an acreage dedication that spans a total of approximately 397,000 gross acres across all of Rattler’s service lines and over the core of the Midland and Delaware Basins.

Our Properties

Location and Land

Our total acreage position in the Permian Basin was approximately 455,378 gross (382,337 net) acres, which consisted primarily of approximately 218,138 gross (195,461 net) acres in the Midland Basin and approximately 196,171 gross (155,296 net) acres in the Delaware Basin at December 31, 2019. We are the operator of approximately 97% of this Permian Basin acreage. In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 814,224 gross acres and 24,304 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 50% of these net royalty acres are operated by us.

Further, our subsidiary Rattler is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. As of December 31, 2019, Rattler owned and operated 867 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays our seven core Midland and Delaware Basin development areas. To facilitate the transportation of water and hydrocarbon volumes away from the producing wellhead to ensuring the efficient operations of a crude oil or natural gas well, Rattler’s midstream infrastructure includes a network of gathering pipelines that collect and transport crude oil, natural gas and produced water from our operations in the Midland and Delaware Basins.

As of December 31, 2019, Rattler also owned (i) a 10% equity interest in EPIC Crude Holdings LP, which is building a long-haul crude oil pipeline from the Permian Basin and the Eagle Ford Shale to Corpus Christi, Texas that, upon completion, will be capable of transporting approximately 590,000 Bbl/d and, with installation of additional pumps and storage, up to approximately 900,000 Bbl/d, which we refer to as the EPIC pipeline; (ii) a 10% equity interest in Gray Oak Pipeline, LLC, which is building a long-haul crude oil pipeline that, upon completion, will be capable for transporting 900,000 Bbl/d from the Permian Basin and the Eagle Ford Shale to points alongside the Texas Gulf Coast, including a marine terminal connection in Corpus Christi, Texas, which we refer to as the Gray Oak pipeline; (iii) a 4% equity interest in Wink to Webster Pipeline LLC, which is developing a crude oil pipeline that, upon completion, will be capable of transporting approximately 1,000,000 Bbl/d from origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations, (iv) a 60% equity interest in OMOG JV LLC, a newly formed joint venture entity that acquired Reliance Midstream LLC, which operates over 230 miles of crude oil gathering and regional transportation pipelines and approximately 200,000 barrels of crude oil storage in Midland, Martin, Andrews and Ector Counties, Texas, and (v) a 50% equity interest in Amarillo Rattler LLC, which will operate the Yellow Rose gas gathering and processing system with estimated total capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. Each of the Epic and Gray Oak pipelines began interim operations in the second half of 2019, and we expect both to begin full commercial operations in the second quarter of 2020. The Wink to Webster project is expected to begin commercial operations in first half of 2021. We anticipate that the Yellow Rose system will commence full commercial operations in the middle of 2021.

The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States.

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Area History

Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Bone Spring, Wolfcamp, Cline, Strawn and Atoka formations. The Spraberry play was initiated with production from several new field discoveries in the late 1940s and early 1950s. It was eventually recognized that a regional productive trend was present, as fields were extended and coalesced over a broad area in the central Midland Basin. Development in the Spraberry play was sporadic over the next several decades due to typically low productive rate wells, with economics being dependent on oil prices and drilling costs.

The Wolfcamp formation is a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or debris flows with good reservoir properties. Exploration using 2-D seismic data located additional fields, but it was not until the use of 3-D seismic data in the 1990s that the greater extent of the Wolfcamp formation was revealed. The additional potential of the shales within this formation as reservoir rather than just source rocks was not recognized until very recently.

During the late 1990s, Atlantic Richfield Company, or Arco, began a drilling program targeting the base of the Spraberry formation at 10,000 feet, with an additional 200 to 300 feet drilled to produce from the upper portion of the Wolfcamp formation. Henry Petroleum, a private firm, owned interests in the Pegasus field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracturing treatments across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they monetized a portion of their acreage position, which led to the acquisition that enabled us to begin our participation in this play. Recent advancements in enhanced recovery techniques and horizontal drilling continue to make this play attractive to the oil and gas industry. By mid-2010, approximately half of the rigs active in the Permian Basin were drilling wells in the Wolfberry play. Since then we and most other operators are almost exclusively drilling horizontal wells in the development of unconventional reservoirs in the Permian Basin. As of December 31, 2019, we held working interests in 2,656 gross (2,202 net) producing wells and only royalty interests in 4,161 additional wells.

Geology

The Greater Permian Basin formed as an area of rapid Pennsylvanian-Permian subsidence in response to dynamic structural influence of the Marathon Uplift and Ancestral Rockies. It is one of the most productive sedimentary basins in the U.S., with established oil and gas production from several stacked reservoirs of varying age ranges, most notably Permian aged sediments. In particular, the Permian aged Wolfcamp and Spraberry/Bone Spring Formations have been heavily targeted for several decades. First, through vertical comingling of these zones and, more recently, through horizontal exploitation of each individual horizon. Prior to deposition of Wolfcamp and Spraberry/Bone Spring Formations, the area of the present-day Permian Basin was a continuous sedimentary feature called the Tabosa Basin. During this time, Ordovician, Silurian, Devonian and Mississippian sediments were laid down in a primarily open marine, shelf setting. However, some time frames saw more restrictive settings that were conducive to the deposition of organically rich mudstone such as the Devonian Woodford and Mississippian Barnett/Meramec. These formations are important sources and, more recently, reservoirs within the present-day Greater Permian Basin.

The Spraberry/Bone Spring was deposited as siliciclastic and carbonate turbidites and debris flows along with pelagic mudstones in a deep-water, basinal environment, while the Wolfcamp reservoirs consist of debris-flow, grain-flow and fine-grained pelagic sediments, which were also deposited in a basinal setting. The best carbonate reservoirs within the Wolfcamp and Spraberry/Bone Spring are generally found in close proximity to the Central Basin Platform, while mudstone reservoirs thicken basin-ward, away from the Central Basin Platform. The mudstone within these reservoirs is organically rich, which when buried to sufficient depth for thermal maturation, became the source of the hydrocarbons found both within the mudstones themselves and in the interbedded conventional clastic and carbonate reservoirs.  Due to this complexity, the Wolfcamp and Spraberry/Bone Spring intervals are a hybrid reservoir system that contains characteristics of both unconventional and conventional reservoirs.

We have successfully developed several hybrid reservoir intervals within the Clearfork, Spraberry/Bone Spring, Wolfcamp and Barnett/Meramec formations since we began horizontal drilling in 2012. The mudstones and some clastics exhibit low permeabilities which necessitate the need for hydraulic fracture stimulation to unlock the vast storage of hydrocarbons in these targets.


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We possess, or are in the process of acquiring, 3-D seismic data over substantially all of our major asset areas.  Our extensive geophysical database currently includes approximately 3,413 square miles of 3-D data.  This data will continue to be utilized in the development of our horizontal drilling program and identification of additional resource to be exploited.

Production Status

During the year ended December 31, 2019, net production from our Permian Basin acreage was 103,285 MBOE, or an average of 282,972 BOE/d, of which approximately 66% was oil, 18% was natural gas liquids and 16% was natural gas.

Facilities

Our oil and natural gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/natural gas/water separation equipment and pumping units.

Our publicly traded subsidiary Rattler owns the Fasken Center which has over 421,000 net rentable square feet within its two office towers and associated assets in Midland, Texas. We, Viper and Rattler are headquartered at the Fasken Center. We and unrelated third parties lease office space within the Fasken Center from Rattler under long-term lease agreements.

We and our subsidiaries also own field offices and related facilities in Midland and Reeves Counties, Texas. We believe that these facilities are adequate for our current operations.

 
Recent and Future Activity

During 2020, we expect to complete an estimated 320 to 360 gross (288 to 324 net) operated horizontal wells on our acreage. We currently estimate that our capital expenditures in 2020 for drilling and infrastructure will be between $2.8 billion and $3.0 billion, consisting of $2.45 billion to $2.6 billion for horizontal drilling and completions including non-operated activity, $200 million to $225 million for midstream investments, excluding joint venture investments, and $150 million to $175 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions. During the year ended December 31, 2019, we drilled 330 gross (296 net) and completed 317 gross (289 net) operated horizontal wells. During the year ended December 31, 2019, our capital expenditures for drilling, completing and equipping wells were $2.6 billion. In addition, we spent $364 million for oil and gas midstream and infrastructure and $776 million for leasehold and mineral rights acquisitions.

We are operating 23 drilling rigs now including two rigs drilling produced water disposal wells and currently intend to operate between 20 and 23 rigs on average in 2020. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans in response to market conditions.
With our current development plan, we expect to continue our strong PUD conversion ratio in 2020 by converting an estimated 35% of our PUDs to a proved developed category, and develop approximately 66% of the consolidated 2019 year-end PUD reserves by the end of 2021.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2019, 2018 and 2017 were prepared by Ryder Scott with respect to our assets and those of Viper. Ryder Scott is an independent petroleum engineering firm. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.

 
Under SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved

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reserves as of December 31, 2019 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 85% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 15% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve reports to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our Executive Vice President–Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. Our Executive Vice President–Reservoir Engineering is a petroleum engineer with over 30 years of reservoir and operations experience and our geoscience staff has an average of approximately 20 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

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.


8


The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2019, 2018 and 2017 (including those attributable to Viper), based on the reserve reports prepared by Ryder Scott. Each reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States.
 As of December 31,
 2019 2018 2017
Estimated proved developed reserves:     
Oil (MBbls)457,083
 403,051
 141,246
Natural gas (MMcf)824,760
 705,084
 190,740
Natural gas liquids (MBbls)165,173
 125,509
 35,412
Total (MBOE)759,716
 646,074
 208,447
Estimated proved undeveloped reserves:     
Oil (MBbls)253,820
 223,885
 91,935
Natural gas (MMcf)294,051
 343,565
 94,629
Natural gas liquids (MBbls)65,030
 64,782
 19,198
Total (MBOE)367,859
 345,928
 126,905
Estimated Net Proved Reserves:     
Oil (MBbls)710,903
 626,936
 233,181
Natural gas (MMcf)1,118,811
 1,048,649
 285,369
Natural gas liquids (MBbls)230,203
 190,291
 54,609
Total (MBOE)(1)
1,127,575
 992,001
 335,352
Percent proved developed67% 65% 62%
(1)Estimates of reserves as of December 31, 2019, 2018 and 2017 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2019, 2018 and 2017, respectively, in accordance with SEC guidelines applicable to 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.

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A.“Risk Factors.” We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2019, our proved undeveloped reserves totaled 253,820 MBbls of oil, 294,051 MMcf of natural gas and 65,030 MBbls of natural gas liquids, for a total of 367,859 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.


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The following table includes the changes in PUD reserves for 2019:
 (MBOE)
Beginning proved undeveloped reserves at December 31, 2018345,928
Undeveloped reserves transferred to developed(120,920)
Revisions(77,519)
Net purchases4,542
Divestitures(5,672)
Extensions and discoveries221,500
Ending proved undeveloped reserves at December 31, 2019367,859

The increase in proved undeveloped reserves was primarily attributable to extensions of 213,909 MBOE from 291 gross (262 net) wells in which we have a working interest and 7,591 MBOE from 97 gross wells in which Viper owns royalty interests. Of the 291 gross working interest wells, 64 were in the Delaware Basin. Transfers of 120,920 MBOE were the result of drilling or participating in 135 gross (119 net) horizontal wells in which we have a working interest and 79 gross wells in which we have a royalty interest or mineral interest through Viper. We own a working interest in 75 of the 79 gross Viper wells. Downward revisions of 77,519 MBOE resulted from 67,114 MBOE of PUD downgrades due to refinement of the PUD inventory following the Energen merger. These downgrades were offset with extensions. The remaining 10,405 MOE of downward revisions were mostly from lower benchmark commodity prices.

Costs incurred relating to the development of PUDs were approximately $956 million during 2019. Estimated future development costs relating to the development of PUDs are projected to be approximately $1.2 billion in 2020, $721 million in 2021, $641 million in 2022 and $576 million in 2023. Since our current executive team assumed management control in 2011, our average drilling costs and drilling times have been reduced. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.

As of December 31, 2019, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.

As of December 31, 2019, none of our total proved reserves were classified as proved developed non-producing.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

The following tables set forth information regarding our net production of oil, natural gas and natural gas liquids by basin for each of the periods indicated:
 Year Ended December 31, 2019 Year Ended December 31, 2018
 Midland BasinDelaware Basin
Other(1)
Total Midland BasinDelaware Basin
Other(2)
Total
 (in thousands)
Production Data:         
Oil (MBbls)41,156
25,951
1,411
68,518
 24,698
9,288
381
34,367
Natural gas (MMcf)48,109
48,447
1,057
97,613
 21,674
12,416
579
34,669
Natural gas liquids (MBbls)10,485
7,826
187
18,498
 5,493
1,866
106
7,465
Total (MBoe)59,659
41,852
1,774
103,285
 33,803
13,223
584
47,610
(1)Includes the Central Basin Platform, the Eagle Ford Shale and the Rockies.
(2)Includes the Eagle Ford Shale.


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 December 31, 2017
 Midland BasinDelaware Basin
Other(1)
Total
 (in thousands)
Production Data:    
Oil (MBbls)17,553
3,865

21,418
Natural gas (MMcf)15,893
4,761
6
20,660
Natural gas liquids (MBbls)3,673
383

4,056
Total (MBoe)23,875
5,042
1
28,917
(1)Includes the Eagle Ford Shale.


The following table sets forth certain price and cost information for each of the periods indicated:
 Year Ended December 31,
 2019 2018 2017
Average Prices:     
Oil ($ per Bbl)$51.87
 $54.66
 $48.75
Natural gas ($ per Mcf)0.68
 1.76
 2.53
Natural gas liquids ($ per Bbl)14.42
 25.47
 22.20
Combined ($ per BOE)37.63
 44.73
 41.02
Oil, hedged ($ per Bbl)(1)
51.96
 51.20
 48.94
Natural gas, hedged ($ per MMbtu)(1)
0.86
 1.72
 2.65
Natural gas liquids, hedged ($ per Bbl)(1)
15.20
 25.46
 
Average price, hedged ($ per BOE)(1)
38.00
 42.20
 41.26
      
Average Costs per BOE:     
Lease operating expense$4.74
 $4.31
 $4.38
Production and ad valorem taxes2.40
 2.79
 2.54
Gathering and transportation expense0.86
 0.55
 0.44
General and administrative - cash component0.54
 0.79
 0.80
Total operating expense - cash$8.54
 $8.44
 $8.16
      
General and administrative - non-cash component$0.46
 $0.57
 $0.88
Depreciation, depletion and amortization14.01
 13.09
 11.30
Interest expense, net1.66
 1.83
 1.40
Merger and integration expense
 0.77
 
Total expenses$16.13
 $16.26
 $13.58
(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.


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Wells Drilled and Completed in 2019

The following table sets forth the total number of operated horizontal wells drilled and completed during the year ended December 31, 2019:
 Year Ended December 31, 2019
 Drilled Completed
AreaGrossNet GrossNet
Midland Basin171
154
 178
163
Delaware Basin159
142
 139
126
Total330
296
 317
289

As of December 31, 2019, we operated the following wells:
 Vertical Wells Horizontal Wells Total
AreaGrossNet GrossNet GrossNet
Midland Basin833
768
 1,004
913
 1,837
1,681
Delaware Basin

 485
453
 485
453
Other3
3
 

 3
3
Total836
771
 1,489
1,366
 2,325
2,137

Productive Wells

As of December 31, 2019, we owned an average unweighted 83% working interest in 2,656 gross (2,202 net) productive wells and an average 3.1% royalty interest in 4,161 additional wells. Through our subsidiary Viper, we own an average unweighted 3.4% royalty or mineral interest in 5,807 productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

The following table sets forth information regarding productive wells by basin as of December 31, 2019:
 Gross Wells Net Wells
Midland Basin1,993
 1,717
Delaware Basin660
 482
Other3
 3
Total productive wells2,656
 2,202


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Drilling Results

The following table sets forth information with respect to the number of wells completed during the periods indicated by basin. Each of these wells was drilled in the Permian Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.
 Year Ended December 31, 2019
 Midland Basin Delaware Basin Total
 Gross Net Gross Net Gross Net
Development:           
Productive75
 68
 31
 28
 106
 96
Dry
 
 
 
 
 
Exploratory:           
Productive96
 86
 128
 114
 224
 200
Dry
 
 
 
 
 
Total:           
Productive171
 154
 159
 142
 330
 296
Dry
 
 
 
 
 
 Year Ended December 31, 2018
 Midland Basin Delaware Basin Total
 Gross Net Gross Net Gross Net
Development:           
Productive67
 58
 21
 20
 88
 78
Dry
 
 
 
 
 
Exploratory:           
Productive50
 43
 38
 35
 88
 78
Dry
 
 
 
 
 
Total:           
Productive117
 101
 59
 55
 176
 156
Dry
 
 
 
 
 
 Year Ended December 31, 2017
 Midland Basin Delaware Basin Total
 Gross Net Gross Net Gross Net
Development:           
Productive26
 22
 1
 1
 27
 23
Dry
 
 
 
 
 
Exploratory:           
Productive93
 67
 19
 17
 112
 84
Dry
 
 
 
 
 
Total:           
Productive119
 89
 20
 18
 139
 107
Dry
 
 
 
 
 


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Acreage

The following table sets forth information as of December 31, 2019 relating to our leasehold acreage:
 
Developed Acreage(1)
 
Undeveloped Acreage(2)
 
Total Acreage(3)
Basin
Gross(4)
 
Net(5)
 
Gross(4)
 
Net(5)
 
Gross(4)
 
Net(5)
Conventional Permian1,278
 1,154
 1,507
 1,401
 2,785
 2,555
Delaware92,408
 75,815
 103,763
 79,481
 196,171
 155,296
Exploration160
 160
 38,124
 28,865
 38,284
 29,025
Midland135,792
 123,159
 82,346
 72,302
 218,138
 195,461
Total229,638
 200,288
 225,740
 182,049
 455,378
 382,337
(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.

Undeveloped acreage expirations

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2019, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.
 2020 2021 2022 2023 2024
BasinGross Net Gross Net Gross Net Gross Net Gross Net
Delaware27,197
 20,284
 9,709
 3,756
 4,659
 571
 1,240
 384
 
 
Exploration18,608
 18,568
 4,405
 3,035
 
 
 7,218
 4,535
 
 
Midland6,145
 3,569
 1,358
 835
 2,039
 1,816
 
 
 
 
Total51,950
 42,421
 15,472
 7,626
 6,698
 2,387
 8,458
 4,919
 
 

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.


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Marketing and Customers

We typically sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the year ended December 31, 2019, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company, which we refer to as Shell (27%); Plains Marketing, which we refer to as Plains (23%); and Vitol Inc., which we refer to as Vitol (15%). For the year ended December 31, 2018, three purchasers each accounted for more than 10% of our revenue: Shell Trading (26%); Koch Supply & Trading LP, which we refer to as Koch (15%); and Occidental Energy Marketing Inc. (11%). For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell (31%); Koch (19%); and Enterprise Crude Oil LLC (11%). No other customer accounted for more than 10% of our revenue during these periods. If a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed.

Agreement with Trafigura Trading LLC

We have entered into a firm commitment oil purchase agreement with Trafigura Trading LLC, which we refer to as Trafigura, in which we agreed to sell and deliver a firm quantity of 25,000 barrels of crude oil per day to Trafigura during the term of the agreement. Under this agreement, which has a seven-year term beginning on August 1, 2018, the price per barrel of oil paid to us by Trafigura is based on the average of the published settlement quotations for NYMEX CMA, as adjusted for different delivery methods and periods. If during the term of the agreement we fail to deliver the required quantities of oil for any month other than for specified force majeure events, we have agreed to pay Trafigura a deficiency payment equal to any unfavorable difference between the contract price and the spot price, multiplied by the deficiency volume.

Agreement with Plains

In July 2019, our wholly-owned subsidiary, Energen Resources Corporation, which we refer to as Energen Resources, entered into a long-term crude oil sales agreement with Plains pursuant to which, among other things, our existing agreements with Plains were terminated. Our new agreement with Plains requires that we make available 50,000 barrels of crude oil per day until the date occurring ten years following the date service commences for ExxonMobil Oil Corporation, which we refer to as Exxon, pursuant to the transportation service agreement between Exxon and the Wink to Webster pipeline carrier (plus extensions for force majeure). If during the term of our agreement we fail to deliver the required quantities of oil for any month other than for specified force majeure events or acts or omissions of Plains, we have agreed to pay Plains a specified per barrel amount, subject to escalation, multiplied by the deficiency volume. If during the term of the agreement we fail to deliver the quantities of oil for any month that we have committed for such month other than for specified force majeure events or acts or omissions of Plains, we have agreed to pay Plains a deficiency payment. We have also dedicated certain crude oil production attributable to certain of our interests to Plains in connection with this agreement. Pricing for our production under the Plains agreement (i) prior to the date service commences for Exxon pursuant to the transportation service agreement between Exxon and the Wink to Webster pipeline carrier, is at a Midland WTI or WTL, as applicable, base price less certain costs and (ii) following the date service commences for Exxon pursuant to the transportation service agreement between Exxon and the Wink to Webster pipeline carrier, for volumes up to 100,000 barrels of crude oil per day, is at a MEH WTI or WTL base price, as applicable, less certain costs.

Agreement with Shell

In December 2018, we entered into an oil purchase agreement with Shell, which was amended and restated in December 2019, in which Shell agreed to transport crude oil it purchases from us through the EPIC pipeline, with which we have an agreement for the transportation of certain crude oil. Our agreement with Shell provides for different purchase obligations during the pre-commencement and service commencement periods for the EPIC pipeline, and provides for a three-year term beginning on the service commencement date for the EPIC pipeline. Shell has the option to extend its purchase obligations for up to three one-year terms, but not beyond March 31, 2026 except in the event of force majeure. Our delivery obligation (i) prior to the full service commencement of the EPIC pipeline will be, subject to certain conditions, including our right to repurchase certain volumes, either 30,000 or 40,000 barrels of crude oil per day and (ii) during the full service term will not exceed 50,000 barrels of crude oil per day. In addition, our wholly-owned subsidiary Energen Resources has signed an agreement with Shell in which all or a portion of the 50,000 barrels of crude oil per day referenced in the previous sentence may also be satisfied by Energen Resources. During different pre-commencement periods, Shell has agreed to pay us the price per barrel of oil based on the arithmetic average of the daily settlement price for the “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the applicable one-month period, subject to certain adjustments, plus a Corpus Christi differential determined based on Shell’s average sales price for its WTI barrels in Corpus Christi less certain other costs, expenses and fees. During the full service term, the price per barrel of oil payable by Shell to us is based on calendar dated Brent pricing plus a negotiated differential generally based on certain Argus WTI Houston CIF Rotterdam and Platts Midland DAP Rotterdam pricing, less certain adjustments.

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Agreements with Vitol

On October 18, 2018, we entered into an agreement with Vitol to, among other things, sell an average of 23,750 barrels of crude oil per day plus other agreed upon volumes. We are continuing to sell crude oil to Vitol on a month-to-month basis and expect to continue to do so under our existing agreement with Vitol until our new agreement with Vitol becomes effective. Under our new agreement with Vitol, we agreed to sell, and Vitol agreed to purchase, (i) subject to certain conditions, including accelerated commissioning service on the Gray Oak pipeline and completion of certain infrastructure connections, 50,000 barrels of crude oil per day on average during each month occurring during the first seven years of full service on the Gray Oak pipeline, (ii) subject to certain conditions and the satisfaction of other conditions, including full service on the Gray Oak Pipeline and completion of certain infrastructure connections, an additional 50,000 barrels of crude oil per day on average during each month occurring during the first seven years following satisfaction of such conditions, (iii) subject to certain conditions, including notice that transportation services on the EPIC pipeline are ready to commence and completion of certain infrastructure connections, an additional 50,000 barrels of crude oil per day on average during each month occurring during the first seven years following satisfaction of such conditions and (iv) such other volumes of crude oil as agreed by the parties. We are entitled to receive payment for such crude oil under netback pricing, whereby the price for our crude oil is determined based on a formula which takes into consideration the final purchase price obtained by Vitol in marketing such crude oil in certain third party transactions less certain costs. In connection therewith, Vitol has agreed to, among other things, use commercially reasonable efforts to (i) maximize the final purchase price to us and mitigate any costs factored into the price determination and (ii) acquire third party crude oil to cover any shortfall below our volumes commitments. Vitol also agrees to (i) use the same care and apply the same policies as it would exercise and apply if it were trading the subject crude oil for Vitol’s own account and (ii) transport such crude oil on certain designated pipelines, including the Gray Oak pipeline pursuant to rights we have obtained through our Gray Oak transportation services agreement described below under “—Transportation”, under third party shipper rights or term assignments, as applicable, prior to Vitol’s downstream marketing activities.

Competition

The oil and natural gas industry is intensely competitive, and in our upstream segment, we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

In our midstream operations segment, as Rattler seeks to expand its crude oil, natural gas and water-related midstream services, it faces a high level of competition, including major integrated crude oil and natural gas companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store or market oil and natural gas. As Rattler seeks to expand to provide midstream services to third party producers, it similarly faces a high level of competition. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gas or NGLs. Within the acreage dedicated by Rattler to us, Rattler does not compete with other midstream companies to provide us with midstream services as a result of our relationship and long-term dedications to Rattler’s midstream assets. However, we may continue to use third party service providers for certain midstream services within such dedicated acreage until the expiration or termination of certain pre-existing dedications.

Transportation

During the initial development of our fields we evaluate all gathering and delivery infrastructure in the areas of our production. Currently, a majority of our production in the Midland and Delaware Basins are transported to purchasers by pipeline. 


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The following table presents the average percentage of produced oil sold by pipeline and the average percentage of produced water connected to saltwater disposals by pipeline:
 Midland Basin Delaware Basin Total
% of produced oil sold by pipeline94% 87% 91%
% of produced water connected to pipeline96% 96% 96%

We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler’s infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in the Delaware and Midland Basins. Our agreements with Rattler include a total of approximately 397,000 gross acres across all Rattler’s service lines across the Midland and Delaware Basins.

We are also party to a transportation services agreement with Gray Oak Pipeline, LLC, pursuant to which we agreed to the accelerated commissioning service, or the ACS, on the Gray Oak pipeline in the amount of 50,000 barrels of crude oil per day. Under the ACS program, shippers must make a deficiency payment for any barrels not shipped during the ACS term, which expires the day before the Gray Oak pipeline goes into full service, which is currently anticipated to occur in the second quarter of 2020. ACS commenced in November 2019 and is ongoing. Due to restrictive API gravity provisions and the lack of markets, we have been unable to ship any volumes over the Gray Oak pipeline since the inception of the ACS.
Once full service commences on the Gray Oak pipeline, subject to the terms and conditions of this transportation services agreement, we will be required to ship 50,000 barrels per day of crude oil on the Gray Oak pipeline or pay a deficiency payment for any shortfall in volumes as measured on a quarterly basis. Such deficiency payments can be used as a credit against future shipments in excess of our minimum contract volume each quarter, subject to certain restrictions.
Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.50% to 30.00%, resulting in a net revenue interest to us generally ranging from 70.00% to 87.50%.

Seasonal Nature of Business

Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. In our exploration and production business, seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations. In our midstream operations business, the volumes of condensate produced at Rattler’s processing facilities fluctuate seasonally, with volumes generally increasing in the winter months and decreasing in the summer months as a result of the physical properties of natural gas and comingled liquids. Severe or prolonged summers may adversely affect our results of operations in the midstream operations segment.

Regulation

Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.

Environmental Matters and Regulation

Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-

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compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Waste Handling. The Resource Conservation and Recovery Act, as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the Resource Conservation and Recovery Act, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the Resource Conservation and Recovery Act, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste are not necessary at this time. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean

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Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or the Corps, jointly promulgated final rules redefining the scope of waters protected under the Clean Water Act. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules. The 2015 rule and the 2019 repeal are subject to several ongoing legal challenges. Also, on January 23, 2020, the EPA and the Corps released a final rule replacing the 2015 rule, and significantly reducing the waters subject to federal regulation under the Clean Water Act. The rule is anticipated to generate further legal challenges. Further, on April 23, 2019, the EPA published an interpretive statement and request for comment, clarifying that the Clean Water Act’s permitting program for pollutant discharges does not apply to releases of pollutants to groundwater. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act. To the extent the rules expand the range of properties subject to the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “–Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The Oil Pollution Act is the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The Oil Pollution Act subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Non-compliance with the Clean Water Act or the Oil Pollution Act may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “–Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs.

At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties

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to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. On November 4, 2019, the Trump Administration submitted its formal notification of withdrawal to the United Nations. It is not clear what steps, if any, will be taken to negotiate a new agreement, or what terms would be included in such an agreement. In response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.

On June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage

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tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. Also, on October 15, 2018, the EPA published a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations, including, for example, reducing the monitoring frequency for fugitive emissions and revising the requirements for pneumatic pumps at well sites. In addition, on August 28, 2019, the EPA proposed amendments to the 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. Legal challenges are anticipated and thus substantial uncertainty exists regarding the scope of these New Source Performance standards for oil and natural gas operations. The 2012 and 2016 New Source Performance standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs.

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Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Endangered Species

The federal Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. On August 12, 2019, the U.S. Fish and Wildlife Service and the National Oceanic and Atmospheric Administration’s National Marine Fisheries Service jointly published final rules that, among other things, tighten the critical habitat designation process and eliminate certain automatic protections for threatened species going forward. Nevertheless, the designation of previously unprotected species in areas where we operate as threatened or endangered could result in the imposition of restrictions on our operations and consequently have a material adverse effect on our business.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

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.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties

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and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates or negotiated rates. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.

Natural Gas Gathering. Although FERC has not made a formal determination with respect to the facilities Rattler LLC considers to be natural gas gathering pipelines, Rattler believes that its natural gas gathering pipelines meet the traditional tests that FERC has used to determine that pipelines perform primarily a gathering function and are, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated interstate transportation services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the Natural Gas Act of 1938, or NGA, and that the facility provides interstate transportation service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act, or NGPA. Such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, adversely affect results of operations and cash flow. In addition, if any of the facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.
Even though Rattler LLC considers its natural gas gathering pipelines to be exempt from the jurisdiction of FERC under the NGA, FERC regulation of interstate natural gas transportation pipelines may indirectly impact gathering services. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release and market center promotion may indirectly affect intrastate markets and gathering services. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural

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gas pipelines. However, there can be no assurance that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.
Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, Rattler LLC’s natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on Rattler’s or our operations, but additional capital expenditures and increased operating costs may result depending on future legislative and regulatory changes.
Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act, and our subsidiary Rattler Midstream Operating LLC has a tariff on file with FERC to perform gathering service in interstate commerce. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines, including our subsidiary Rattler Midstream Operating LLC, must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Safety and Maintenance Regulation. In our midstream operations, Rattler LLC is subject to regulation by the U.S. Department of Transportation, or DOT, under the Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.

Rattler LLC is also subject to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States crude oil and natural gas transportation pipelines and some gathering pipelines in high-consequence areas within ten years. DOT, through the Pipeline and Hazardous Materials Safety Administration, or PHMSA, has developed regulations implementing the Pipeline Safety Improvement Act that requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.

The Pipeline Safety and Job Creation Act, enacted in 2011, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, also known as the PIPES Act, enacted in 2016, amended the HLPSA and NGPSA and increased safety regulation. The Pipeline Safety and Job Creation Act doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations (now increased for inflation to $218,647 and $2,186,465, respectively), and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. The PIPES Act ensures that the PHMSA completes the Pipeline Safety and Job Creation Act requirements; reforms PHMSA to be a more dynamic, data-driven regulator; and closes gaps in federal standards.

PHMSA has undertaken rulemakings to address many areas of this legislation. For example, on October 1, 2019, PHMSA published final rules to expand its integrity management requirements and impose new pressure testing requirements

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on regulated pipelines, including certain segments outside High Consequence Areas. The rules, once effective, also extend reporting requirements to certain previously unregulated gathering lines. The safety enhancement requirements and other provisions of the Pipeline Safety and Job Creation Act and the PIPES Act, as well as any implementation of PHMSA rules thereunder and/or related rule making proceedings, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders could have an adverse impact on our business, financial condition, results of operation and cash flow.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards, and many states have undertaken responsibility to enforce the federal standards. The Railroad Commission of Texas is the agency vested with intrastate natural gas pipeline regulatory and enforcement authority in Texas. The Commission’s regulations adopt by reference the minimum federal safety standards for the transportation of natural gas. In addition, on December 17, 2019, the Commission adopted rules requiring that operators of gathering lines take 'appropriate' actions to fix safety hazards. We do not anticipate any significant problems in complying with applicable federal and state laws and regulations in Texas. Our gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. Moreover, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Rattler LLC and the entities in which it owns an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt from these standards. Also, the Department of Homeland Security and other agencies such as the EPA continue to develop regulations concerning the security of industrial facilities, including crude oil and natural gas facilities. We are subject to a number of requirements and must prepare Federal Response Plans to comply. We must also prepare Risk Management Plans under the regulations promulgated by the EPA to implement the requirements under the CAA to prevent the accidental release of extremely hazardous substances. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements. We believe that we are in compliance in all material respects with all applicable laws and regulations relating to safety and security.

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Operational Hazards and Insurance

The oil and natural gas industry involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies for onshore property (oil lease property/production equipment) for selected locations, rig physical damage protection, control of well protection for selected wells,

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comprehensive general liability, commercial automobile, workers compensation, pollution liability (claims made coverage with a policy retroactive date), excess umbrella liability and other coverage.

Our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. See Item 1A. “Risk Factors–Risks Related to the Oil and Natural Gas Industry and Our Business–Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.”

We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Generally, we also require our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

Employees

As of December 31, 2019, we had approximately 712 full time employees. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full time employees.

Facilities

Our corporate headquarters is located in Midland, Texas. We also lease additional office space in Birmingham, Alabama, Houston, Texas, Midland, Texas and Oklahoma City, Oklahoma. We believe that our facilities are adequate for our current operations.

Availability of Company Reports

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports are available free of charge on the Investor Relations page of our website at www.diamondbackenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

ITEM 1A. RISK FACTORS

The nature of our business activities subjects us to certain hazards and risks. The following is a summary of some of the material risks relating to our business activities. Other risks are described in Item 1. “Business and Properties” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” These risks are not the only risks we face. We could also face additional risks and uncertainties not currently known to the Company or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline.

Risks Related to the Oil and Natural Gas Industry and Our Business

Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have

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been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

the domestic and foreign supply of oil and natural gas;

the level of prices and expectations about future prices of oil and natural gas;

the level of global oil and natural gas exploration and production;

the cost of exploring for, developing, producing and delivering oil and natural gas;

the price and quantity of foreign imports;

political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

speculative trading in crude oil and natural gas derivative contracts;

the level of consumer product demand;

weather conditions and other natural disasters;

risks associated with operating drilling rigs;

technological advances affecting energy consumption;

the price and availability of alternative fuels;

domestic and foreign governmental regulations and taxes;

the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

global or national health concerns, including the outbreak of pandemic or contagious disease, such as the coronavirus;

the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as WTI Futures Contract 1 price for crude oil has ranged from a low of $26.21 per barrel, or Bbl, in February 2016 to a high of $76.41 per Bbl in October 2018. The Natural Gas Futures Contract 1 price spot market price of natural gas has ranged from a low of $1.64 per MMBtu in March 2016 to a high of $4.84 per MMBtu in November 2018. During 2019, WTI Futures Contract 1 prices ranged from $46.54 to $66.30 per Bbl and the Natural Gas Futures Contract 1 spot market price of natural gas ranged from $2.07 to $3.59 per MMBtu. On January 31, 2020, the WTI Futures Contract 1 posted price for crude oil was $51.56 per Bbl and the Natural Gas Futures Contract 1 spot market price of natural gas was $1.84 per MMBtu, representing decreases of 22% and 49%, respectively, from the high of $66.30 per Bbl of oil and $3.59 per MMBtu for natural gas during 2019. In response to recent volatility in commodity prices, many producers have reduced their capital expenditure budgets. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.

In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our

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reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East, the occurrence or threat of terrorist attacks in the United States or other countries and global or national health concerns could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, may precipitate an economic slowdown. Concerns about global economic growth may have an adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our development and exploration operations and our ability to complete acquisitions require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2019, our total capital expenditures, including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately $3.1 billion. Our 2020 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $2.8 billion to $3.0 billion, representing an increase of 1% over our 2019 capital budget. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and the senior notes.

We intend to finance our future capital expenditures with cash flow from operations, proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:

our proved reserves;

the volume of oil and natural gas we are able to produce from existing wells;

the prices at which our oil and natural gas are sold;

our ability to acquire, locate and produce economically new reserves; and

our ability to borrow under our credit facility.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2020 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt

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financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

Our success depends on finding, developing or acquiring additional reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made, and expect to make in the future, substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings and slow our growth.

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:

recoverable reserves;

future oil and natural gas prices and their applicable differentials;

operating costs; and

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

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No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. The inability to effectively manage the integration of acquisitions, including our recently completed and pending acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.

Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If future wells or the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.

Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 12,310 gross (8,141 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage. As of December 31, 2019, only 477 of our gross identified potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, we have identified approximately 3,382 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or

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completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Through December 31, 2019, we are the operator of, have participated in, or have acquired a total of 1,770 horizontal wells completed on our acreage, we cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our quarterly operating results.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2019, we had leases representing 42,421 net acres expiring in 2020, 7,626 net acres expiring in 2021, 2,387 net acres expiring in 2022, 4,919 net acres expiring in 2023 and no net acres expiring in 2024. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases expiring in 2020, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy these rigs in this time frame, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.

We have entered into fixed price swap contracts, fixed price basis swap contracts, double-up swap contracts and three-way collars with corresponding put, short put and call options and may in the future enter into forward sale contracts or additional fixed price swap, fixed price basis swap, double-up swap derivatives or three-way collars for a portion of our production. Although we have hedged a portion of our estimated 2020 and 2021 production, we may still be adversely affected by continuing and prolonged declines in the price of oil.

We use fixed price swap contracts, fixed price basis swap contracts, double-up swap contracts and three-way collars with corresponding put, short put and call options to reduce price volatility associated with certain of our oil and natural gas sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. Under our three-way collar contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the ceiling price to a maximum of the difference between the floor price and the short put price.  We are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the ceiling price. If the settlement price is between the floor and the ceiling price, there is no payment required.

To the extent that the prices of oil and natural gas remain at current levels or decline further, we may not be able to economically hedge future production at the same level as our current hedges, and our results of operations and financial condition may be negatively impacted. For additional information regarding our outstanding derivative contracts as of December 31, 2019, see Note 15—Derivatives to our consolidated financial statements included elsewhere in this report.


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Our derivative transactions expose us to counterparty credit risk.

By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose ourselves to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. We do not require collateral from our counterparties. We have entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk by us.

If production from our Permian Basin acreage decreases due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contract, which will result in deficiency payments to the counterparty and may have an adverse effect on our operations.

We are a party to long-term crude oil agreements with Trafigura, Plains, Shell and Vitol under which, subject to certain terms and conditions, we are obligated to deliver specified quantities of oil to such companies. Our maximum delivery obligation under these agreements varies for different periods and depends in some cases upon certain conditions, such as the in-service dates for the Gray Oak pipeline and the EPIC pipeline as described in this report. See “Business and Properties—Marketing and Customers” above. If production from our Permian Basin acreage decreases due to decreased developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under our oil purchase agreements, which may result in deficiency payments to certain counterparties or a default under such agreements and may have an adverse effect on our company.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $186 million at December 31, 2019) and receivables from purchasers of our oil and natural gas production (approximately $429 million at December 31, 2019). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2019, three purchasers each accounted for more than 10% of our revenue: Shell (27%); Plains (23%); and Vitol (15%). For the year ended December 31, 2018, three purchasers each accounted for more than 10% of our revenue: Shell (26%); Koch (15%); and Occidental Energy Marketing Inc. (11%). For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell (31%); Koch (19%); and Enterprise Crude Oil LLC (11%). No other customer accounted for more than 10% of our revenue during these periods. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $13.54, $12.62 and $11.11 for the years ended December 31, 2019, 2018 and 2017, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, 2019, 2018 and 2017 was $1.4 billion, $595 million and $321 million, respectively.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of

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evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. Beginning December 31, 2009, we have used the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.

An impairment on proved oil and natural gas properties of $790 million was recorded for the year ended December 31, 2019. No impairments on proved oil and natural gas properties were recorded for the years ended December 31, 2018 and 2017. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Method of accounting for oil and natural gas properties” for a more detailed description of our method of accounting.

Our estimated reserves and EURs are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves as of December 31, 2019, 2018 and 2017 (which include those attributable to Viper) are based on reports prepared by Ryder Scott, which conducted a well-by-well review of all our properties for the periods covered by its reserve reports using information provided by us. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

The estimates of reserves as of December 31, 2019, 2018 and 2017 included in this report 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 December 31, 2019, 2018 and 2017, respectively, in accordance with the SEC guidelines applicable to reserve estimates for such periods.

The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.

The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil reserves.

The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.


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SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe because they have become uneconomic or otherwise.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Approximately 33% of our total estimated proved reserves as of December 31, 2019, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

All of our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition to the geographic concentration of our producing properties described above, as of December 31, 2019, all of our proved reserves were attributable to the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the year ended December 31, 2019, three purchasers each accounted for more than 10% of our revenue: Shell (27%); Plains (23%); and Vitol (15%). For the year ended December 31, 2018, three purchasers each accounted for more than 10% of our revenue: Shell (26%); Koch (15%); and Occidental Energy Marketing Inc. (11%). For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell (31%); Koch (19%); and Enterprise Crude Oil LLC (11%). No other customer accounted for more than 10% of our revenue during these periods. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.

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The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

Our business operations have grown substantially since our initial public offering in October 2012 and we expect our business operations to continue to grow in the future. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

We have incurred losses from operations during certain periods since our inception and may do so in the future.

Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from our operating activities in the future.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and

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complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.
 
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system, which interconnects with third party pipelines. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.

Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels. See Item 1. “Business—Regulation” for a description of certain laws and regulations that affect us.

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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.

On June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. For a more detailed discussion of federal laws concerning hydraulic fracturing, see “Items 1 and 2. Business and Properties—Regulation—Regulation of Hydraulic Fracturing.”

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For a more detailed discussion of state and local laws and initiatives concerning hydraulic fracturing, see “Items 1 and 2. Business and Properties—Regulation—Regulation of Hydraulic Fracturing.” We use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volumes of oil and natural gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further

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regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act, which we refer to as Dodd-Frank Act, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission, which we refer to as the CFTC, the SEC, and federal regulators of financial institutions, which we refer to as the Prudential Regulators, adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.

Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued many rules to implement the Dodd-Frank Act, including a rule, which we refer to as the

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Mandatory Clearing Rule, requiring clearing of hedges, or swaps, that are subject to it (currently, only certain interest rate and credit default swaps, which we do not presently have), a rule, which we refer to as the End User Exception, establishing an “end user” exception to the Mandatory Clearing Rule, a rule, which we refer to as the Margin Rule, setting forth collateral requirements in connection with swaps that are not cleared and also an exception to the Margin Rule for end users that are not financial end users, which exception we refer to as the Non-Financial End User Exception, and a rule, subsequently vacated by the United States District Court for the District of Columbia and remanded to the CFTC for further proceedings, imposing position limits. The CFTC has three times proposed a new version of this rule, with respect to which the comment period closed but the rule was not adopted, and another version of this rule, which we refer to as the Latest-Proposed Position Limit Rule, with respect to which the comment period will close on April 29, 2020 unless extended and a final rule may or may not be issued. The Latest-Proposed Position Limit Rule provides an exemption from the position limits for swaps that constitute “bona fide hedging positions” within the definition of such term under the Latest-Proposed Position Limit Rule, subject to the party claiming the exemption complying with the applicable filing, recordkeeping and reporting requirements of the Latest-Proposed Position Limit Rule.

We qualify for the End User Exception and will utilize it if the Mandatory Clearing Rule is expanded to cover swaps in which we participate, we qualify for the Non-Financial End User Exception and will not be required to post margin in connection with uncleared swaps under the Margin Rule, and our existing and anticipated hedging positions constitute “bona fide hedging positions” under the Re-Proposed Position Limit Rule and we intend to undertake the filing, recordkeeping and reporting necessary to utilize the bona fide hedging position exemption under the Latest-Proposed Position Limit Rule if and when it becomes effective, so we do not expect to be directly affected by any of such rules. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations (including laws and regulations giving the European Union financial authorities the power to write down amounts we may be owed on hedging agreements with counterparties subject to such laws and regulations and/or require that we accept equity interests in such counterparties in lieu of cash in satisfaction of such amounts), which we refer to collectively as Foreign Regulations, which may apply to our transactions with counterparties subject to such Foreign Regulations, which we refer to as Foreign Counterparties, and the U.S. adopted law and rules, which we call the U.S. Resolution Stay Rules, clarifying similar rights of U.S. banking authorities with respect to banking institutions subject to their regulation. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the Latest-Proposed Position Limit Rule is effected, such proposed rule and the U.S. Resolution Stay Rules could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulation, the U.S. Resolution Stay Rules and Foreign Regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

Recently enacted U.S. tax legislation as well as future U.S. tax legislations may adversely affect our business, results of operations, financial condition and cash flow.
 
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act, which we refer to as the Tax Act, that significantly reforms the Internal Revenue Code of 1986, as amended, which we refer to as the Code. Among other changes, the Tax Act (i) reduces the maximum U.S. corporate income tax rate from 35% to 21%, (ii) preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling, (iii) allows for immediate expensing of capital expenditures for tangible personal property for a period of time, (iv) modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations and (v) enacts new limitations regarding the deductibility of interest expense. The Tax Act is complex and far-reaching, and while we have evaluated the resulting impact of its enactment on us and recorded adjustments as required in our financial statements, aspects of the Tax Act are unclear and may not be clarified for some time. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued, and any such changes in our interpretations and assumptions could have an adverse effect on our business, results of operations, financial condition and cash flow.

In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry, including (i) eliminating the immediate deduction for

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intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.

Regulation of greenhouse gas emissions could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. While we are subject to certain federal greenhouse gas monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed greenhouse gas rules and regulations, see “Items 1 and 2. Business and Properties—Regulation—Environmental Regulation—Climate Change.”
At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. On November 4, 2019, the Trump Administration submitted its formal notification of withdrawal to the United Nations. It is not clear what steps, if any, will be taken to negotiate a new agreement, or what terms would be included in such an agreement. In response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.


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Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Commission has used this authority to deny permits for waste disposal wells.
We dispose of large volumes of produced water gathered from our drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by owned disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Although FERC has not made a formal determination with respect to the facilities we consider to be natural gas gathering pipelines, we believe that our subsidiary Rattler LLC’s natural gas gathering pipelines meet the traditional tests that FERC has used to determine that pipelines perform primarily a gathering function and are, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated interstate transportation services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, and that the facility provides interstate transportation service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act, or NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flow. In addition, if any of Rattler LLC’s facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.

Even though we consider Rattler LLC’s natural gas gathering pipelines to be exempt from the jurisdiction of FERC under the NGA, FERC regulation of interstate natural gas transportation pipelines may indirectly impact gathering services. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets and gathering services. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Rattler LLC’s gathering operations could also be subject to safety and operational regulations relating to the design, construction,

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testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on our or Rattler LLC’s operations, but we could be required to incur additional capital expenditures and increased operating costs depending on future legislative and regulatory changes.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The U.S. Department of Transportation, or DOT, through the PHMSA and state agencies, enforces safety regulations with respect to the design, construction, operation, maintenance, inspection and management of certain of Rattler LLC’s pipeline facilities. The PHMSA requires pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high-consequence areas, or HCAs, defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. The regulations require operators to (i) perform ongoing assessments of pipeline integrity, (ii) identify and characterize applicable threats to pipeline segments that could impact a HCA, (iii) improve data collection, integration and analysis, (iv) repair and remediate pipelines as necessary and (v) implement preventive and mitigating actions. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. The PHMSA’s regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans, including extensive spill response training for pipeline personnel.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, also known as the Pipeline Safety and Job Creation Act, and the PIPES Act, are the most recent enactments of federal legislation to amend the NGPSA and the HLPSA which are pipeline safety laws requiring increased safety measures for natural gas and hazardous liquids pipelines. Among other things, the Pipeline Safety and Job Creation Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, material strength testing and verification of the maximum allowable pressure of certain pipelines. The Pipeline Safety and Job Creation Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and from $1.0 million to $2.0 million for a related series of violations. Effective July 31, 2019, to account for inflation, those maximum civil penalties were increased to $218,647 per violation per day, with a maximum of $2,186,465 for a related series of violations. The PIPES Act ensures that the PHMSA completes the Pipeline Safety and Job Creation Act requirements; reforms PHMSA to be a more dynamic, data-driven regulator; and closes gaps in federal standards.

On October 1, 2019, PHMSA published final rules to expand its integrity management requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside High Consequence Areas. The rules, once effective, also extend reporting requirements to certain previously unregulated gathering lines. The safety enhancement requirements and other provisions of the Pipeline Safety and Job Creation Act and the PIPES Act, as well as any implementation of PHMSA rules thereunder and/or related rule making proceedings, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in increased operating costs that could have a material adverse effect on our or Rattler LLC’s results of operations or financial position.

If third party pipelines or other facilities interconnected to Rattler LLC’s midstream systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our midstream operations could be adversely affected.

Our subsidiary Rattler LLC’s midstream systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport, treat or process natural gas or crude oil, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our midstream operations could be adversely affected.

Rattler LLC’s rates are subject to review by federal regulators, which could adversely affect our revenues.

Our subsidiary Rattler LLC has a tariff on file with FERC to gather crude oil in interstate commerce. Pipelines that gather or transport crude oil for third parties in interstate commerce are, among other things, subject to regulation of the rates and terms and conditions of service by the FERC. Rattler is also subject to annual reporting requirements and may also be required to respond to requests for information from government agencies, including compliance audits conducted by FERC.


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We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes.  Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We have employment agreements with these executives which contain restrictions on competition with us in the event they cease to be employed by us. However, as a practical matter, such employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.

Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

unusual or unexpected geological formations;

loss of drilling fluid circulation;

title problems;

facility or equipment malfunctions;

unexpected operational events;

shortages or delivery delays of equipment and services;

compliance with environmental and other governmental requirements; and

adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time.

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However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operations.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

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Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.

We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Increased costs of capital could adversely affect our business.

Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. We require continued

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access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and cash flows.

We recorded stock-based compensation expense in 2019, 2018 and 2017, and we may incur substantial additional compensation expense related to our future grants of stock compensation which may have a material negative impact on our operating results for the foreseeable future.

As a result of outstanding stock-based compensation awards, for the years ended December 31, 2019, 2018 and 2017 we incurred $65 million, $37 million and $34 million, respectively, of stock based compensation expense, of which we capitalized $17 million, $10 million and $9 million respectively, pursuant to the full cost method of accounting for oil and natural gas properties. In addition, our compensation expenses may increase in the future as compared to our historical expenses because of the costs associated with our existing and possible future incentive plans. These additional expenses could adversely affect our net income. The future expense will be dependent upon the number of share-based awards issued and the fair value of the options or shares of common stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of its vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.

Risks Related to Our Indebtedness

References in this section to “us, “we” or “our” shall mean Diamondback Energy, Inc. and Diamondback O&G LLC, collectively, unless otherwise specified.

We have relied in the past, and we may rely from time to time in the future, on borrowings under our revolving credit facility to fund a portion of our capital expenditures. Unless we are able to repay borrowings under the revolving credit facility with

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cash flow from operations and proceeds from equity or debt offerings, implementing our capital programs may require an increase in our total leverage through additional debt issuances. In addition, a reduction in availability under our revolving credit facility and the inability to otherwise obtain financing for our capital programs could require us to curtail our capital expenditures.

We have historically relied on availability under our revolving credit facility to fund a portion of our capital expenditures. We expect that we will continue to fund a portion of our capital expenditures with borrowings under the revolving credit facility, cash flow from operations and the proceeds from debt and equity offerings. In the past, we have created availability under the revolving credit facility by repaying outstanding borrowings with the proceeds from debt or equity offerings. We cannot assure you that we will choose to or be able to access the capital markets to repay any such future borrowings. Instead, we may be required or choose to finance our capital expenditures through additional debt issuances, which would increase our total amount of debt outstanding. If the availability under the revolving credit facility were reduced, and we were otherwise unable to secure other sources of financing, we may be required to curtail our capital expenditures, which could limit our ability to fund our drilling activities and acquisitions or otherwise finance the capital expenditures necessary to replace our reserves.

Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.

As of December 31, 2019, we had total long-term debt of $5.4 billion, including $4.3 billion outstanding under our 5.375% Senior Notes due 2025, which we refer to as the 2025 Notes, the Energen Notes, our 2.875% Senior Notes due 2024, our 3.250% Senior Notes due 2026 and our 3.500% Senior Notes due 2029, which are collectively referred to, together with the 2025 Notes, as the senior notes, and $13 million outstanding under our revolving credit facility, and we had $1.99 billion available for borrowing under our revolving credit facility. As of December 31, 2019, Energen, one of our subsidiaries, had $539 million, which are collectively referred to as the Energen Notes. As of December 31, 2019, Viper LLC, one of our subsidiaries, had $97 million in outstanding borrowings, and $678 million available for borrowing, under its revolving credit facility and $500 million outstanding under its 5.375% Senior Notes due 2027. As of December 31, 2019, Rattler LLC, one of our subsidiaries, had $424 million in outstanding borrowings, and $176 million available for borrowing, under its revolving credit facility. We may in the future incur significant additional indebtedness under our revolving credit facility or otherwise in order to make acquisitions, to develop our properties or for other purposes. Our level of indebtedness could have important consequences to you and affect our operations in several ways, including the following:

our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our debt instruments, including any repurchase obligations that may arise thereunder;

a significant portion of our cash flows could be used to service our indebtedness, which could reduce the funds available to us for operations and other purposes;

our high level of debt could increase our vulnerability to general adverse economic and industry conditions;
the covenants contained in the agreements governing certain of our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

our high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to, changes in the economy and in our industry;

our high level of debt could limit our ability to access the capital markets to raise capital on favorable terms;
our high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and

we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.

Our high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our

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ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

Restrictive covenants in certain of our existing and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.

Certain of our debt instruments contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things:

incur or guarantee additional indebtedness;

make certain investments;

create liens;

sell or transfer assets;

issue preferred stock;

merge or consolidate with another entity;

pay dividends or make other distributions;

create unrestricted subsidiaries; and

engage in transactions with affiliates.

Under our revolving credit facility we are allowed, among other things, to designate one or more of our subsidiaries as “unrestricted subsidiaries” that are not subject to certain restrictions contained in the revolving credit facility. Under our revolving credit facility, we designated Viper, Viper’s general partner, Viper’s subsidiary, Rattler, Rattler’s general partner and Rattler’s subsidiaries as unrestricted subsidiaries, and upon such designation, they were automatically released from any and all obligations under the revolving credit facility, including the related guaranty. Further Viper, Viper’s general partner, Viper’s subsidiaries, Rattler, Rattler’s general partner and Rattler’s subsidiaries are designated as unrestricted subsidiaries under the indentures governing our outstanding senior notes.

We and our subsidiaries may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants and financial covenants contained in our and our subsidiaries’ debt instruments. As an example, our revolving credit facility requires us to maintain a total net debt to capitalization ratio. The requirement that we and our subsidiaries comply with these provisions may materially adversely affect our and our subsidiaries ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

A breach of any of these restrictive covenants could result in default under the applicable debt instrument. If default occurs under our revolving credit facility, the lenders thereunder may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.

Our indebtedness is structurally subordinated to the indebtedness and other liabilities of our subsidiaries, and our obligations are not obligations of any of our subsidiaries.

Our senior indebtedness obligations are obligations exclusively of Diamondback Energy, Inc. and Diamondback O&G LLC, and not of any of our other subsidiaries. None of our subsidiaries is a guarantor of our senior indebtedness. Any assets of our subsidiaries will not be directly available to satisfy the claims of our creditors, including lenders under our revolving credit facility and holders of the senior notes. Except to the extent we are a creditor with recognized claims against our subsidiaries, all claims of creditors of our subsidiaries will have priority over our equity interests in such subsidiaries (and therefore the claims of our creditors, including lenders under our revolving credit facility and holders of the senior notes) with respect to the assets of such subsidiaries. Even if we are recognized as a creditor of one or more of our subsidiaries, our claims would still be effectively

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subordinated to any security interests in the assets of any such subsidiary and to any indebtedness or other liabilities of any such subsidiary senior to our claims. Consequently, our senior indebtedness will be structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries and any subsidiaries that we may in the future acquire or establish, As of December 31, 2019, Energen, one of our subsidiaries, had an aggregate of $539 million of notes, which are collectively referred to as the Energen Notes. As of December 31, 2019, Viper LLC, one of our subsidiaries, had $97 million in outstanding borrowings, and $678 million available for borrowing, under its revolving credit facility and $500 million outstanding under its 5.375% Senior Notes due 2027. As of December 31, 2019, Rattler LLC, one of our subsidiaries, had $424 million in outstanding borrowings, and $176 million available for borrowing, under its revolving credit facility.

Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.

Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. The indenture governing the 2025 Notes restricts our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.

We depend on our subsidiaries for dividends, distributions and other payments.

We depend on our subsidiaries for dividends, distributions and other payments. We are a legal entity separate and distinct from our operating subsidiaries. There are statutory and regulatory limitations on the payment of dividends or distributions by certain of our subsidiaries to us. If our subsidiaries are unable to make dividend or distribution payments to us and sufficient cash or liquidity is not otherwise available, we may not be able to make dividend payments to our stockholders or principal and interest payments on our outstanding indebtedness.

We and our subsidiaries may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our and our subsidiaries’ revolving credit facilities and the indentures restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2019, we had $13 million outstanding under our revolving credit facility, and we had $1.99 billion available for borrowing under our revolving credit facility As of December 31, 2019, Viper LLC had $97 million in outstanding borrowings, and $678 million available for borrowing, under its revolving credit facility. As of December 31, 2019, Rattler LLC had $424 million in outstanding borrowings, and $176 million available for borrowing, under its revolving credit facility. Further, the indentures governing our and our subsidiaries’ notes allow us to issue additional notes incur certain other additional debt and to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset

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purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

Borrowings under our, Viper LLC’s and Rattler LLC’s revolving credit facilities expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our and our subsidiaries’ revolving credit facilities. The terms of our and our subsidiaries’ revolving credit facilities provide for interest on borrowings at a floating rate equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.0% in the case of the alternative base rate and from 1.125% to 2.0% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. Both Viper LLC’s and Rattler LLC’s revolving credit facilities provide for interest on borrowings at floating rates, which are also tied to LIBOR. LIBOR tends to fluctuate based on multiple facts, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. We have not hedged our interest rate exposure with respect to our floating rate debt. Accordingly, our interest expense for any particular period will fluctuate based on LIBOR and other variable interest rates. As of December 31, 2019, we had $13 million borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 3.20% on December 31, 2019. Viper LLC’s weighted average interest rate on borrowings from its revolving credit facility was 4.30% during the year ended December 31, 2019. Rattler LLC’s weighted average interest rate on borrowings from its revolving credit facility was 2.98% during the year ended December 31, 2019. As of December 31, 2019, Viper LLC had $97 million in outstanding borrowings, and $678 million available for borrowing, under its revolving credit facility. As of December 31, 2019, Rattler LLC had $424 million in outstanding borrowings, and $176 million available for borrowing, under its revolving credit facility. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

On July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established or if LIBOR will continue to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United States or elsewhere.

Risks Related to Our Common Stock

The corporate opportunity provisions in our certificate of incorporation could enable affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our certificate of incorporation, among other things:

permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;

permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.


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We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

In the past, we have engaged in transactions with affiliated companies and may do so again in the future. These transactions, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests.

If the price of our common stock fluctuates significantly, your investment could lose value.

Although our common stock is listed on the Nasdaq Select Global Market, we cannot assure you that an active public market will continue for our common stock. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:

our quarterly or annual operating results;

changes in our earnings estimates;

investment recommendations by securities analysts following our business or our industry;

additions or departures of key personnel;

changes in the business, earnings estimates or market perceptions of our competitors;

our failure to achieve operating results consistent with securities analysts’ projections;
 
changes in industry, general market or economic conditions; and

announcements of legislative or regulatory changes.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

The declaration of dividends and repurchases of our common stock are each within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchases of our common stock in the future or at levels anticipated by our stockholders.
On February 13, 2018, we initiated payment of quarterly cash dividends on our common stock payable beginning with the first quarter of 2018. The decision to pay any future dividends, however, is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns to our stockholders.
In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. This repurchase program is at the discretion of our board of directors and may be suspended from time to time, modified, extended or discontinued by our board of directors at any time.


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A change of control could limit our use of net operating losses.

If we were to experience an “ownership change,” as determined under Section 382 of the Code, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code) at any time during a rolling three-year period.

As of December 31, 2019, we had a net operating loss, or NOL, carry forward of approximately $1.7 billion for federal income tax purposes, including $748 million acquired as part of the Energen acquisition. Although the NOL, and tax credits of $3 million, attributable to Energen’s pre-acquisition activity are subject to an annual limitation under Section 382 of the Code, we do not expect that limitation to materially impact our utilization of those amounts

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrade our stock or if our operating results do not meet their expectations, our stock price could decline.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
 
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;

limitations on the ability of our stockholders to call a special meeting and act by written consent;

the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws;

the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors;

the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and

the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.


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These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

We are a party to various legal proceedings, disputes and claims arising in the course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

For additional information regarding contingencies, see Note 18—Commitments and Contingencies included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.



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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Listing and Holders of Record
Our common stock is listed on the Nasdaq Select Global Market under the symbol “FANG”. There were 20 holders of record of our common stock on February 13, 2020.

Dividend Policy 

On February 13, 2018, we announced the initiation of an annual cash dividend in the amount of $0.50 per share of our common stock payable quarterly which began with the first quarter of 2018. Beginning with the first quarter of 2019, the annual cash dividend was increased to $0.75 per share of our common stock. Additionally, beginning with the fourth quarter of 2019, the annual cash dividend was increased to $1.50 per share of our common stock. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.

Repurchases of Equity Securities

Our common stock repurchase activity for the year ended December 31, 2019 was as follows:
Period Total Number of Shares Purchased 
Average Price Paid Per Share(1)
 Total Number of Shares Purchased as Part of Publicly Announced Plan 
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(2)
  ($ in millions, except per share amounts, shares in thousands)
January 2019 0 $
 0 $2,000
February 2019(3)
 108 $102.14
 0 $2,000
March 2019(3)
 17 $102.93
 0 $2,000
April 2019 0 $
 0 $2,000
May 2019 40 $100.86
 40 $1,996
June 2019 976 $102.04
 976 $1,896
July 2019 995 $105.56
 995 $1,791
August 2019 1,252 $97.53
 1,252 $1,669
September 2019 707 $97.29
 707 $1,600
October 2019 812 $84.97
 812 $1,531
November 2019 994 $78.16
 994 $1,454
December 2019(4)
 609 $85.08
 609 $1,402
Total 6,510 $93.83
 6,385  
(1)The average price paid per share is net of any commissions paid to repurchase stock.
(2)In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. This repurchase program may be suspended from time to time, modified, extended or discontinued by our board of directors at any time.
(3)Acquired in connection with tax withholdings and payment of exercise price on equity compensation plans.
(4)Includes 108,942 shares that had not settled as of December 31, 2019.


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ITEM 6. SELECTED FINANCIAL DATA

This section presents our selected historical combined consolidated financial data. The selected historical combined consolidated financial data presented below is not intended to replace our historical consolidated financial statements. You should read the following data along with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report on Form 10-K.

Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years ended December 31, 2019, 2018 and 2017 and the balance sheet data as of December 31, 2019 and 2018 are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The historical financial data for the year ended December 31, 2016 and 2015 and the balance sheet data as of December 31, 2017, 2016 and 2015 are derived from our audited financial statements not included in this Annual Report on Form 10-K.
 Year Ended December 31,
(In millions, except per share amounts, shares in thousands)2019 
2018(1)
 2017 2016 2015
Statements of Operations Data:         
Total revenues$3,964
 $2,176
 $1,205
 $527
 $447
Total costs and expenses3,269
 1,165
 600
 596
 1,187
Income (loss) from operations695
 1,011
 605
 (69) (740)
Other income (expense)(333) 102
 (108) (96) (9)
Income (loss) before income taxes362
 1,113
 497
 (165) (749)
Provision for (benefit from) income taxes47
 168
 (20) 
 (201)
Net income (loss)315
 945
 517
 (165) (548)
Less: Net income attributable to non-controlling interest75
 99
 35
 
 3
Net income (loss) attributable to Diamondback Energy, Inc.$240
 $846
 $482
 $(165) $(551)
Earnings per common share:         
Basic$1.47
 $8.09
 $4.95
 $(2.20) $(8.74)
Diluted$1.47
 $8.06
 $4.94
 $(2.20) $(8.74)
Weighted average common shares outstanding:         
Basic163,493
 104,622
 97,458
 75,077
 63,019
Diluted163,843
 104,929
 97,688
 75,077
 63,019
Cash dividends declared per common share$0.9375
 $0.5000
 $
 $
 $
(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 Energen merger, through December 31, 2018.

 As of December 31,
(In millions)2019 2018 2017 2016 2015
Balance Sheet Data:         
Cash and cash equivalents$123
 $215
 $112
 $1,666
 $20
Net property and equipment21,835
 20,372
 7,344
 3,391
 2,598
Total assets23,531
 21,596
 7,771
 5,350
 2,751
Current liabilities1,263
 1,019
 577
 209
 141
Long-term debt5,371
 4,464
 1,477
 1,106
 488
Total stockholders’/ members’ equity(1)
13,249
 13,700
 5,255
 3,697
 1,876
Total equity$14,906
 $14,167
 $5,582
 $4,018
 $2,109

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 Year Ended December 31,
(In millions)2019 2018 2017 2016 2015
Other Financial Data:         
Net cash provided by operating activities$2,734
 $1,565
 $889
 $332
 $417
Net cash used in investing activities$(3,888) $(3,503) $(3,132) $(1,310) $(895)
Net cash provided by financing activities$1,062
 $2,041
 $689
 $2,625
 $468
 Year Ended December 31,
(In millions)2019 2018 2017 2016 2015
Consolidated Adjusted EBITDA(2)
$2,949
 $1,538
 $928
 $388
 $449
(1)For the years ended December 31, 2019, 2018, 2017, 2016 and 2015, total stockholders’ equity excludes $738 million, $467 million, $327 million, $321 million and $233 million, respectively, of non-controlling interest related to Viper Energy Partners LP. For the year ended December 31, 2019, total stockholders’ equity excludes $919 million of non-controlling interest related to Rattler Midstream 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.

Non-GAAP financial measure and reconciliation

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) plus non-cash (gain) loss on derivative instruments, net, net interest expense, depreciation, depletion and amortization expense, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, (gain) loss on revaluation of investment, loss on extinguishment of debt, merger and integration expense, income tax (benefit) provision and non-controlling interest in net (income) loss. Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We add the items listed above to net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies or to such measure in our revolving credit facility or any of our other contracts.


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The following presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss):
 Year Ended December 31,
(In millions)2019 2018 2017 2016 2015
Net income (loss)$315
 $945
 $517
 $(165) $(548)
Non-cash loss (gain) on derivative instruments, net188
 (222) 84
 27
 113
Interest expense, net172
 87
 41
 41
 41
Depreciation, depletion and amortization1,447
 623
 327
 178
 218
Impairment of oil and natural gas properties790
 
 
 246
 815
Non-cash equity-based compensation expense65
 37
 34
 33
 24
Capitalized equity-based compensation expense(17) (10) (9) (7) (6)
Asset retirement obligation accretion expense7
 2
 1
 1
 1
Loss on extinguishment of debt56
 
 
 33
 
Gain (loss) on revaluation of investment(5) 1
 
 
 
Merger and integration expense
 36
 
 
 
Income tax (benefit) provision47
 168
 (20) 
 (201)
Consolidated Adjusted EBITDA3,065
 1,667
 975
 387
 457
Non-controlling interest in net (income) loss(116) (129) (47) 1
 (8)
Adjusted EBITDA attributable to Diamondback Energy, Inc.$2,949
 $1,538
 $928
 $388
 $449



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ITEM 7.         MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto appearing elsewhere in this Annual Report on Form 10–K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Item 1A. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We operate in two business segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas and (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.

Upstream Operations

In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

As of December 31, 2019, we had approximately 382,337 net acres, which primarily consisted of approximately 195,461 net acres in the Midland Basin and approximately 155,296 net acres in the Delaware Basin. As of December 31, 2019, we had an estimated 12,310 gross horizontal locations that we believe to be economic at $60.00 per Bbl West Texas Intermediate, or WTI.

In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 814,224 gross acres and 24,304 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 50% of these net royalty acres are operated by us. We own Viper’s general partner and, together with one of our subsidiaries, approximately 58% of the limited partner interest in Viper, represented by common units and Class B units. We, as the holder of the Class B units in Viper and Viper’s general partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective capital contributions payable quarterly.

Midstream Operations

In our midstream operations segment, Rattler’s crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for its customers. Rattler’s facilities gather crude oil from horizontal and vertical wells in our ReWard, Spanish Trail, Pecos and Fivestones areas within the Permian Basin. Rattler’s natural gas gathering and compression system consists of gathering pipelines, compression and metering facilities, which collectively service the production from our Pecos area assets within the Permian Basin. Rattler’s water sourcing and distribution assets consists of water wells, frac pits, pipelines and water treatment facilities, which collectively gather and distribute water from Permian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Rattler’s gathering and disposal system spans approximately 474 miles and consists of gathering pipelines along with produced water disposal, or PWD, wells and facilities which collectively gather and dispose of produced water from operations throughout our Permian Basin acreage.

We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler’s infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in the Delaware and Midland Basins. Our agreements with Rattler include substantial acreage dedications.


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2019 Transactions and Recent Developments

Rattler Midstream LP

Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR”. Rattler was formed by us in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler Midstream GP LLC, or Rattler’s General Partner, a wholly-owned subsidiary of us, serves as the general partner of Rattler. As of December 31, 2019, we owned approximately 71% of Rattler’s total units outstanding.

In May 2019, Rattler completed its initial public offering, which we refer to as the Rattler Offering. Prior to the completion of the Rattler Offering, we owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of an aggregate of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of $17.50 per common unit, which included 5,700,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms which closed on May 30, 2019. Rattler received net proceeds of approximately $720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions.
In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a $1 million cash contribution from us, (ii) issued a general partner interest in Rattler to Rattler’s general partner, in exchange for a $1 million cash contribution from Rattler’s general partner, and (iii) caused Rattler LLC to make a distribution of approximately $727 million to us. We, as the beneficial holder of the Class B units, and Rattler’s general partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly.

Fourth Quarter 2019 Dividend Declaration and Increase

On February 14, 2020, our board of directors declared a cash dividend for the fourth quarter of 2019 of $0.3750 per share of common stock, payable on March 10, 2020 to our stockholders of record at the close of business on March 3, 2020, representing an increase of $0.1875 per share from the previously paid quarterly dividend.

Stock Repurchase Program

In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. This repurchase program is another component of our capital return program that includes the quarterly dividend discussed above. We anticipate that the repurchase program will be funded primarily by free cash flow generated from operations and liquidity events such as the sale of assets. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require us to acquire any specific number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the year ended December 31, 2019, we repurchased approximately $598 million of common stock under our repurchase program. As of December 31, 2019, $1.4 billion remains available for use to repurchase shares under our common stock repurchase program.

Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen

On May 23, 2019, we completed our divestiture of 6,589 net acres of certain non-core Permian assets, which we acquired in the Energen merger, for an aggregate sale price of $37 million. This divestiture did not result in a gain or loss because it did not have a significant effect on our reserve base or depreciation, depletion and amortization rate.

On July 1, 2019, we completed our divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which we acquired in the Energen merger, for an aggregate sale price of $285 million. This divestiture did not result in a gain or loss because it did not have a significant effect on our reserve base or depreciation, depletion and amortization rate.

Viper’s Equity Offering

On March 1, 2019, Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, we owned approximately 54% of Viper’s total units then outstanding. Viper received net proceeds from this offering

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of approximately $341 million, after deducting underwriting discounts and commissions and estimated offering expenses. Viper used the net proceeds to purchase units of Viper LLC. Viper LLC in turn used the net proceeds to repay a portion of the outstanding borrowings under its revolving credit facility and finance acquisitions during the period.

Drop-Down
On October 1, 2019, we completed a transaction to divest certain mineral and royalty interests to Viper for 18.3 million of Viper’s newly-issued Class B units, 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits, which we refer to as the Drop-Down. The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by us, and have an average net royalty interest of approximately 3.2%.
Increase in the Borrowing Base under Viper LLC’s Revolving Credit Facility

In connection with Viper LLC’s fall redetermination in November 2019, the borrowing base under Viper LLC’s revolving credit facility was increased from $725 million to $775 million.

Viper’s Notes Offering
 
On October 16, 2019, Viper completed an offering, which we refer to as the Viper Notes Offering, of $500 million in aggregate principal amount of its 5.375% senior notes due 2027, which we refer to as the Viper Notes. Viper received net proceeds of approximately $490 million from the Viper Notes Offering. Viper loaned the gross proceeds to Viper LLC. Viper LLC used the proceeds from the Viper Notes Offering to pay down borrowings under its revolving credit facility.

December 2019 Notes Offering

On December 5, 2019, we issued $1.0 billion in aggregate principal amount of 2.875% senior notes due 2024, which we refer to as the 2024 notes, $800 million in aggregate principal amount of 3.250% senior notes due 2026, which we refer to as the 2026 notes, and $1.2 billion aggregate principal amount of 3.500% senior notes due 2029, which we refer to as the 2029 notes and, together with the 2024 notes and the 2026 notes, the December 2019 Notes. The 2024 notes will mature on December 1, 2024, the 2026 notes will mature on December 1, 2026 and the 2029 notes will mature on December 1, 2029. Interest will accrue and be payable semi-annually, in arrears on June 1 and December 1 of each year, commencing on June 1, 2020. The December 2019 Notes are fully and unconditionally guaranteed by Diamondback O&G LLC.

Redemption of the Outstanding 4.750% Senior Notes.

On December 20, 2019, we redeemed all of our then outstanding 4.750% Senior Notes due 2024, which we refer to as the 4.750% senior notes, with a portion of our net proceeds from the issuance of the December 2019 Notes.

Operational Update

Our development program is focused entirely within the Permian Basin, where we continue to focus on long-lateral multi-well pad development. Our horizontal development consists of multiple targeted intervals, primarily within the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Springs formations in the Delaware Basin.

We are operating 23 drilling rigs now including two rigs drilling produced water disposal wells and currently intend to operate between 20 and 23 drilling rigs in 2020 on average across our asset base in the Midland and Delaware Basins.

In the Midland Basin, we continued to have positive results across our core development areas located within Midland, Martin, Howard, Glasscock and Andrews counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations.

In the Delaware Basin, we have now drilled and completed a significant number of wells in Pecos, Reeves and Ward counties targeting the Wolfcamp A, which we believe has been de-risked across a significant portion of our total acreage position and remains our primary development target. In 2020, we expect to focus development on these areas.

We continue to focus on low cost operations and best in class execution. To combat potential fluctuation in service costs, we have looked to lock in pricing for dedicated activity levels and will continue to seek opportunities to control additional well cost where possible. Our 2020 drilling and completion budget accounts for capital costs that we believe cover potential increases in our service costs during the year.

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In 2020, we remain focused on navigating our industry challenges by staying disciplined, improving our industry-leading cost structure, growing production, increasing environmental transparency and returning more cash to our stockholders as evidenced by our quarterly dividend increase beginning with the fourth quarter of 2019.

2020 Capital Budget

We have currently budgeted a 2020 total capital spend of $2.8 billion to $3.0 billion, consisting of $2.45 billion to $2.6 billion for horizontal drilling and completions including non-operated activity, $200 million to $225 million for midstream investments, excluding joint venture investments, and $150 million to $175 million for infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions. We expect to drill and complete 320 to 360 gross horizontal wells in 2020. Should commodity prices weaken further or remain weak for an extended period of time, we intend to act responsibly and, consistent with our prior practices, reduce capital spending. If commodity prices strengthen, we intend to grow oil production within our 2020 budget and return cash to our stockholders or pay down indebtedness.

Reserves and pricing

Ryder Scott prepared estimates of our proved reserves at December 31, 2019 and 2018 (which include estimated proved reserves attributable to Viper). The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
 As of December 31,
 2019 2018
Estimated Net Proved Reserves:   
Oil (MBbls)710,903
 626,936
Natural gas (MMcf)1,118,811
 1,048,649
Natural gas liquids (MBbls)230,203
 190,291
Total (MBOE)1,127,575
 992,001
 Unweighted Arithmetic Average
 First-Day-of-the-Month Prices
 2019 2018
Oil (per Bbl)$51.88
 $59.63
Natural gas (per Mcf)$0.18
 $1.47
Natural gas liquids (per Bbl)$15.65
 $24.43

Sources of our revenue

In our upstream segment, our main sources of revenues are the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing.
In our midstream operations segment, our results are primarily driven by: the volumes of crude oil that Rattler gathers, transports and delivers; natural gas that Rattler gathers, compresses, transports and delivers; water that Rattler sources, transports and delivers; and produced water that Rattler gathers, transports and disposes of, and the fees Rattler charges per unit of throughput for our midstream services.


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The following table presents the sources of our oil and natural gas revenues for the years presented:
 Year Ended December 31,
 2019 2018
Revenues:   
Oil sales91% 88%
Natural gas sales2% 3%
Natural gas liquid sales7% 9%
 100% 100%
 
Commodity Prices

Since our production, in our exploration and production business, consists primarily of oil, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas or natural gas liquids prices. Viper, as the owner of mineral interests, is also indirectly exposed to fluctuations in commodity prices. Oil, natural gas and natural gas liquids prices have historically been volatile. Lower commodity prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be redetermined at the discretion of our lenders.

In our midstream operations business, we have indirect exposure to commodity price risk in that persistent low commodity prices may cause us or Rattler’s other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If we or Rattler’s other customers delay drilling or temporarily shut in production due to persistently low commodity prices or for any other reason, our revenue in the midstream operations segment could decrease, as Rattler’s commercial agreements do not contain minimum volume commitments.

The following table sets forth information related to commodity prices for the following periods:

 Year Ended December 31,
 2019 2018
High and Low Futures Contract Prices:   
Oil ($/Bbl, WTI Futures Contract 1)   
High$66.30
 $76.41
Low$46.54
 $42.53
Natural Gas ($/MMBtu, Futures Contract 1)   
High$3.59
 $4.84
Low$2.07
 $2.55
    
Average realized oil price ($/Bbl)$51.87
 $54.66
Average WTI Futures Contract 1 ($/Bbl)$57.04
 $64.90
Differential to WTI Futures Contract 1$(5.17) $(10.24)
Average realized oil price to WTI Futures Contract 191% 84%
    
Average realized natural gas price ($/Mcf)$0.68
 $1.76
Average Natural Gas Futures Contract 1 ($/Mcf)$2.53
 $3.07
Differential to Natural Gas Futures Contract 1$(1.85) $(1.31)
Average realized natural gas price to Natural Gas Futures Contract 127% 57%
    
Average realized natural gas liquids price ($/Bbl)$14.42
 $25.47
Average WTI Futures Contract 1 ($/Bbl)$57.04
 $64.90
Average realized natural gas liquids price to WTI Futures Contract 125% 39%

On December 31, 2019, the WTI Futures Contract 1 price for crude oil was $61.06 per Bbl and the Natural Gas Futures Contract 1 price was $2.19 per MMBtu.

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Principal components of our cost structure

Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.

Production and ad valorem taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

General and administrative expenses. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.

Midstream services expense. These are costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.

Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.

Impairment of oil and natural gas properties. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.

Other income (expense)

Interest income (expense). We have financed a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our revolving credit facility and our net proceeds from the issuance of the senior notes. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. This amount reflects interest paid to our lender plus the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees net of interest received on our cash and cash equivalents.

Gain (loss) on derivative instruments, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil. This amount represents (i) the recognition of the change in the fair value of open non-hedge derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into, and (ii) our gains and losses on the settlement of these commodity derivative instruments.

Deferred tax assets (liabilities). We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.


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Results of Operations

For a discussion of the results of operations for the year ended December 31, 2018 as compared to the year ended December 31, 2017 refer to Part II, Item 7. Management's Discussion and Analysis in our 2018 Form 10-K, which was filed with the SEC on February 25, 2019, which discussion is incorporated in this report by reference from such prior report on Form 10-K. The following table sets forth selected historical operating data for the periods indicated:

 Year Ended December 31,
 2019 2018
Production Data:   
Oil (MBbls)68,518
 34,367
Natural gas (MMcf)97,613
 34,669
Natural gas liquids (MBbls)18,498
 7,465
Combined volumes (MBOE)103,285
 47,610
    
Daily oil volumes (BO/d)187,721
 94,156
Daily combined volumes (BOE/d)282,972
 130,439
    
Average Prices:   
Oil ($ per Bbl)$51.87
 $54.66
Natural gas ($ per Mcf)$0.68
 $1.76
Natural gas liquids ($ per Bbl)$14.42
 $25.47
Combined ($ per BOE)$37.63
 $44.73
Oil, hedged ($ per Bbl)(1)
$51.96
 $51.20
Natural gas, hedged ($ per MMbtu)(1)
$0.86
 $1.72
Natural gas liquids, hedged ($ per Bbl)(1)
$15.20
 $25.46
Average price, hedged ($ per BOE)(1)
$38.00
 $42.20
(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.

Production Data

Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. The following tables set forth our production data for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
Oil (MBbls)66% 72%
Natural gas (MMcf)16% 12%
Natural gas liquids (MBbls)18% 16%
 100% 100%

Comparison of the Years Ended December 31, 2019 and 2018

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $1.8 billion, or 82%, to $3.9 billion for the year ended December 31, 2019 from $2.1 billion for the year ended December 31, 2018. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 152,533 BOE/d to 282,972 BOE/d during the year ended December 31, 2019 from 130,439 BOE/d during the year ended December 31, 2018. The total increase in revenue of approximately $1.8 billion is attributable to higher oil, natural gas liquids and natural gas production volumes, partially offset by lower average sales prices for the year ended December 31, 2019 as compared to the year ended December 31, 2018. The increase in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our

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production increased by 34,151 MBbls of oil, 62,944 MMcf of natural gas and 11,033 MBbls of natural gas liquids for the year ended December 31, 2019 as compared to the year ended December 31, 2018.

The net dollar effect of the change in prices of approximately $501 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the change in production of approximately $2.3 billion (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.
 Change in prices 
Production volumes(1)
 Total net dollar effect of change
     (in millions)
Effect of changes in price:     
Oil$(2.79) 68,518
 $(191)
Natural gas$(1.08) 97,613
 $(106)
Natural gas liquids$(11.05) 18,498
 $(204)
Total revenues due to change in price    $(501)
      
 
Change in production volumes(1)
 Prior period average prices Total net dollar effect of change
     (in millions)
Effect of changes in production volumes:     
Oil34,151
 $54.66
 $1,867
Natural gas62,944
 $1.76
 $110
Natural gas liquids11,033
 $25.47
 $281
Total change in revenues    $2,258
     $1,757
(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Lease Bonus Revenue. The following table shows lease bonus revenue for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
 (in millions)
Lease bonus revenue$4
 $3

Lease bonus revenue for the year ended December 31, 2019 was attributable to lease bonus payments of less than $1 million to extend the term of seven leases and lease bonus payments of $3 million on 12 new leases. Lease bonus revenue for the year ended December 31, 2018 was attributable to lease bonus payments of $1 million to extend the term of two leases and lease bonus payments of $2 million on five new leases.

Midstream Services Revenue. The following table shows midstream services revenue for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
 (in millions)
Midstream services revenue$64
 $34

Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.


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Lease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
(in millions, except per BOE amounts)AmountPer BOE AmountPer BOE
Lease operating expenses$490
$4.74
 $205
$4.31

Lease operating expenses for the year ended December 31, 2019 as compared to the year ended December 31, 2018 increased by $285 million, or $0.43 per BOE. In both cases, lease operating expenses increased primarily due to increased power generation costs as a result of reduced electrical availability as well as increased production and the higher cost of the Central Basin Platform assets which were divested during 2019. We are actively working to mitigate this issue and expect these costs to decrease in the future.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
(in millions, except per BOE amounts)AmountPer BOE AmountPer BOE
Production taxes$184
$1.78
 $104
$2.18
Ad valorem taxes64
0.62
 29
0.61
Total production and ad valorem expense$248
$2.40
 $133
$2.79

In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, among other factors, whereas production taxes are based upon current year commodity prices. Production taxes for the year ended December 31, 2019 as compared to the year ended December 31, 2018 increased by $80 million due to increased overall production from acquisitions and well completions. Production taxes per BOE for the year ended December 31, 2019 as compared to the year ended December 31, 2018 decreased by $0.40 primarily due to a higher percentage increase in production volumes as compared to production taxes. Ad valorem taxes for the year ended December 31, 2019 as compared to the year ended December 31, 2018 increased by $35 million due to the addition of acquired and completed wells from the latter half of 2019.

Midstream Services Expense. The following table shows midstream services expense for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
 (in millions)
Midstream services expense$91
 $72

Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities. Midstream services expense for the year ended December 31, 2019 as compared to the year ended December 31, 2018, increased by $19 million primarily due to increased volume and build out of the Rattler systems.


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Depreciation, Depletion and Amortization. The following table provides the components of our depreciation, depletion and amortization expense for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
 (in millions, except BOE amounts)
Depletion of proved oil and natural gas properties$1,398
 $595
Depreciation of midstream assets33
 19
Depreciation of other property and equipment16
 9
Depreciation, depletion and amortization expense$1,447
 $623
Oil and natural gas properties depreciation, depletion and amortization per BOE$13.54
 $12.62

The increase in depletion of proved oil and natural gas properties of $803 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018 resulted primarily from higher production levels and an increase in net book value on new reserves added.

Impairment of Oil and Natural Gas Properties. The following table shows impairment of oil and natural gas properties for the years ended December 31, 2019 and 2018:

 Year Ended December 31,
 2019 2018
 (in millions)
Impairment of oil and natural gas properties$790
 $

General and Administrative Expenses. The following table shows general and administrative expenses for the years ended December 31, 2019 and 2018:

 Year Ended December 31,
 2019 2018
(in millions, except per BOE amounts)AmountPer BOE AmountPer BOE
General and administrative expenses$56
$0.54
 $38
$0.79
Non-cash stock-based compensation48
0.46
 27
0.57
Total general and administrative expenses$104
$1.00
 $65
$1.36

General and administrative expenses for the year ended December 31, 2019 as compared to the year ended December 31, 2018 increased by $39 million primarily due to an increase in salaries and benefits as a result of increased head count.

Net Interest Expense. The following table shows net interest expense for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
 (in millions)
Net interest expense$172
 $87

Net interest expense for the year ended December 31, 2019 as compared to the year ended December 31, 2018, increased by $85 million. This increase was primarily due to increased average borrowings under our credit facility partially offset by a lower interest rate during the year ended December 31, 2019 as compared to the year ended December 31, 2018 as well as an increase in interest expense of $2 million related to our DrillCo Agreement.


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Derivatives. The following table shows the gain (loss) on derivative instruments, net for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
 (in millions)
Change in fair value of open non-hedge derivative instruments$(188) $222
Gain (loss) on settlement of non-hedge derivative instruments80
 (121)
Gain (loss) on derivative instruments$(108) $101

We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.”

Provision for Income Taxes. The following table shows provision for income taxes for the years ended December 31, 2019 and 2018:
 Year Ended December 31,
 2019 2018
 (in millions)
Provision for income taxes$47
 $168

The change in our income tax provision was primarily due to the decrease in pre-tax income for the year ended December 31, 2019 and the change in the deferred income tax benefit resulting from estimated deferred taxes recognized as a result of Viper’s change in tax status for the years ended December 31, 2019 and 2018.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of the senior notes and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. As we pursue reserves and production growth, we regularly consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.

Liquidity and Cash Flow

Our cash flows for the years ended December 31, 2019 and 2018 are presented below:
 Year Ended December 31,
 2019 2018
 (in millions)
Net cash provided by operating activities$2,734
 $1,565
Net cash used in investing activities(3,888) (3,503)
Net cash provided by financing activities1,062
 2,041
Net change in cash$(92) $103

Operating Activities

Net cash provided by operating activities was $2.7 billion for the year ended December 31, 2019 as compared to $1.6 billion for the year ended December 31, 2018. The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenues due to an increase in production during the year ended December 31, 2019, partially offset by lower average sales prices.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional

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and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See “–Sources of our revenue” and Item 1A. “Risk Factors” above.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cash for investing activities of $3.9 billion and $3.5 billion during the years ended December 31, 2019 and 2018, respectively.

During the year ended December 31, 2019, we spent (a) $2.7 billion on capital expenditures in conjunction with our drilling program, in which we drilled 330 gross (296 net) horizontal wells and completed 317 gross (289 net) operated horizontal wells, (b) $244 million on additions to midstream assets, (c) $333 million for the acquisition of mineral interests, (d) $443 million on leasehold acquisitions, (e) $5 million for the purchase of other property and equipment, (f) $1 million on investment in real estate and (g) $485 million on equity method investments.

During the year ended December 31, 2018, we spent (a) $1.5 billion on capital expenditures in conjunction with our drilling program, in which we drilled 189 gross (168 net) horizontal wells and completed 176 gross (155 net) operated horizontal wells, (b) $204 million on additions to midstream assets, (c) $440 million for the acquisition of mineral interests, (d) $1.4 billion on leasehold acquisitions, (e) $7 million for the purchase of other property and equipment and (f) $111 million on investment in real estate.

Our investing activities for the years ended December 31, 2019 and 2018 are summarized in the following table:
 Year Ended December 31,
 2019 2018
 (in thousands)
Drilling, completion and infrastructure$(2,677) $(1,461)
Additions to midstream assets(244) (204)
Acquisition of leasehold interests(443) (1,371)
Acquisition of mineral interests(333) (440)
Purchase of other property, equipment and land(5) (7)
Investment in real estate(1) (111)
Proceeds from sale of assets300
 80
Funds held in escrow
 11
Equity investments(485) 
Net cash used in investing activities$(3,888) $(3,503)

Financing Activities
    
References in this section to “us, “we” or “our” shall mean Diamondback Energy, Inc. and Diamondback O&G LLC, collectively, unless otherwise specified.

Net cash provided by financing activities for the years ended December 31, 2019 and 2018 was $1.1 billion and $2.0 billion, respectively.

During the year ended December 31, 2019, the amount provided by financing activities was primarily attributable to $341 million in net proceeds from Viper’s public offering completed on March 1, 2019, $720 million in net proceeds from the Rattler Offering, $39 million in proceeds from joint ventures and $2.2 billion in proceeds from the December 2019 Notes, net of repayments, partially offset by $1.4 billion of repayments, net of borrowings under our credit facility, $44 million of premium on debt extinguishment, $122 million of distributions to non-controlling interest, $13 million of share repurchases for tax withholdings, $593 million of share repurchases as part of our stock repurchase program and $112 million of dividends to stockholders.

During the year ended December 31, 2018, the amount provided by financing activities was primarily attributable to the issuance of $1.1 billion of new senior notes, $1.4 billion of borrowings, net of repayments under our credit facility, $559 million of repayments under Energen’s credit facility and an aggregate of $305 million of net proceeds from Viper’s public offerings, partially offset by $98 million of distributions to non-controlling interest and $37 million of dividends to stockholders.

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4.750% Senior Notes

On October 28, 2016, we issued $500.0 million in aggregate principal amount of 4.750% senior notes due 2024 under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On September 25, 2018, we issued $750 million aggregate principal amount of new 4.750% senior notes as additional notes under, and subject to the terms of the same indenture governing the 4.750% senior notes. We received approximately $741 million in net proceeds, after deducting the initial purchasers’ discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the 4.750% senior notes. We used a portion of the net proceeds from the issuance of the 4.750% senior notes to repay a portion of the outstanding borrowings our revolving credit facility and the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of certain assets from Ajax Resources LLC.

On December 20, 2019, we redeemed all of the outstanding 4.750% senior notes, which we refer to as the Redemption Date. The redemption payment, which we refer to the Redemption Payment, included $1.25 billion of outstanding principal at a redemption price of 103.563% of the principal amount of the 4.750% senior notes, plus accrued and unpaid interest on the outstanding principal amount to the Redemption Date. On December 5, 2019, the indenture governing the 4.750% senior notes was fully satisfied and discharged and the guarantors were released from their guarantees of the 4.750% senior notes. The 4.750% senior notes, which bore interest at 4.750% per year, were scheduled to mature on November 1, 2024. On the Redemption Date, the Redemption Price will be paid to the holders of the 4.750% senior notes. We funded the Redemption Payment with a portion of our net proceeds from the issuance of the December 2019 Notes.

The 4.750% senior notes, bore interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017, and would have matured on November 1, 2024. All of our restricted subsidiaries that guaranteed our revolving credit facility guaranteed the 4.750% senior notes; provided, however, that the 4.750% senior notes were not guaranteed by Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner or Rattler LLC.

2025 Senior Notes

On December 20, 2016, we issued $500.0 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the exiting 2025 notes, under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, which we refer to as the 2025 indenture. On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture, which we refer to as the new 2025 notes and, together with the existing 2025 notes, as the 2025 senior notes. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.
The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility guarantee the 2025 senior notes. Currently, the 2025 senior notes are not guaranteed by any of our subsidiaries other than Diamondback O&G LLC and will not be guaranteed by any of our future unrestricted subsidiaries.
For additional information regarding the 2025 senior notes, see Note 10—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.

December 2019 Notes Offering

On December 5, 2019, we issued $1.0 billion in aggregate principal amount of 2.875% senior notes due 2024, $800 million in aggregate principal amount of 3.250% senior notes due 2026 and $1.2 billion aggregate principal amount of 3.500% senior notes due 2029. The 2024 notes will mature on December 1, 2024, the 2026 notes will mature on December 1, 2026 and the 2029 notes will mature on December 1, 2029. Interest will accrue and be payable semi-annually, in arrears on June 1 and December 1 of each year, commencing on June 1, 2020. The December 2019 notes are fully and unconditionally guaranteed by Diamondback O&G LLC and are not guaranteed by any of our other subsidiaries.

The December 2019 notes were issued under an indenture, dated as of December 5, 2019, among us and Wells Fargo Bank, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019, which we refer to as the December 2019 Notes Indenture. The December 2019 Notes Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of certain of our subsidiaries to incur liens

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securing funded indebtedness and on our ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of our assets.
For additional information regarding the December 2019 Notes, see Note 10—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.

Second Amended and Restated Credit Facility

We and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. On June 28, 2019, the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied (the “investment grade changeover date”). At December 31, 2019, the maximum credit amount available under the credit agreement is $2.0 billion. As of December 31, 2019, we had approximately $13 million of outstanding borrowings under our revolving credit facility and $1.99 billion available for future borrowings under our revolving credit facility.
Diamondback O&G LLC is the borrower under the credit agreement, and as of December 31, 2019, the credit agreement is guaranteed by Diamondback Energy, Inc. None of our other subsidiaries are guarantors under our revolving credit facility. On December 5, 2019, Diamondback O&G LLC delivered a letter notifying the administrative agent under the credit agreement that as of such date, each of the guarantors, other than Diamondback Energy, Inc., ceased to be a guarantor under the credit agreement.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.0% per annum and from 1.125% to 2.0% per annum in the case of LIBOR, in each case, depending on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt.
Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction of the aggregate maximum credit amount and (b) at the maturity date of November 1, 2022.
The credit agreement contains a financial covenant that requires us to maintain a total net debt to capitalization ratio (as defined in the credit agreement) of no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets.

As of December 31, 2019, we were in compliance with all financial covenants under our revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

Energen Notes

At the effective time of the merger, Energen became our wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes, which we refer to as the Energen Notes, issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee, which we refer to as the Energen Indenture. As of December 31, 2019, the Energen Notes consist of: (a) $399 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $108 million of 7.125% notes due on February 15, 2028, (3) $21 million of 7.32% notes due on July 28, 2022, and (4) $11 million of 7.35% notes due on July 28, 2027.

The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as our wholly owned subsidiary, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen if any, and are effectively subordinated to Energen’s senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. Neither we nor any of our subsidiaries guarantee the Energen Notes.

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For additional information regarding the Energen Notes, See Note 10—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.

Viper’s Facility-Wells Fargo Bank

On July 20, 2018, Viper LLC, as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended, which we refer to as the Viper credit agreement, provides for a revolving credit facility in the maximum credit amount of $2 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $775 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. In connection with Viper’s fall redetermination in November 2019, the borrowing base under the Viper credit agreement was increased to $775 million. As of December 31, 2019, the borrowing base was $775 million, and Viper LLC had $97 million of outstanding borrowings and $678 million available for future borrowings under the Viper credit agreement. Neither we nor any of our other subsidiaries guarantee the Viper credit agreement.

The outstanding borrowings under the Viper credit agreement bear interest at a per annum rate elected by Viper LLC that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. Viper LLC is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of Viper and Viper LLC.

The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial CovenantRequired Ratio
Ratio of total net debt to EBITDAX, as defined in the Viper credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the Viper credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $1.0 billion in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. The covenant limiting dividends and distributions includes an exception allowing Viper LLC to make distributions if no default, event of default or borrowing base deficiency exists.

As of December 31, 2019, Viper and Viper LLC were in compliance with all financial covenants under the Viper credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

Viper’s Notes

On October 16, 2019, Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of $500 million. Viper received gross proceeds of $500 million from the such offering, which it loaned to Viper LLC. Viper LLC paid the expenses of the offering, resulting in net proceeds of the offering of $490 million, which Viper LLC used to pay down borrowings under the Viper credit agreement.


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The Viper Notes were issued under an indenture, dated as of October 16, 2019, among Viper, as issuer, Viper LLC, as guarantor and Wells Fargo, as trustee, which we refer to as the Viper Indenture. Pursuant to the Viper Indenture and the Viper Notes, interest on the Viper Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2020. The Viper Notes will mature on November 1, 2027.

Viper LLC guarantees the Viper Notes pursuant to the Viper Indenture. Neither we nor any of our other subsidiaries guarantee the Viper Notes.

The Viper Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Viper’s ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events.

Rattler’s Credit Agreement

In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, as administrative agent, and a syndicate of banks, as lenders party thereto, which we refer to as the Rattler credit agreement.

The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be prepaid at the maturity date of May 28, 2024. The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC and is secured by substantially all of the assets of Rattler LLC, Rattler, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. As of December 31, 2019, Rattler LLC had $424 million of outstanding borrowings and $176 million available for future borrowings under the Rattler credit agreement.

The outstanding borrowings under the Rattler credit agreement bear interest at a per annum rate elected by Rattler LLC that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum for prime-based loans and 1.250% to 2.250% per annum for LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as defined in the Rattler credit agreement). Rattler LLC is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused portion of the commitment, which fee is also dependent on the Consolidated Total Leverage Ratio.

The Rattler credit agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler, Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowing Rattler LLC or Rattler to issue unsecured debt securities and an exception allowing payment of distributions if no default or events of default exists.


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The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below:
Financial Covenant Required Ratio
Consolidated Total Leverage RatioNot greater than 5.00 to 1.00 (or not greater than 5.50 to 1.00 for 3 fiscal quarters following certain acquisitions), but if the Consolidated Senior Secured Leverage Ratio (as defined in the Rattler credit agreement) is applicable, then not greater than 5.25 to 1.00)
Consolidated Senior Secured Leverage Ratio commencing with the last day of any fiscal quarter in which the Financial Covenant Election (as defined in the Rattler credit agreement) is madeNot greater than 3.50 to 1.00
Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement)Not less than 2.50 to 1.00

For purposes of calculating the financial maintenance covenants prior to the fiscal quarter ending June 30, 2020, EBITDA (as defined in the Rattler credit agreement) will be annualized based on the actual EBITDA for the preceding fiscal quarters starting with the fiscal quarter ending September 30, 2019.

As of December 31, 2019, Rattler and Rattler LLC were in compliance with all financial covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control.

Capital Requirements and Sources of Liquidity

Our board of directors approved a 2020 capital budget for drilling, midstream and infrastructure of $2.8 billion to $3.0 billion, representing an increase of 1% over our 2019 capital budget. We estimate that, of these expenditures, approximately:

$2.45 billion to $2.6 billion will be spent on drilling and completing 320 to 360 gross (288 to 324 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 9,700 feet;

$200 million to $225 million will be spent on midstream infrastructure, excluding joint venture investments; and

$150 million to $175 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

During the year ended December 31, 2019, our aggregate capital expenditures for drilling and infrastructure were $2.7 billion. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. During the year ended December 31, 2019, we spent approximately $443 million in cash on acquisitions of leasehold interests and mineral acres.

In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. We repurchased approximately $598 million of our common stock under this program during the year ended December 31, 2019, with approximately $1.4 billion remaining available for future repurchases under this program. We intend to continue to purchase shares under the repurchase program opportunistically with available funds primarily from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure programs.

The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating 23 drilling rigs including two rigs drilling produced water disposal wells and nine completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.


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Based upon current oil and natural gas prices and production expectations for 2020, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2020. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2020 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

We monitor and adjust our projected capital expenditures in response to the results of our drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. If there is a decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.

Contractual Obligations
The following table summarizes our contractual obligations and commitments as of December 31, 2019:
 Payments Due by Period
 2020 2021-2022 2023-2024 Thereafter Total
 (in millions)
Secured revolving credit facility(1)
$
 $13
 $
 $
 $13
Commitment fees related to the secured revolving credit facility(2)
2
 5
 
 
 7
Senior notes
 420
 1,000
 2,919
 4,339
Interest expense related to the senior notes(3)
168
 311
 294
 301
 1,074
DrillCo Agreement
 
 
 39
 39
Viper's secured revolving credit facility(1)

 97
 
 
 97
Commitment fees under Viper's credit agreement(4)
3
 4
 
 
 7
Viper's senior notes
 
 
 500
 500
Interest expense related to Viper's senior notes27
 54
 54
 76
 211
Rattler's secured revolving credit facility(1)

 
 424
 
 424
Commitment fees under Rattler's credit agreement(5)

 1
 1
 
 2
Asset retirement obligations(6)

 
 
 94
 94
Drilling commitments(7)
15
 
 
 
 15
Sand supply agreements18
 36
 36
 23
 113
Operating lease obligations(8)
11
 14
 7
 5
 37
 $244

$955

$1,816

$3,957
 $6,972
(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)Includes only the minimum amount of commitment fees due which, as of December 31, 2019, includes a commitment fee equal to 0.125% per year of the unused portion of the borrowing base of the Company’s credit agreement.
(3)Interest represents the scheduled cash payments on the senior notes and Energen Notes.
(4)Includes only the minimum amount of commitment fees due which, as of December 31, 2019, includes a commitment fee equal to 0.375% per year of the unused portion of the borrowing base of Viper’s credit agreement.
(5)Includes only the minimum amount of commitment fees due which, as of December 31, 2019, includes a commitment fee equal to 0.250% per year of the unused portion of the borrowing base of Rattler’s credit agreement.
(6)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 8—Asset Retirement Obligations of the Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.

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(7)Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2019.
(8)Operating lease obligations represent future commitments for building, equipment and vehicle leases.

The table above does not include estimated deficiency fees related to certain volume commitments that we have as they are based off future volume deliveries and differences from market pricing which we cannot predict.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2—Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.

Use of Estimates

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.

Method of accounting for oil and natural gas properties

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.


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Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Revenue recognition

Revenue from Contracts with Customers

Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in our contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.

Oil sales

Our oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, we or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in our consolidated statements of operations.

Natural gas and natural gas liquids sales

Under our natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of natural gas liquids and residue gas. In these scenarios, we evaluate whether it is the principal or the agent in the transaction. For those contracts where we have concluded it is the principal and the ultimate third party is its customer, we recognize revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in our consolidated statements of operations.

In certain natural gas processing agreements, we may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in our consolidated statements of operations.


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Midstream Revenue

Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler provides to exploration and production operations. The portion of such fees shown in our consolidated financial statements represent amounts charged to interest owners in our operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of our facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.

Transaction price allocated to remaining performance obligations

Our upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of our product sales contracts.
The majority of our midstream revenue agreements have a term greater than one year, and as such we have utilized the practical expedient in ASC 606, which states that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The remainder of our midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. We have utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.

Contract balances

Under our product sales contracts, we have the right to invoice our customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. We believe that the pricing provisions of our oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.

Impairment

We use the full cost method of accounting for our oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence

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of proved reserves. The inclusion of our unevaluated costs into the amortization base is expected to be completed within three to five years. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

Under this method of accounting, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.

Asset retirement obligations

We measure the future cost to retire our tangible long-lived assets and recognize such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

Our asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

Derivatives

From time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We recognize all of our derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. None of our derivatives were designated as hedging instruments during the years ended December 31, 2019 and 2018. For derivative instruments not designated as hedging instruments, changes in the fair value of these instruments are recognized in earnings during the period of change.

Accounting for Equity-Based Compensation

We grant various types of equity-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 12—Equity-Based Compensation of the Notes to the Consolidated Financial Statements included elsewhere in the Form 10-K. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.

Income Taxes

We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

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Recent Accounting Pronouncements

For information regarding recent accounting pronouncements, See Note 2—Summary of Significant Accounting Policies included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.
Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the years ended December 31, 2019 and 2018. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Off-balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2019. Please read Note 18—Commitments and Contingencies included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.


ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control.

We use price swap derivatives, including basis swaps, double-up swaps, put spreads, interest rate swaps and three-way collars, to reduce price volatility associated with certain of our oil and natural gas sales. With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil - Brent and with natural gas derivative settlements based on NYMEX Henry Hub and Waha Hub pricing.

At December 31, 2019 and December 31, 2018, we had a net asset derivative position of $26 million and $216 million, respectively, related to our price swap, price basis swap derivatives and three-way collars. Utilizing actual derivative contractual volumes under our fixed price swaps and fixed price basis swaps as of December 31, 2019, a 10% increase in forward curves associated with the underlying commodity would have decreased the net asset position to a net liability position of $178 million, a decrease of $204 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset derivative position to $232 million, an increase of $206 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $186 million at December 31, 2019) and receivables from the sale of our oil and natural gas production (approximately $429 million at December 31, 2019).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2019, three purchasers each accounted for more than 10% of our revenue: Shell (27%); Plains (23%); and Vitol (15%). For the year ended December 31, 2018, three purchasers each accounted for more than 10% of our revenue: Shell (26%); Koch (15%); and Occidental Energy Marketing Inc. (11%). For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell (31%); Koch (19%); and Enterprise Crude Oil LLC (11%). No other customer accounted for more than 10% of our revenue during these periods.

80




Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2019, we had 15 customers that represented approximately 80% of our total joint operations receivables. At December 31, 2018, we had four customer that represented approximately 82% of our total joint operations receivables.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.0% per annum and from 1.125% to 2.0% per annum in the case of LIBOR, in each case, depending on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt.

As of December 31, 2019, we had $13 million borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 3.20% on December 31, 2019. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $130,000 based on the $13 million outstanding in the aggregate under our revolving credit facility as of such date.

As of December 31, 2019, Viper LLC had $97 million in outstanding borrowings. Viper LLC’s weighted average interest rate was 4.30%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in Viper LLC’s interest expense of approximately $1 million based on the $97 million outstanding in the aggregate under the Viper credit agreement on December 31, 2019.

As of December 31, 2019, Rattler LLC had $424 million of outstanding borrowings. Rattler LLC’s weighted average interest rate was 2.98%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in Rattler LLC’s interest expense of approximately $4 million based on the $424 million outstanding under the Rattler credit agreement as of December 31, 2019.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
    
The information required by this item appears beginning on page F-1 of this report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

81




ITEM 9A.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of December 31, 2019, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2019, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.


82



MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internal control over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2019.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2019. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2019, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”


83



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Diamondback Energy, Inc.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2019, and our report dated February 26, 2020 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
February 26, 2020

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ITEM 9B.     OTHER INFORMATION

Senior Management Severance Plan

Effective February 20, 2020, we adopted the Diamondback Energy, Inc. Senior Management Severance Plan, or the Severance Plan, and have entered into a participation agreement thereunder with each of our named executive officers. Pursuant to the participation agreements, the benefits under the Severance Plan replace the employment agreements with each of our named executive officers. The Severance Plan also covers other eligible executives who are selected to participate and replaces any employment agreement they may have.

Payments and Benefits Unrelated to a Change in Control. In the event that the employment of a participating executive is terminated by us other than for “cause” (and not by reason of death or disability) or if the participant terminates his or her employment for “good reason” (in each case as defined in the Severance Plan), in addition to any accrued but unpaid base salary or unreimbursed business expenses payable in accordance with the requirements of applicable law, the participant is entitled to receive severance benefits consisting of:

(i)an amount, if any, equal to the bonus that would be payable for services attributable to a completed prior year performance period that has not been paid under the terms of the Diamondback Energy, Inc. 2014 Executive Annual Incentive Compensation Plan;

(ii)a multiple of base salary continuation for a specified number of months (2x for 24 months for the Chief Executive Officer, 1x for 18 months for Executive Vice-Presidents, 1x for 15 months for Senior Vice-Presidents and 1x for 12 months for Vice-Presidents);

(iii)a pro-rated target annual cash bonus for the year of termination (based on the number of days employed during the year of termination);

(iv)up to 18 months of Company-paid COBRA coverage; and

(v)the vesting or forfeiture, as applicable, of each outstanding unvested equity-based compensation award granted by us or our affiliates in accordance with the terms of the applicable equity award agreement. Mr. Stice’s participation agreement includes terms that are intended to maintain certain benefits under his prior employment agreement and are consistent with prior public disclosure that require each equity award granted to Mr. Stice to become 100% vested upon an eligible termination, and in the case of outstanding performance based equity awards to vest at the maximum level under the equity award agreement, and be settled within ten business days.

Severance Benefits Related to a Change in Control). In the event that employment of a participant is terminated by us other than for “cause” (and not by reason of death or disability) or if the participant terminates his or her employment for “good reason,” in either case within the two year period immediately following a change in control (as defined in the Severance Plan), the participant will be entitled to the benefits described above, except that the salary continuation described in clause (ii) will be replaced by a lump sum cash payment equal to a multiple of the participant’s base salary plus such participant’s average bonus for the preceding three years (3.0x for the Chief Executive Officer, 2.5x for Executive Vice-Presidents, 2.25x for Senior Vice-Presidents and 2.0x for Vice-Presidents).

Severance Benefits Related to Death or Disability. The Severance Plan also provides the same benefits described in clauses (i), (ii) and (iii) (but not clause (iv)) in the event that a participant dies or becomes disabled (as defined in the Severance Agreement) while employed by us. Mr. Stice’s participation agreement includes terms that are intended to maintain certain benefits under his prior employment agreement and are consistent with prior public disclosure that require the Company to pay 100 percent of the premiums to continue his, his spouse’s and any of his eligible dependents’ group health plan continuation coverage under COBRA.

Release and Restrictive Covenants. The payment of any benefits under the Severance Plan is conditioned on the participant’s (or if applicable, the participant’s personal representative’s or estate’s) execution of a general release of claims. The Severance Plan also includes certain restrictive covenants that continue beyond the employment period, including non-competition and non-solicitation obligations for a period of one year following termination of employment. If a participating executive terminates employment on a basis that is not eligible for severance benefits, we can elect to apply the restrictive covenants for up to 12 months and receive a release by payment of an amount equal to one-twelfth of the participant’s annualized base salary plus target annual bonus for each month the restrictive covenants will apply.


85


We believe that these severance benefits provide the same type of income transition protections that were provided to our executives under their prior employment agreements. These arrangements are intended to attract and retain qualified executives that could have job alternatives that may appear to them to be less risky absent these arrangements. We believe that the enhanced severance benefits resulting from terminations related to a change in control transaction are in the interest of our stockholders because they provide an incentive for executives to continue to help successfully execute such a transaction from its early stages through consummation. We also believe that these benefits provide important protection to our named executive officers, are consistent with the prior employment protections and the practices of peer group companies and are appropriate for the attraction and retention of executive talent.

Appointment of Executive Vice President-Operations

On February 20, 2020, our board of directors promoted Daniel N. Wesson to serve as our Executive Vice President-Operations, effective March 1, 2020. Until the effective date of this promotion, Mr. Wesson will continue to serve as our Senior Vice President of Operations, a position he has held since February 2019. Mr. Wesson served as our Vice President of Operations from April 2017 to February 2019 and as our Completions Manager from January 2013 to April 2017. He joined us as an Operations Engineer in February 2012. Before joining our company, Mr. Wesson served in various operations and engineering roles for BOPCO L.P. from 2010 to 2012 and ConocoPhillips from 2007 to 2010. Mr. Wesson received his Bachelor of Science degree in Mechanical Engineering from Louisiana State University and is a member of the Permian Basin Society of Petroleum Engineers.

In his role as our Executive Vice President-Operations, Mr. Wesson is entitled to receive an annual base salary and participate in (i) our annual executive cash incentive program, which provides an opportunity to receive an annual bonus, based on a target percentage of the annual base salary and pre-established performance goals, (ii) our equity incentive plan, under which we grant annual performance-based and time-vesting equity awards, (iii) the Severance Plan described above and (iv) any other employee benefit plans generally available to similarly situated employees of our company, as in effect from time to time.


PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2019.

We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accounting officer and controller and persons performing similar functions. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. The Company also has made the Code of Business Conduct and Ethics available on our website under the “Corporate Governance” section at http://ir.diamondbackenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.

ITEM 11.     EXECUTIVE COMPENSATION

Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2019.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2019.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2019.


86



ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2019.


ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)Documents included in this report:
 1. Financial Statements 
 
 
 
 
 
 
   
 2. Financial Statement Schedules
 Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s consolidated financial statements and related notes. 
3. Exhibits
Exhibit Number Description
2.1# 
3.1 
3.2 
3.3 
3.4 
4.1* 
4.2 
4.3 
4.4 
4.5 



3. Exhibits
Exhibit Number Description
4.6 
4.7 
4.8 
4.9 
4.10 
4.11 
4.12 
4.13 
4.14 
10.1 
10.2+* 
10.3+* 
10.4+ 
10.5+* 
10.6+ 
10.7+ 
10.8+ 
10.9+ 
10.10 

88


3. Exhibits
Exhibit Number Description
10.11 
10.12 
10.13 
10.14 
10.15 
10.16 
10.17 
10.18 
10.19 
10.20 
10.21 

89


3. Exhibits
Exhibit Number Description
10.22 
10.23 
10.24 
10.25 
10.26 
10.27+ 
10.28+ 
10.29+ 
10.30+ 
10.31+ 
10.32+ 
21.1* 
23.1* 
23.2* 
23.3* 
31.1* 
31.2* 
32.1** 
32.2** 
99.1* 

90


3. Exhibits
Exhibit Number Description
99.2* 
101 The following financial information from the Company’s Annual Report on Form 10-K for the year ended December 31, 2019, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Changes in Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to Consolidated Financial Statements.
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
_______________
*Filed herewith.
**The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
+Management contract, compensatory plan or arrangement.
#The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.

ITEM 16. FORM 10-K SUMMARY
None.


91


SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

   DIAMONDBACK ENERGY, INC.
   
Date:February 26, 2020  
   /s/ Travis D. Stice
   Travis D. Stice
   Chief Executive Officer
   (Principal Executive Officer)

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature Title Date
    
/s/ Steven E. West Chairman of the Board and Director February 26, 2020
Steven E. West    
     
/s/ Travis D. Stice Chief Executive Officer and Director February 26, 2020
Travis D. Stice (Principal Executive Officer)  
     
/s/ Michael P. Cross Director February 26, 2020
Michael P. Cross    
     
/s/ David L. Houston Director February 26, 2020
David L. Houston    
     
/s/ Mark L. Plaumann Director February 26, 2020
Mark L. Plaumann    
     
/s/ Melanie M. Trent Director February 26, 2020
Melanie M. Trent    
     
/s/ Kaes Van’t Hof Chief Financial Officer and Executive Vice President—Business Development February 26, 2020
Kaes Van’t Hof (Principal Financial Officer)  
     
/s/ Teresa L. Dick Chief Accounting Officer, Executive Vice President and Assistant Secretary February 26, 2020
Teresa L. Dick (Principal Accounting Officer)  


S-1



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Diamondback Energy, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (collectively the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2020 expressed an unqualified opinion.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Depletion expense, impairment evaluation and acquisition of oil and gas properties

As described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues to record depletion expense and measure its oil and gas properties for potential impairment. Additionally, as described in Note 3 to the financial statements, the Company acquired significant oil and gas properties throughout the year. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties, forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties, and for acquisitions that included proved developed producing properties using an estimated fair value pricing model for the valuation of proved producing reserves. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense, impairment evaluation and acquisition valuation of oil and gas properties, as a critical audit matter.

F-1



The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or impairment expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others.

We tested the design and operating effectiveness of key controls relating to the preparation of the ceiling test calculation, management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment, and management’s estimation of the fair value of acquired oil and gas properties. Specifically, these controls related to the use of historical information in the estimation of proved reserves derived from the Company’s accounting records and the management review controls on information provided to the reservoir engineering specialists and the management review controls on the final proved reserve report prepared by the Company’s specialists.

We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.

For acquisitions of oil and gas properties during the year in which proved developed producing properties are significant and to the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, working and net revenue interests and future capital expenditures and operating costs, we tested management’s process for determining the assumptions, including examining the underlying support. Specifically, our audit procedures involved testing management’s assumptions as follows:
Analyzed the appropriateness of fair value pricing used in the acquisition reserve report to published product pricing on the acquisition closing date;
Analyzed the appropriateness of the future operating cost and capital expenditure assumptions used in the acquisition reserve report to historical operating costs and capital expenditures of similarly located properties
Evaluated the working and net revenue interests used in the acquisition reserve report by inspecting a sample of land and division order records;
Analyzed, on a sample basis, the appropriateness of management’s estimated future production volumes and the production decline curves; and
Utilized valuation specialists to compare the acreage value allocated, on a per acre basis, to undeveloped properties and to other recent acquisitions in the same or similar locations.

To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows:
Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;
Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations;
Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of land and division order records;
Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the operator’s intent to develop the proved undeveloped properties;
Evaluated the estimated ultimate recovery of proved undeveloped properties to the estimated ultimate recovery of comparable proved developed producing properties; and
Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.




F-2



/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2009.

Oklahoma City, Oklahoma
February 26, 2020


F-3


Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets



                                                                                                           
 December 31,
 2019 2018
 (In millions, except share amounts)
Assets   
Current assets:   
Cash and cash equivalents$123
 $215
Restricted cash5
 
Accounts receivable:   
Joint interest and other, net186
 96
Oil and natural gas sales429
 296
Inventories37
 37
Derivative instruments46
 231
Prepaid expenses and other43
 50
Total current assets869
 925
Property and equipment:   
Oil and natural gas properties, full cost method of accounting ($9,207 million and $9,670 million excluded from amortization at December 31, 2019 and 2018, respectively)25,782
 22,299
Midstream assets931
 700
Other property, equipment and land125
 147
Accumulated depletion, depreciation, amortization and impairment(5,003) (2,774)
Net property and equipment21,835
 20,372
Equity method investments479
 1
Derivative instruments7
 
Deferred tax asset142
 97
Investment in real estate, net109
 116
Other assets90
 85
Total assets$23,531
 $21,596
Liabilities and Stockholders’ Equity   
Current liabilities:   
Accounts payable-trade$179
 $128
Accrued capital expenditures475
 495
Other accrued liabilities304
 253
Revenues and royalties payable278
 143
Derivative instruments27
 
Total current liabilities1,263
 1,019
Long-term debt5,371
 4,464
Derivative instruments
 15
Asset retirement obligations94
 136
Deferred income taxes1,886
 1,785
Other long-term liabilities11
 10
Total liabilities$8,625
 $7,429
    
    
    
    
    
    
    
    
    
    

F-4

Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets - Continued


 December 31,
 2019 2018
 (In millions, except share amounts)
Commitments and contingencies (Note 18)


 


Stockholders’ equity:   
Common stock, $0.01 par value, 200,000,000 shares authorized, 159,002,338 issued and outstanding at December 31, 2019; 200,000,000 shares authorized, 164,273,447 issued and outstanding at December 31, 2018$2
 $2
Additional paid-in capital12,357
 12,936
Retained earnings890
 762
Total Diamondback Energy, Inc. stockholders’ equity13,249
 13,700
Non-controlling interest1,657

467
Total equity14,906
 14,167
Total liabilities and equity$23,531
 $21,596









































See accompanying notes to consolidated financial statements.

F-5

Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Operations



 Year Ended December 31,
 2019 2018 2017
 (In millions, except per share amounts, shares in thousands)
Revenues:     
Oil sales$3,554
 $1,879
 $1,044
Natural gas sales66
 61
 52
Natural gas liquid sales267
 190
 90
Lease bonus4
 3
 12
Midstream services64
 34
 7
Other operating income9
 9
 
Total revenues3,964
 2,176
 1,205
Costs and expenses:     
Lease operating expenses490
 205
 127
Production and ad valorem taxes248
 133
 74
Gathering and transportation88
 26
 13
Midstream services91
 72
 10
Depreciation, depletion and amortization1,447
 623
 327
Impairment of oil and natural gas properties790
 
 
General and administrative expenses104
 65
 48
Asset retirement obligation accretion7
 2
 1
Merger and integration expense
 36
 
Other operating expense4
 3
 
Total costs and expenses3,269
 1,165
 600
Income from operations695
 1,011
 605
Other income (expense):     
Interest expense, net(172) (87) (41)
Other (expense) income, net(2) 89
 11
(Loss) gain on derivative instruments, net(108) 101
 (78)
Gain (loss) on revaluation of investment5
 (1) 
Loss on extinguishment of debt(56) 
 
Total other income (expense), net(333) 102
 (108)
Income before income taxes362
 1,113
 497
Provision for (benefit from) income taxes47
 168
 (20)
Net income315
 945
 517
Net income attributable to non-controlling interest75
 99
 35
Net income attributable to Diamondback Energy, Inc.$240
 $846
 $482
      
Earnings per common share:     
Basic$1.47
 $8.09
 $4.95
Diluted$1.47
 $8.06
 $4.94
Weighted average common shares outstanding:     
Basic163,493
 104,622
 97,458
Diluted163,843
 104,929
 97,688
Dividends declared per share$0.9375
 $0.5000
 $




See accompanying notes to consolidated financial statements.

F-6

Diamondback Energy, Inc. and Subsidiaries
Consolidated Statement of Stockholders’ Equity


 Common Stock Additional Paid-in Capital Retained Earnings (Accumulated Deficit) Non-Controlling Interest  
 SharesAmount    Total
           
 ($ in millions, shares in thousands)
Balance December 31, 201690,144
$1
 $4,216
 $(520) $321
 $4,018
Net proceeds from issuance of common units - Viper Energy Partners LP       370
 370
Unit-based compensation       2
 2
Common units issued for acquisition       3
 3
Stock-based compensation   32
     32
Distribution to non-controlling interest       (41) (41)
Common shares issued for Brigham7,686
  809
     809
Exercise of stock options and vesting of restricted stock units337
        
Change in ownership of consolidated subsidiaries, net   234
   (363) (129)
Net income     482
 35
 517
Balance at December 31, 201798,167
1
 5,291
 (38) 327
 5,581
Impact of adoption of ASU 2016-01, net of tax     (9) (7) (16)
Net proceeds from issuance of common units - Viper Energy Partners LP       303
 303
Unit-based compensation       3
 3
Stock-based compensation   34
     34
Common shares issued for business combination63,126
1
 7,069
     7,070
Stock options assumed in business combination   14
     14
Restricted stock units assumed in business combination   52
     52
Repurchased shares for tax withholding(140)  (14)     (14)
Distribution to non-controlling interest       (98) (98)
Common shares issued for Ajax2,584
  340
     340
Dividend paid     (37)   (37)
Exercise of stock options and vesting of restricted stock units536
        
Change in ownership of consolidated subsidiaries, net   150
   (160) (10)
Net income     846
 99
 945
Balance December 31, 2018164,273
2
 12,936
 762
 467
 14,167
Net proceeds from issuance of common units - Viper Energy Partners LP       341
 341
Net proceeds from issuance of common units - Rattler Midstream LP       720
 720
Unit-based compensation       7
 7
Common units issued for acquisition 
 
   124
 124
Stock-based compensation   57
     57
Repurchased shares for tax withholding(125)

 (13) 

 

 (13)
Repurchased shares for share buyback program(6,385)  $(598)     $(598)
Distribution to non-controlling interest       $(122) $(122)

F-7

Diamondback Energy, Inc. and Subsidiaries
Consolidated Statement of Stockholders’ Equity - Continued


 Common Stock Additional Paid-in Capital Retained Earnings (Accumulated Deficit) Non-Controlling Interest  
 SharesAmount    Total
           
 ($ in millions, shares in thousands)
Dividend paid     (112)   (112)
Exercise of stock and unit options and awards of restricted stock1,239
  8
     8
Change in ownership of consolidated subsidiaries, net   (33)   45
 12
Net income     240
 75
 315
Balance December 31, 2019159,002
$2
 $12,357
 $890
 $1,657
 $14,906








































See accompanying notes to consolidated financial statements.

F-8

Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows


 Year Ended December 31,
 2019 2018 2017
 (In millions)
Cash flows from operating activities:     
Net income$315
 $945
 $517
Adjustments to reconcile net income to net cash provided by operating activities:     
Provision for (benefit from) deferred income taxes47
 168
 (20)
Impairment of oil and natural gas properties790
 
 
Asset retirement obligation accretion7
 2
 1
Depreciation, depletion and amortization1,447
 623
 327
Amortization of debt issuance costs9
 12
 4
Loss on early extinguishment of debt56
 
 
Change in fair value of derivative instruments188
 (222) 84
Loss (income) from equity investment6
 
 (1)
(Gain) loss on revaluation of investment(5) 1
 
Equity-based compensation expense48
 27
 26
(Gain) loss on sale of assets, net(1) 3
 (1)
Gain on sale of inventory(1) 
 
Restricted cash(5) 
 
Changes in operating assets and liabilities:     
Accounts receivable(187) 13
 (97)
Inventories(10) (14) (2)
Prepaid expenses and other29
 25
 (11)
Accounts payable and accrued liabilities(129) (7) 37
Income tax payable
 (1) 1
Accrued interest(5) (22) (21)
Revenues and royalties payable135
 12
 45
Net cash provided by operating activities2,734
 1,565
 889
Cash flows from investing activities:     
Drilling, completions and non-operated additions to oil and natural gas properties(2,557) (1,359) (737)
Infrastructure additions to oil and natural gas properties(120) (102) (56)
Additions to midstream assets(244) (204) (68)
Purchase of other property, equipment and land(5) (7) (23)
Acquisition of leasehold interests(443) (1,371) (1,961)
Acquisition of mineral interests(333) (440) (407)
Acquisition of midstream assets
 
 (50)
Proceeds from sale of assets300
 80
 66
Investment in real estate(1) (111) 
Funds held in escrow
 11
 104
Equity investments(485) 
 
Net cash used in investing activities(3,888) (3,503) (3,132)
Cash flows from financing activities:     
Proceeds from borrowings under credit facility2,350
 2,652
 754
Repayment under credit facility(3,718) (1,242) (384)
Repayment on Energen's credit facility
 (559) 
Proceeds from senior notes3,469
 1,062
 
Repayment of senior notes(1,250) 
 
Proceeds from joint venture$39
 $
 $

F-9

Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows - Continued


 Year Ended December 31,
 2019 2018 2017
 (In millions)
Premium on extinguishment of debt$(44) $
 $
Debt issuance costs(18) (25) (9)
Public offering costs(41) (3) (1)
Proceeds from public offerings1,106
 305
 370
Proceeds from exercise of stock options9
 
 
Repurchased shares for tax withholdings(13) (14) 
Repurchased as part of share buyback(593) 
 
Dividends to stockholders(112) (37) 
Distributions to non-controlling interest(122) (98) (41)
Net cash provided by financing activities1,062
 2,041
 689
Net (decrease) increase in cash and cash equivalents(92) 103
 (1,554)
Cash and cash equivalents at beginning of period215
 112
 1,666
Cash and cash equivalents at end of period$123
 $215
 $112
      
Supplemental disclosure of cash flow information:     
Interest paid, net of capitalized interest$237
 $114
 $58
Cash paid for income taxes$
 $1
 $
Supplemental disclosure of non-cash transactions:     
Change in accrued capital expenditures$(20) $274
 $161
Capitalized stock-based compensation$17
 $10
 $9
Common stock issued for Ajax$
 $340
 $
Common stock issued for Brigham$
 $
 $809
Common stock issued for business combination(1)
$
 $7,136
 $
Asset retirement obligations acquired$4
 $111
 $2
(1)Includes $7 billion of Common stock issued for business combination, $14 million for stock options assumed and $52 million for restricted stock units assumed.























See accompanying notes to consolidated financial statements.

F-10

Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



1.    DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Organization and Description of the Business

Diamondback Energy, Inc. (“Diamondback” or the “Company”) is an independent oil and gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011.

The wholly-owned subsidiaries of Diamondback, as of December 31, 2019, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company (“Viper’s General Partner”), Rattler Midstream GP LLC, a Delaware limited liability company (Rattler’s General Partner), and Energen Corporation, an Alabama corporation (“Energen”). The consolidated subsidiaries include these wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (“Viper”), Viper’s subsidiary Viper Energy Partners LLC, a Delaware limited liability company (“Viper LLC”), Rattler Midstream LP (formerly known as Rattler Midstream Partners LP), a Delaware limited partnership (“Rattler”), Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC), a Delaware limited liability company (“Rattler LLC”), Rattler LLC’s wholly-owned subsidiary Tall City Towers LLC, a Delaware limited liability company (“Tall City”), and Energen’s wholly-owned subsidiaries Energen Resources Corporation, an Alabama corporation (“Energen Resources”), and EGN Services, Inc., an Alabama corporation.

Basis of Presentation

The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.

Viper is consolidated in the financial statements of the Company. As of December 31, 2019, the Company owned approximately 58% of the total units outstanding of Viper and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is Viper’s General Partner.

Rattler is consolidated in the financial statements of the Company. As of December 31, 2019, the Company owned approximately 71% of the total units outstanding of Rattler. The Company’s wholly-owned subsidiary, Rattler Midstream GP LLC, is Rattler’s General Partner.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.

F-11


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

Restricted Cash

As of December 31, 2019, the Company had restricted cash of $5 million related to the Company’s obligations under its participation and development agreement with Obsidian Resources, L.L.C.

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date.

Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. At December 31, 2019 and 2018, the Company recorded an allowance for doubtful accounts of $2 million related to joint interest receivables.

Derivative Instruments

The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives and senior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 16—Fair Value Measurements).


F-12


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Prepaid Expenses and Other

Prepaid expenses and other consist of the following:
 Year Ended December 31,
 2019 2018
 (In millions)
Prepaid insurance$6
 $4
Prepaid fees and licenses4
 3
Income tax receivable19
 38
Other14
 5
Total prepaid expenses and other$43
 $50


Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 9–Equity Method Investments). Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $13.54, $12.62 and $11.11 for the years ended December 31, 2019, 2018 and 2017, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $1.4 billion, $595 million and $321 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. An impairment on proved oil and natural gas properties of $790 million was recorded for the year ended December 31, 2019. NaN impairments on proved oil and natural gas properties were recorded for the years ended December 31, 2018 and 2017.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.


F-13


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Real Estate Assets

Real estate assets are stated at cost, less accumulated depreciation and amortization. The Company considers the period of future benefit of each respective asset to determine the appropriate useful life and depreciation and amortization is calculated using the straight-line method over the assigned useful life.

Upon acquisition of real estate properties, the purchase price is allocated to tangible assets, consisting of land and building, and to identified intangible assets and liabilities, which may include the value of above market and below market leases and the value of in-place leases. The allocation of the purchase price is based upon the fair value of each component of the property. Although independent appraisals may be used to assist in the determination of fair value, in many cases these values will be based upon management’s assessment of each property, the selling prices of comparable properties and the discounted value of cash flows from the asset.

The fair values of above market and below market in-place leases will be recorded based on the present value (using an interest rate which reflects the risks associated with the leases acquired) of the difference between (i) the contractual amounts to be paid pursuant to the in-place leases and (ii) an estimate of fair market lease rates for the corresponding in-place leases measured over a period equal to the non-cancelable term of the lease including any bargain renewal periods. The above market and below market lease values will be capitalized as intangible lease assets or liabilities. Above market lease values will be amortized as an adjustment of rental income over the remaining term of the respective leases. Below market lease values will be amortized as an adjustment of rental income over the remaining term of the respective leases, including any bargain renewal periods. If a lease were to be terminated prior to its stated expiration, all unamortized amounts of above market and below market in-place lease values relating to that lease would be recorded as an adjustment to rental income.

The fair values of in-place leases will include estimated direct costs associated with obtaining a new tenant, and opportunity costs associated with lost rentals which are avoided by acquiring an in-place lease. Direct costs associated with obtaining a new tenant may include commissions, tenant improvements, and other direct costs and are estimated, in part, by management’s consideration of current market costs to execute a similar lease.

These direct costs will be included in intangible lease assets on the balance sheet and will be amortized to expense over the remaining term of the respective leases. The value of opportunity costs will be calculated using the contractual amounts to be paid pursuant to the in-place leases over a market absorption period for a similar lease. These intangibles will be included in intangible lease assets on the balance sheet and will be amortized to expense over the remaining term of the respective leases. If a lease were to be terminated prior to its stated expiration, all unamortized amounts of in-place lease assets relating to that lease would be expensed.

Other Property, Equipment and Land

Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to 15 years. Depreciation expense for other property and equipment was $16 million, $9 million and $1 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties.

F-14


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Impairment of Long-Lived Assets

Other property and equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the years ended December 31, 2019, 2018 and 2017, respectively.

Capitalized Interest

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these unevaluated properties to their intended use. Capitalized interest cannot exceed gross interest expense. The Company capitalized interest of $66 million, $32 million and $22 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Inventories

Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2019 and 2018. The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2019, the Company estimated that all of its tubular goods and equipment will be utilized within one year.

Debt Issuance Costs

Other assets included capitalized costs related to the credit facility of $36 million and $28 million, net of accumulated amortization of $15 million and $9 million, as of December 31, 2019 and 2018, respectively. Long-term debt included capitalized costs related to the senior notes of $24 million and $32 million, net of accumulated amortization of $14 million and $15 million, as of December 31, 2019 and 2018, respectively. The costs associated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior notes using the effective interest method. The costs associated with the Company’s credit facility that are included in other assets are being amortized over the term of the facility.

Other Accrued Liabilities

Other accrued liabilities consist of the following:
 December 31,
 2019 2018
 (In millions)
Liability for drilling costs prepaid by joint interest partners$12
 $16
Interest payable27
 26
Lease operating expenses payable119
 59
Ad valorem taxes payable68
 49
Other78
 103
Total other accrued liabilities$304
 $253



F-15


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Revenue and Royalties Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.

Revenue Recognition

Revenue from Contracts with Customers

Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.

Oil sales

The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations.

Natural gas and natural gas liquids sales

Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations.

Midstream Revenue

Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes

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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.

Transaction price allocated to remaining performance obligations

The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of our product sales contracts.
The majority of the Company’s midstream revenue agreements have a term greater than one year, and as such the Company has utilized the practical expedient in ASC 606, which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The remainder of the Company’s midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. The Company has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.

Contract balances

Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.

Investments

Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2019, 2018 and 2017.

For additional information on the Company’s investments, see Note 9—Equity Method Investments.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Accounting for Equity-Based Compensation

The Company has granted various types of stock-based awards including stock options and restricted stock units. Viper has granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner and the Company who perform services for Viper. Rattler has granted unit-based awards consisting of phantom units to employees, officers and directors of Rattler’s General Partner and the Company who perform services for Rattler. These plans and related accounting policies are defined and described more fully in Note 12—Equity-Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2019, three purchasers each accounted for more than 10% of our revenue: Shell (27%); Plains (23%); and Vitol (15%). For the year ended December 31, 2018, three purchasers each accounted for more than 10% of the Company’s revenue: Shell (26%); Koch (15%); and Occidental Energy Marketing Inc. (11%). For the year ended December 31, 2017, three purchasers each accounted for more than 10% of the Company’s revenue: Shell (31%); Koch (19%); and Enterprise Crude Oil LLC (11%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

Diamondback uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Company is subject to margin tax in the state of Texas. During the years ended December 31, 2019, 2018 and 2017, the Company had no margin tax expense. The Company’s 2015, 2016, 2017, 2018 and 2019 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2019 and 2018, we had $2 million unrecognized tax benefits. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2019, 2018 and 2017, there was no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Recent Accounting Pronouncements

The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements:
StandardDescriptionDate of AdoptionEffect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses”This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.Q1 2020
The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.

ASU 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels.Q1 2020The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement.Q1 2020The Company adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)”This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis.Q1 2020The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have any cost method investments.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.Q1 2021This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity.


3.    ACQUISITIONS AND DIVESTITURES
2019 Activity

Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen

On May 23, 2019, the Company completed its divestiture of 6,589 net acres of certain non-core Permian assets, which were acquired by the Company in its merger with Energen (as described below), for an aggregate sale price of $37 million. This divestiture did 0t result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


On July 1, 2019, the Company completed its divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in the merger with Energen (as described below), for an aggregate sale price of $285 million. This divestiture did 0t result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.

2019 Drop-Down Transaction
On July 29, 2019, the Company entered into a definitive purchase agreement to divest certain mineral and royalty interests to Viper for approximately 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits (the “Drop-Down”). The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by the Company, and have an average net royalty interest of approximately 3.2% (the “Drop-Down Assets”). The Drop-Down closed on October 1, 2019 and was effective as of July 1, 2019. Viper funded the cash portion of the purchase price of the Drop-Down Assets through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility.
2018 Activity

Tall City Towers LLC

On January 31, 2018, Tall City Towers LLC, a subsidiary of the Company, completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located for a net purchase price of $110 million.

Ajax Resources, LLC

On October 31, 2018, the Company completed its acquisition of leasehold interests and related assets of Ajax Resources, LLC, which included approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900 million in cash and approximately 2.6 million shares of the Company’s common stock (the “Ajax acquisition”). This transaction was effective as of July 1, 2018. The cash portion of this transaction was funded through a combination of cash on hand, proceeds from the sale of mineral interests to Viper (described below under the caption “2018 Drop-Down Transaction”), borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 10—Debt for information relating to this offering.

2018 Drop-down Transaction

On August 15, 2018, the Company completed a transaction to sell to Viper mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by the Company, for $175 million.
ExL Petroleum Management, LLC and EnergyQuest II LLC

On October 31, 2018, the Company completed its acquisitions of leasehold interests and related assets, one with ExL Petroleum Management, LLC and ExL Petroleum Operating, Inc. and one with EnergyQuest II LLC, for an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $313 million in cash. These transactions were effective as of August 1, 2018 and were funded through a combination of cash on hand, proceeds from the sale of assets to Viper (described immediately above) and borrowing under the Company’s revolving credit facility.

Energen Corporation Merger

On November 29, 2018, the Company completed its acquisition of Energen in an all-stock transaction (the “ Merger”), which was accounted for as a business combination. Upon completion of the Merger, the addition of Energen’s assets increased the Company’s assets to: (i) over 273,000 net Tier One acres in the Permian Basin, (ii) approximately 7,200 estimated total net horizontal Permian locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins. Under the terms of the Merger, each share of Energen common stock was converted into 0.6442 of a share of the Company’s common stock. The Company issued approximately 62.8 million shares of its common stock valued at a price of $112.00 per share on

F-20


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


the closing date, resulting in total consideration paid by the Company to the former Energen shareholders of approximately $7.1 billion.

In connection with the closing of the Merger, the Company repaid outstanding principal under Energen’s revolving credit facility and assumed all of Energen’s long-term debt. See Note 10—Debt for additional information.

Purchase Price Allocation

The Merger has been accounted for as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of Energen to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date resulting in no goodwill or bargain purchase gain.

The following table sets forth the Company’s purchase price allocation:
 (In millions)
Consideration: 
Fair value of the Company's common stock issued$7,136
Total consideration$7,136
  
Fair value of liabilities assumed: 
Current liabilities$388
Asset retirement obligation105
Long-term debt1,099
Noncurrent derivative instruments17
Deferred income taxes1,425
Other long-term liabilities7
Amount attributable to liabilities assumed$3,041
  
Fair value of assets acquired: 
Total current assets$298
Oil and natural gas properties9,361
Midstream assets253
Investment in real estate11
Other property, equipment and land58
Asset retirement obligation105
Other postretirement assets3
Noncurrent income tax receivable, net76
Other long term assets12
Amount attributable to assets acquired$10,177


The Company has included in its consolidated statements of operations revenues of $102 million and direct operating expenses of $17 million for the period from December 1, 2018 to December 31, 2018 due to the acquisition.

Pro Forma Financial Information

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the years ended December 31, 2018 and 2017 have been prepared to give effect to the Merger as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Energen’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Energen’s outstanding

F-21


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Energen’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $37 million for the year ended December 31, 2018 and acquisition-related costs incurred by Energen of $59 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Energen assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.

The pro forma consolidated statement of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2017 and is not intended to be a projection of future results.
 Year Ended December 31,
 2018 2017
 (in millions, except per share amounts)
Revenues$3,532
 $2,196
Income from operations1,559
 900
Net income1,320
 875
Basic earnings per common share$7.54
 $5.26
Diluted earnings per common share$7.53
 $5.24


2017 Activity

On February 28, 2017, the Company completed its acquisition of certain oil and natural gas properties, midstream assets and other related assets in the Delaware Basin for an aggregate purchase price consisting of $1.7 billion in cash and 7.69 million shares of the Company’s common stock, of which approximately 1.15 million shares were placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $48 million. The Company used the net proceeds from its December 2016 equity offering, net proceeds from its December 2016 debt offering, cash on hand and other financing sources to fund the cash portion of the purchase price for this acquisition.

The following represents the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5 billion, resulting in no goodwill or bargain purchase gain.
 (in millions)
Proved oil and natural gas properties$386
Unevaluated oil and natural gas properties2,123
Midstream assets47
Prepaid capital costs4
Oil inventory1
Revenues and royalties payable(10)
Asset retirement obligations(2)
Total fair value of net assets$2,549


The Company has included in its consolidated statements of operations revenues of $81 million and direct operating expenses of $24 million for the period from February 28, 2017 to December 31, 2017 due to the acquisition.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Pro Forma Financial Information

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the years ended December 31, 2017 and 2016 have been prepared to give effect to the February 28, 2017 acquisition as if it had occurred on January 1, 2016. The pro forma data are not necessarily indicative of the financial results that would have been attained had the acquisitions occurred on January 1, 2016.

The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.
 Year Ended December 31,
 2017 2016
 (in millions, except per share amounts)
Revenues$1,228
 $627
Income (loss) from operations619
 (13)
Net income (loss)473
 (109)
Basic earnings per common share$4.85
 $(1.45)
Diluted earnings per common share$4.84
 $(1.45)


4.    VIPER ENERGY PARTNERS LP

Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. Viper is currently focused on oil and natural gas properties in the Permian Basin. Viper Energy Partners GP LLC, a consolidated subsidiary of Diamondback, serves as the general partner of, and holds a general partner interest in, Viper. As of December 31, 2019, the Company owned approximately 58% of Viper’s total units outstanding.

During the year ended December 31, 2019, Diamondback received distributions of $133 million in respect of its interests in Viper and Viper LLC.

Viper completed the following equity offerings during the years ended December 31, 2019, 2018 and 2017:
DateNumber of Units of Common Units SoldNumber of Units of Common Units Issued to UnderwritersProceeds Received by ViperAmount Repaid on Viper LLC’s Credit Facility
   (in millions) 
January 20179,775,000
1,275,000
$148
$121
July 2017(1)
16,100,000
2,100,000
$232
$153
July 201810,080,000
1,080,000
$303
$362
March 201910,925,000
1,425,000
$341
$314
(1)In this offering, Diamondback purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of the Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters.

As a result of Viper’s public offerings, Viper’s issuance of units for acquisitions and Viper’s issuance of unit-based compensation, the Company’s ownership percentage in Viper was reduced. During the year ended December 31, 2019, the Company recorded a $45 million decrease to non-controlling interest in Viper with an increase to additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value in Viper before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Recapitalization, Tax Status Election and Related Transactions by Viper

In March 2018, Viper announced that the Board of Directors of the General Partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 Viper (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of the Operating Company, (iii) amended and restated its existing registration rights agreement with the Company and (iv) entered into an exchange agreement with the Company, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, the Company delivered and assigned to Viper the 73,150,000 common units the Company owned in exchange for (i) 73,150,000 of Viper’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, Viper continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and the Company owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of Viper’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and the Company owned the remaining approximately 59%. The Operating Company units and Viper’s Class B units owned by the Company are exchangeable from time to time for Viper’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

On May 10, 2018, the change in Viper’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1 million to Viper in respect of its general partner interest and (ii) the Company made a cash capital contribution of $1 million to Viper in respect of the Class B units. The Company, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, the Company also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of Viper and a cash amount of $10,000 representing a proportionate return of the $1 million invested capital in respect of the Class B units. The General Partner continues to serve as Viper’s general partner and the Company continues to control Viper. After the effectiveness of the tax status election and the completion of related transactions, Viper’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to Viper’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to Viper’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and Viper’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

Partnership Agreement

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Viper Partnership Agreement”), requires Viper to reimburse Viper’s General Partner for all direct and indirect expenses incurred or paid on Viper’s behalf and all other expenses allocable to Viper or otherwise incurred by Viper’s General Partner in connection with operating Viper’s business. The Viper Partnership Agreement does not set a limit on the amount of expenses for which Viper’s General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for Viper or on its behalf and expenses allocated to Viper’s General Partner by its affiliates. Viper’s General Partner is entitled to determine the expenses that are allocable to Viper. For each of the year ended December 31, 2019 and 2018, Viper’s General Partner allocated $3 million and $2 million, respectively, to Viper.

Tax Sharing

In connection with the closing of the Viper Offering, Viper entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which Viper agreed to reimburse Diamondback for its share of state and local income and other taxes for which Viper’s results are included in a consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax Viper would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its consolidated group, of which Viper may be a member for this purpose, to owe less or no tax. In such a situation, Viper agreed to reimburse Diamondback for the tax Viper would have owed had the tax attributes not been available or used for Viper’s benefit, even

F-24


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


though Diamondback had no cash tax expense for that period. For the year ended December 31, 2019, Viper did 0t accrue any state income tax expense. For the year ended December 31, 2018, Viper accrued a minimal amount for its share of Texas margin tax for which Viper’s results are included in a combined tax return filed by Diamondback.

Viper LLC’s Revolving Credit Facility

Viper has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 10—Debt for a description of this credit facility.

5.    RATTLER MIDSTREAM LP

Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR”. Rattler was formed by Diamondback in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler’s General Partner, a wholly-owned subsidiary of Diamondback, serves as the general partner of Rattler. As of December 31, 2019, Diamondback owned approximately 71% of Rattler’s total units outstanding.

Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May of 2019, Diamondback owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of $17.50 per common unit, which included 5,700,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms which closed on May 30, 2019. Rattler received net proceeds of approximately $720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions.

In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B Units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a $1 million cash contribution from Diamondback, (ii) issued a general partner interest in Rattler to Rattler’s General Partner, in exchange for a $1 million cash contribution from Rattler’s General Partner, and (iii) caused Rattler LLC to make a distribution of approximately $727 million to Diamondback. Diamondback, as the holder of the Class B units, and Rattler’s General Partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly.

Diamondback has also entered into the following agreements with Rattler:

Rattler’s Partnership Agreement

In connection with the closing of the Rattler Offering, Rattler’s General Partner and Energen Resources entered into the first amended and restated agreement of limited partnership of Rattler, dated May 28, 2019 (the “Rattler Partnership Agreement”). The Rattler Partnership Agreement requires Rattler to reimburse Rattler’s General Partner for all direct and indirect expenses incurred or paid on Rattler’s behalf and all other expenses allocable to Rattler or otherwise incurred by Rattler’s General Partner in connection with operating Rattler’s business. The Rattler Partnership Agreement does not set a limit on the amount of expenses for which its general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for Rattler or on its behalf and expenses allocated to Rattler’s General Partner by its affiliates. Rattler’s General Partner is entitled to determine the expenses that are allocable to Rattler. For the year ended December 31, 2019, Rattler’s General Partner allocated $364,342 of such expenses to Rattler.

Rattler’s Services and Secondment Agreement
In connection with the closing of the Rattler Offering, Rattler entered into a services and secondment agreement with Diamondback, Diamondback E&P LLC, Rattler’s General Partner and Rattler LLC, dated as of May 28, 2019 (the “Services and Secondment Agreement”). Pursuant to the Services and Secondment Agreement, Diamondback and its subsidiaries second certain operational, construction, design and management employees and contractors of Diamondback to Rattler’s General Partner, Rattler and its subsidiaries, providing management, maintenance and operational functions with respect to Rattler’s assets. The Services and Secondment Agreement requires Rattler’s General Partner and Rattler to reimburse Diamondback for the cost of the seconded employees and contractors, including their wages and benefits. For the year ended December 31, 2019, Rattler’s General Partner and Rattler paid Diamondback $5 million under the Services and Secondment Agreement.

F-25


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Rattler’s Tax Sharing Agreement

In connection with the closing of the Rattler Offering, Rattler LLC entered into a tax sharing agreement with Diamondback pursuant to which Rattler LLC will reimburse Diamondback for its share of state and local income and other taxes borne by Diamondback as a result of Rattler LLC’s results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on May 28, 2019. The amount of any such reimbursement is limited to the tax that Rattler LLC would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which Rattler LLC may be a member for this purpose, to owe less or no tax. In such a situation, Rattler LLC agreed to reimburse Diamondback for the tax Rattler LLC would have owed had the attributes not been available or used for Rattler LLC’s benefit, even though Diamondback had no cash expense for that period.

For the year ended December 31, 2019, Rattler accrued state income tax expense of $188,808 for its share of Texas margin tax for which Rattler’s share of Rattler LLC’s results are included in a combined tax return filed by Diamondback.

Rattler LLC’s Revolving Credit Facility

Rattler LLC has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, sole book runner and lead arranger. See Note 10—Debt for a description of this credit facility.

6.    REAL ESTATE ASSETS    

In conjunction with Diamondback’s acquisition of Fasken Towers Tall Towers, the Company allocated the $110 million purchase price between real estate assets and intangible lease assets related to in-place and above-market leases. In addition, the Company owns $10 million in office buildings. The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of Diamondback’s real estate assets including intangible lease assets:
 Estimated Useful Lives December 31,
  2019 2018
 (Years) (in millions)
Buildings20-30 $102
 $103
Tenant improvements15 5
 4
LandN/A 2
 1
Land improvements15 1
 1
Total real estate assets  110
 109
Less: accumulated depreciation  (9) (4)
Total investment in land and buildings, net  $101
 $105

 Weighted Average Useful Lives December 31,
  2019 2018
 (Months) (in millions)
In-place lease intangibles45 $11
 $11
Less: accumulated amortization  (6) (3)
In-place lease intangibles, net  5
 8
Above-market lease intangibles45 4
 4
Less: accumulated amortization  (1) (1)
Above-market lease intangibles, net  3
 3
Total intangible lease assets, net  $8
 $11



F-26


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


7.    PROPERTY AND EQUIPMENT

Property and equipment includes the following:
 December 31,
 2019 2018
 (in millions)
Oil and natural gas properties:   
Subject to depletion$16,575
 $12,629
Not subject to depletion9,207
 9,670
Gross oil and natural gas properties25,782
 22,299
Accumulated depletion(2,995) (1,599)
Accumulated impairment(1,934) (1,144)
Oil and natural gas properties, net20,853
 19,556
Midstream assets931
 700
Other property, equipment and land125
 147
Accumulated depreciation(74) (31)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment$21,835
 $20,372
    
Balance of costs not subject to depletion:   
Incurred in 2019$604
  
Incurred in 20185,654
  
Incurred in 20172,329
  
Incurred in 2016620
  
Total not subject to depletion$9,207
  


The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs were approximately $49 million, $29 million and $22 million for the years ended December 31, 2019, 2018 and 2017, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any acreage expire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.


F-27


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


As a result of the decline in commodity prices during 2019, the Company recorded a non-cash ceiling test impairment for the year ended December 31, 2019 of $790 million which was included in accumulated depletion. The impairment charge affected the Company’s reported net income but did not reduce its cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods. NaN impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2018.

At December 31, 2019, there was $228 million in exploration costs and development costs and $118 million in capitalized interest that are not subject to depletion. At December 31, 2018, there were $68 million exploration costs and development costs and $55 million capitalized interest that are not subject to depletion.

8.    ASSET RETIREMENT OBLIGATIONS

The following table describes the changes to the Company’s asset retirement obligations liability for the following periods:
 Year Ended December 31,
 2019 2018 2017
 (in millions)
Asset retirement obligations, beginning of period$136
 $21
 $17
Additional liabilities incurred8
 3
 2
Liabilities acquired4
 111
 2
Liabilities settled(61) (2) (1)
Accretion expense7
 2
 1
Revisions in estimated liabilities
 1
 
Asset retirement obligations, end of period94
 136
 21
Less current portion
 
 1
Asset retirement obligations - long-term$94
 $136
 $20


The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

9.    EQUITY METHOD INVESTMENTS

At December 31, 2019 and 2018, Rattler had the following investments:
 Net Ownership Interest December 31, 2019 December 31, 2018
   (In millions)
EPIC Crude Holdings, LP10% $110
 $
Gray Oak Pipeline, LLC10% 115
 1
Wink to Webster Pipeline LLC4% 34
 
OMOG JV LLC60% 219
 
Amarillo Rattler, LLC50% 1
 
   $479
 $1


F-28


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


The following summarizes the income (loss) of equity method investees for the periods presented:
 Year Ended December 31,
 2019 2018 2017
 (In millions)
EPIC Crude Holdings, LP$(6) $
 $
Gray Oak Pipeline, LLC1
 
 
Wink to Webster Pipeline LLC(1) 
 
OMOG JV LLC
 
 
HMW LLC
 
 1
 $(6) $
 $1


In October 2014, the Company acquired a 25% interest in HMW Fluid Management LLC (“HMW LLC”), which was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas.

On June 30, 2018, HMW LLC’s operating agreement was amended. As a result of the amendment, Rattler no longer recognizes an equity investment in HMW LLC but instead consolidates its undivided interest in the produced water disposal (“PWD”) assets owned by HMW LLC. In exchange for Rattler’s 25% investment, Rattler received a 50% undivided ownership interest in 2 of the 4 PWD wells and associated assets previously owned by HMW LLC. Rattler’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC.

On February 1, 2019, Rattler LLC acquired a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which is building a pipeline (the “EPIC project”) that, once fully operational, will transport crude and NGL across Texas for delivery into the Corpus Christi market. The EPIC project began initial operations during the third quarter of 2019.

On February 15, 2019, Rattler LLC acquired a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which is building a pipeline (the “Gray Oak project”) that, once operational, will transport crude from the Permian to Corpus Christi on the Texas Gulf Coast. The Gray Oak project began initial operations during the fourth quarter of 2019.

On March 29, 2019, Rattler LLC executed a short-term promissory note to Gray Oak. The note allows for borrowing by Gray Oak of up to $123 million at 2.52% interest rate with a maturity date of March 31, 2022. During the year ended December 31, 2019, there were $23 million in borrowings and repayments under this note. The short-term promissory note was repaid on May 31, 2019.

On June 4, 2019, Rattler entered into an equity contribution agreement with respect to Gray Oak. The equity contribution agreement requires Rattler to contribute equity or make loans to Gray Oak so that Gray Oak can, to the extent necessary, cure payment defaults under Gray Oak’s credit agreement and, in certain instances, repay Gray Oak’s credit agreement in full. Rattler’s obligations under the equity contribution agreement are limited to its proportionate ownership interest in Gray Oak, and such obligations are guaranteed by Rattler LLC, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC.

On July 30, 2019, Rattler LLC joined Wink to Webster Pipeline LLC as a 4% member, together with affiliates of ExxonMobil, Plains All American Pipeline, Delek US, MPLX LP and Lotus Midstream. The joint venture is developing a crude oil pipeline with origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations (the “Wink to Webster project”). The Wink to Webster project is expected to begin service in the first half of 2021.

On October 1, 2019, Rattler LLC acquired a 60% equity interest in OMOG JV LLC (“OMOG”). On November 7, 2019, OMOG acquired 100% of Reliance Gathering, LLC which operates a crude oil gathering system in the Permian, and was renamed as Oryx Midland Oil Gathering LLC following the acquisition. While Rattler’s equity interest is 60%, the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling minority investor.

On December 20, 2019, Rattler LLC acquired a 50% equity interest in Amarillo Rattler LLC, which currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. This joint

F-29


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


venture also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin County, Texas. While Rattler’s equity interest is 50%, the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling investor.

NaN impairments were recorded for Rattler’s equity method investments for the year ended December 31, 2019 or 2018.

At December 31, 2019, there was $1 million of capitalized interest that was related to equity method investments that have not yet begun operations.

10.    DEBT
Long-term debt consisted of the following as of the dates indicated:
 December 31,
 2019 2018
 (in millions)
4.625% Notes due 2021$399
 $400
7.320% Medium-term Notes, Series A, due 202221
 20
2.875% Senior Notes due 20241,000
 
4.750% Senior Notes due 2024
 1,250
5.375% Senior Notes due 2025800
 800
3.250% Senior Notes due 2026800
 
7.350% Medium-term Notes, Series A, due 202711
 10
7.125% Medium-term Notes, Series B, due 2028108
 100
3.500% Senior Notes due 20291,200
 
DrillCo Agreement39
 
Unamortized debt issuance costs(19) (27)
Unamortized discount costs(31) 
Unamortized premium costs9
 10
Revolving credit facility13
 1,490
Viper revolving credit facility97
 411
Viper 5.375% Senior Notes due 2027500
 
Rattler revolving credit facility424
 
Total long-term debt$5,371
 $4,464


Diamondback Notes

4.750% Senior Notes

On October 28, 2016, the Company issued $500 million in aggregate principal amount of 4.750% senior notes due 2024 (“4.750% senior notes”), under an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On September 25, 2018, the Company issued $750 million aggregate principal amount of new 4.750% senior notes as additional notes under, and subject to the terms of, the same indenture governing the 4.750% senior notes. The Company received approximately $741 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the new 4.750% senior notes. The Company used a portion of the net proceeds from the issuance of the new 4.750% senior notes to repay a portion of the outstanding borrowings its revolving credit facility and the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of certain assets from Ajax Resources, LLC..

On December 20, 2019, the Company redeemed all of the outstanding 4.750% senior notes. The redemption payment (the “Redemption Payment”) included $1.25 billion of outstanding principal at a redemption price of 103.563% of the principal amount of the 4.750% senior notes, plus accrued and unpaid interest on the outstanding principal amount to the Redemption

F-30


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Date. On December 5, 2019, the indenture governing the 4.750% senior notes was fully satisfied and discharged and the guarantors were released from their guarantees of the 4.750% senior notes. The Company funded the Redemption Payment with a portion of the net proceeds from the issuance of the December 2019 Notes.

The 4.750% senior notes bore interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and would have matured on November 1, 2024. All of our restricted subsidiaries that guaranteed our revolving credit facility guaranteed the 4.750% senior notes; provided, however, that the 4.750% senior notes were not guaranteed by Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner or Rattler LLC.

2025 Senior Notes

On December 20, 2016, the Company issued $500 million in aggregate principal amount of 5.375% senior notes due 2025 (the “existing 2025 notes”), under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee (the “2025 indenture”). On January 29, 2018, the Company issued $300 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture (the “new 2025 notes” and, together with the existing 2025 notes, the 2025 senior notes). The Company received approximately $308 million in net proceeds, after deducting the initial purchaser’s discount and the Company’s estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. The Company used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under its revolving credit facility.
The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility guarantee the 2025 senior notes. Currently, the 2025 senior notes are not guaranteed by any of the Company’s subsidiaries other than Diamondback O&G LLC and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.
The Company may on any one or more occasions redeem some or all of the 2025 senior notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or more occasions redeem all or a portion of the 2025 senior notes at a price equal to 100% of the principal amount of the 2025 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem the 2025 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 senior notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

December 2019 Notes Offering

On December 5, 2019, the Company issued $1.0 billion in aggregate principal amount of 2.875% senior notes due 2024 (the “2024 notes”), $800 million in aggregate principal amount of 3.250% senior notes due 2026 (the “2026 notes”), and $1.2 billion aggregate principal amount of 3.500% senior notes due 2029, (the “2029 notes” and, together with the 2024 notes and the 2026 notes, the “December 2019 Notes”). The 2024 notes will mature on December 1, 2024, the 2026 notes will mature on December 1, 2026 and the 2029 notes will mature on December 1, 2029. Interest will accrue and be payable semi-annually, in arrears on June 1 and December 1 of each year, commencing on June 1, 2020. The December 2019 Notes are fully and unconditionally guaranteed by Diamondback O&G LLC and are not guaranteed by any of the Company’s other subsidiaries.

The December 2019 Notes were issued under an indenture, dated as of December 5, 2019, among the Company and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019 (the “December 2019 Notes Indenture”).
The Company may redeem (i) the 2024 Notes in whole or in part at any time prior to November 1, 2024 (one month prior to the maturity date of the 2024 Notes), (ii) the 2026 Notes in whole or in part at any time prior to October 1, 2026 (two months prior to the maturity date of the 2026 Notes) and (iii) the 2029 Notes in whole or in part at any time prior to September 1, 2029 (three months prior to the maturity date of the 2029 Notes) (each such date, a “par call date”), in each case at the

F-31


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


redemption price set forth in the indenture governing the December 2019 Notes. If the December 2019 Notes are redeemed on or after their respective par call dates, in each case, such December 2019 Notes will be redeemed at a redemption price equal to 100% of the principal amount of the December 2019 Notes to be redeemed plus interest accrued thereon to but not including the redemption date.

Upon the occurrence of a Change of Control Triggering Event (as defined in the indenture governing the December 2019 Notes), holders may require the Company to purchase some or all of their December 2019 Notes for cash at a price equal to 101% of the principal amount of the December 2019 Notes being purchased, plus accrued and unpaid interest, if any, to the date of purchase.

The indenture governing the December 2019 Notes contains customary terms and covenants, including limitations on the Company’s ability and the ability of certain of its subsidiaries to incur liens securing funded indebtedness and on the Company’s ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of its assets.

Second Amended and Restated Credit Facility

The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. On June 28, 2019, the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied (the “investment grade changeover date”). On November 20, 2019, Diamondback O&G LLC caused Diamondback O&G LLC to deliver a notice as borrower under the revolving credit facility to trigger the “investment grade changeover date.” As of December 31, 2019, the maximum credit amount available under the credit agreement is $2.0 billion. As of December 31, 2019, the Company had approximately $13 million of outstanding borrowings under its revolving credit facility and $1.99 billion available for future borrowings under the revolving credit facility.

Diamondback O&G LLC is the borrower under the credit agreement, and, as of December 31, 2019, the credit agreement is guaranteed by Diamondback Energy, Inc. None of the Company’s other subsidiaries are guarantors under the revolving credit facility. On December 5, 2019, Diamondback O&G LLC delivered a letter notifying the administrative agent under the credit agreement that as of such date, each of the guarantors, other than Diamondback Energy, Inc., ceased to be a guarantor under the credit agreement.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to the alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5%, and 3 month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin with range from 0.125% to 1.0% per annum and from 1.125% to 2.0% per annum in the case of LIBOR, in each case, depending on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt.
Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction of the aggregate maximum credit amount and (b) at the maturity date of November 1, 2022.
The credit agreement contains a financial covenant that requires us to maintain a Total Net Debt to Capitalization Ratio (as defined in the credit agreement) of no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets.

As of December 31, 2019 and 2018, the Company was in compliance with all financial covenants under the revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

F-32


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Energen Notes
At the effective time of the Merger, Energen became the Company’s wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes (the “Energen Notes”), issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee (the “Energen Indenture”). As of December 31, 2019, the Energen Notes consist of: (1) $399 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $108 million of 7.125% notes due on February 15, 2028, (3) $21 million of 7.32% notes due on July 28, 2022, and (4) $11 million of 7.35% notes due on July 28, 2027.
The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as a wholly owned subsidiary, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen if any, and are effectively subordinated to Energen’s senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. Neither we nor any of our subsidiaries guarantee the Energen Notes.
The Energen Indenture contains certain covenants that, subject to certain exceptions and qualifications, limit Energen’s ability to incur or suffer to exist liens, to enter into sale and leaseback transactions, to consolidate with or merge into any other entity, and to convey, transfer or lease its properties and assets substantially as an entirety to any person or entity.  The Energen Indenture not include a restriction on the payment of dividends.
On November 29, 2018, Energen guaranteed the Company’s indebtedness under its credit facility and granted a lien on certain of its assets to secure such indebtedness, and on December 21, 2018, Energen’s subsidiaries guaranteed the Company’s indebtedness under its credit agreement and granted liens on certain of their assets to secure such indebtedness. As a result of such guarantees, under the terms of and the 2025 Indenture, Energen is also a guarantor of the 2025 Senior Notes.
Viper’s Facility - Wells Fargo Bank

On July 20, 2018, Viper LLC, as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended (the “Viper credit agreement”), provides for a revolving credit facility in the maximum credit amount of $2 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $775 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper LLC and Wells Fargo each may request up to 3 interim redeterminations of the borrowing base during any 12-month period. In connection with Viper’s fall redetermination in November 2019, the borrowing base under the Viper credit agreement was increased to $775 million. As of December 31, 2019, the borrowing base was set at $775 million, and Viper LLC had $97 million of outstanding borrowings and $678 million available for future borrowings under the Viper credit agreement.

The outstanding borrowings under the Viper credit agreement bear interest at a per annum rate elected by Viper LLC that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. Viper LLC is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of Viper and Viper LLC.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, purchases of margin stock and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial CovenantRequired Ratio
Ratio of total net debt to EBITDAX, as defined in the Viper credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined the Viper credit agreementNot less than 1.0 to 1.0


The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $1.0 billion in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. The covenant limiting dividends and distributions includes an exception allowing Viper LLC to make distributions if no default, event of default or borrowing base deficiency exists.

As of December 31, 2019 and 2018, Viper and Viper LLC were in compliance with all financial covenants under the Viper credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

Viper’s Notes