Diamondback Energy (FANG) 10-K risk factor changes: FY2019 vs FY2018

[removed: The] [added: *The] nature of our business activities subjects us to certain hazards and risks.

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 [removed: decline.][added: decline.*]

[removed: Failure] [added: Restrictions on our ability] to [removed: successfully manage the combined company] [added: obtain water] may have an adverse effect on our financial condition, results of operations [removed: or] [added: and] cash [removed: flows.][added: flows.]

[removed: Risks] [added: Risks] Related to the Oil and Natural Gas Industry and Our [removed: Business][added: Business]

[removed: Market] [added: 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 [removed: reserves.][added: reserves.]

[removed: Historically, oil and natural gas prices have] 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:

During the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as [removed: West Texas Intermediate or WTI,] [added: WTI Futures Contract 1 price for crude oil] has ranged from a low of [removed: $26.19] [added: $26.21] per barrel, or Bbl, in February 2016 to a high of [removed: $107.95] [added: $76.41] per Bbl in [removed: June 2014.][added: October 2018.]

The [removed: Henry Hub] [added: Natural Gas Futures Contract 1 price] spot market price of natural gas has ranged from a low of [removed: $1.49] [added: $1.64] per MMBtu in March 2016 to a high of [removed: $8.15] [added: $4.84] per MMBtu in [removed: February 2014.][added: November 2018.]

During [removed: 2018,] [added: 2019,] WTI [added: Futures Contract 1] prices ranged from [removed: $44.48] [added: $46.54] to [removed: $77.41] [added: $66.30] per Bbl and the [removed: Henry Hub] [added: Natural Gas Futures Contract 1] spot market price of natural gas ranged from [removed: $2.49] [added: $2.07] to [removed: $6.24] [added: $3.59] per MMBtu.

On January [removed: 28, 2019,] [added: 31, 2020,] the WTI [added: Futures Contract 1] posted price for crude oil was [removed: $51.79] [added: $51.56] per Bbl and the [removed: Henry Hub] [added: Natural Gas Futures Contract 1] spot market price of natural gas was [removed: $3.05] [added: $1.84] per MMBtu, representing decreases of [removed: 33%] [added: 22%] and [removed: 51%,] [added: 49%,] respectively, from the high of [removed: $77.41] [added: $66.30] per Bbl of oil and [removed: $6.24] [added: $3.59] per MMBtu for natural gas during [removed: 2018.][added: 2019.]

In response to recent [removed: declines] [added: volatility] in commodity prices, many producers have reduced their capital expenditure budgets.

If the prices of oil and natural gas [removed: remain at current levels or] 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.

[removed: Reductions in our] 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.

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

In addition, continued hostilities in the Middle [removed: East and] [added: East,] the occurrence or threat of terrorist attacks in the United States or other countries [added: and global or national health concerns] could adversely affect the global economy.

[removed: A] [added: 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 [removed: income.][added: income.]

[removed: Our] [added: 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 [removed: reserves.][added: reserves.]

In [removed: 2018,] [added: 2019,] our total capital expenditures, including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately [removed: $3.3] [added: $3.1] billion.

Our [removed: 2019] [added: 2020] capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately [removed: $2.7] [added: $2.8] billion to $3.0 billion, representing an increase of [removed: 85%] [added: 1%] over our [removed: 2018] [added: 2019] capital budget.

Further, our actual capital expenditures in [removed: 2019] [added: 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 [removed: financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means.]

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, [added: revenues and results of operations.]

[removed: Our] [added: Our] success depends on finding, developing or acquiring additional [removed: reserves.][added: reserves.]

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

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 [added: our earnings and growth.]

[removed: Properties] [added: 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 [removed: liabilities.][added: liabilities.]

[removed: We] [added: We] may incur losses as a result of title defects in the properties in which we [removed: invest.][added: invest.]

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

[removed: Our] [added: 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 [removed: drilling.][added: drilling.]

At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately [removed: 11,868] [added: 12,310] gross [removed: (7,633] [added: (8,141] net) identified economic potential horizontal drilling locations in multiple horizons on our acreage.

As of December 31, [removed: 2018,] [added: 2019,] only [removed: 416] [added: 477] of our gross identified potential horizontal drilling locations were attributed to proved reserves.

In addition, we have identified approximately [removed: 3,195] [added: 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 [removed: completion costs or to be economically viable.]

[added: Through December 31, 2019, we are the operator of, have participated in, or have] acquired a total of [removed: 1,465] [added: 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.

[removed: Multi-well] [added: Multi-well] pad drilling may result in volatility in our operating [removed: results.][added: results.]

[removed: Our] [added: 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 [removed: opportunities.][added: opportunities.]

As of December 31, [removed: 2018,] [added: 2019,] we had leases representing [removed: 37,536] [added: 42,421] net acres expiring in [removed: 2019, 27,690] [added: 2020, 7,626] net acres expiring in [removed: 2020, 6,867] [added: 2021, 2,387] net acres expiring in [removed: 2021, 254] [added: 2022, 4,919] net acres expiring in [removed: 2022] [added: 2023] and no net acres expiring in [removed: 2023.][added: 2024.]

In addition, in order to hold our current leases expiring in [removed: 2019,] [added: 2020,] we will need to operate at least a one-rig program.

[removed: We] [added: We] have entered into fixed price swap contracts, fixed price basis swap [added: contracts, double-up swap] contracts and [removed: costless] [added: three-way] collars with corresponding [added: put, short] put and call options and may in the future enter into forward sale contracts or additional fixed price swap, fixed price basis [added: swap, double-up] swap derivatives or [removed: costless] [added: three-way] collars for a portion of our production.

Historically, oil and natural gas prices have

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

Reductions in our

financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means.

completion costs or to be economically viable.

If the settlement price is between the floor and the ceiling price, there is no payment required.

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.

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.

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.

To the extent capitalized costs of

complete multiple wells before any such wells begin producing.

For a more detailed discussion of federal laws concerning hydraulic fracturing, see “Items 1 and 2.

In addition, if hydraulic fracturing is further

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

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 Foreign Regulations could have similar effects.

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.

On November 4, 2019, the Trump Administration submitted its formal notification of withdrawal to the United Nations.

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,

Risk Related to Our Recently Completed Merger with Energen

The integration of Energen’s business into our business may not be as successful as anticipated, and we may not achieve the intended benefits of the merger or do so within the intended timeframe.

We completed the merger with Energen on November 29, 2018.

The merger involves numerous operational, strategic, financial, accounting, legal, tax and other risks, including potential liabilities associated with the acquired business.

Difficulties in integrating Energen’s business into our business, and our ability to manage the combined company, may result in the combined company performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies, and could have an adverse effect on our financial condition, results of operations or cash flows.

Potential difficulties that may be encountered in the integration process include, among other factors:

| | |

| --- | --- |

| • | the inability to successfully integrate the businesses of Energen into our business, operationally and culturally; |

| | |

| --- | --- |

| • | complexities associated with managing the larger, more complex, integrated business; |

| | |

| --- | --- |

| • | complexities resulting from the different accounting methods of our company and Energen; |

| | |

| --- | --- |

| • | not realizing anticipated operating synergies; |

| | |

| --- | --- |

| • | integrating personnel from the two companies and the loss of key employees; |

| | |

| --- | --- |

| • | potential unknown liabilities and unforeseen expenses associated with the merger or integration; |

| | |

| --- | --- |

| • | integrating relationships with customers, vendors and business partners; |

| | |

| --- | --- |

| • | performance shortfalls as a result of the diversion of management’s attention caused by integrating Energen’s operations into operations; and |

| | |

| --- | --- |

| • | the disruption of, or the loss of momentum in, our business or inconsistencies in standards, controls, procedures and policies encountered during integration of our business with that of Energen. |

Additionally, the success of the merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and Energen’s businesses, including operational and other synergies that we believe the combined company will achieve.

The anticipated benefits and cost savings of the merger may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee.

Our results may suffer if we do not effectively manage our expanded operations following the merger.

Following the merger, the size of our business increased significantly beyond the former size of our business.

Our future success will depend, in part, on our ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of Energen into our business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors and business partners.

Sales of substantial amounts of our common stock in the open market, by former Energen shareholders or otherwise, could depress our common stock price.

Our stockholders may not wish to continue to invest in the additional operations of the combined company, or for other reasons may wish to dispose of some or all of their interests in the combined company, and as a result may seek to sell their shares of our common stock.

[removed: The] [added: *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.

“Risk Factors” and “Cautionary Statement Regarding Forward-Looking [removed: Statements.”][added: Statements.”*]

[removed: Overview][added: Overview]

[removed: Our] [added: 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.

The following table sets forth [removed: our production] [added: selected historical operating] data for the periods indicated:

| | [removed: Year] [added: Year] Ended December [removed: 31, | | |] [added: 31,] | | | | |

| Oil (MBbls) | [removed: 72 | % | | 74] [added: 66] | % | | [removed: 73] [added: 72] | % |

| Natural gas (MMcf) | [removed: 12] [added: 16] | % | | 12 | % | [removed: | 11 | % |]

| Natural gas liquids (MBbls) | [removed: 16 | % | | 14] [added: 18] | % | | 16 | % |

| | 100 | % | | 100 | % | [removed: | 100 | % |]

[removed: 2018 Transactions] [added: 2019 Transactions] and Recent [removed: Developments][added: Developments]

[removed: Drop-down Transaction][added: Drop-Down]

[removed: New] [added: 4.750%] Senior [removed: Notes][added: Notes]

On January 29, 2018, we issued $300.0 million aggregate principal amount of new [removed: 2025] [added: 5.375% senior] notes [added: due 2025] as additional notes under [removed: our existing] [added: the 2025] indenture, [removed: dated as of December 20, 2016, as supplemented, among us, subsidiary guarantors party thereto and Wells Fargo, as trustee, under] which we [removed: previously issued $500.0 million aggregate principal amount of our] [added: refer to as the new 2025 notes and, together with the] existing [removed: 5.375% Senior Notes due 2025.][added: 2025 notes, as the 2025 senior notes.]

We received approximately [removed: $308.4] [added: $741] million in net proceeds, after deducting the initial [removed: purchaser’s] [added: purchasers’] discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the [removed: new 2025] [added: 4.750% senior] notes.

[removed: We] [added: Viper LLC] used the [removed: net] proceeds from the [removed: issuance of the new 2025 notes] [added: Viper Notes Offering] to [removed: repay a portion of the outstanding] [added: pay down] borrowings under [removed: our] [added: its] revolving credit facility.

On September 25, 2018, we issued [removed: $750.0] [added: $750] million aggregate principal amount of new 4.750% senior notes [removed: due 2024, or] [added: as additional notes under, and subject to] the [removed: new 2024] [added: terms of the same indenture governing the 4.750% senior] notes.

We used a portion of the net proceeds from the issuance of the [removed: new 2024] [added: 4.750% senior] notes to repay a portion of the outstanding borrowings our revolving credit facility and [removed: we used] the balance for general corporate purposes, including [removed: the] funding [removed: of] a portion of the cash consideration for the [added: acquisition of certain assets from] Ajax [removed: acquisition.][added: Resources LLC.]

We, as the holder of the Class B [removed: units,] [added: units in Viper] and [removed: the General Partner,] [added: Viper’s general partner,] as the holder of the general partner interest, are entitled to receive [removed: an] [added: cash preferred distributions equal to] 8% [removed: annual distribution] [added: per annum] on the outstanding amount of [removed: these] [added: their respective] capital [removed: contributions,] [added: contributions] payable [removed: quarterly, as a return on this invested capital.][added: quarterly.]

[removed: Viper’s July 2018] [added: Viper’s] Equity [removed: Offering][added: Offering]

[removed: In July 2018,] [added: On March 1, 2019,] Viper completed an underwritten public offering of [removed: 10,080,000] [added: 10,925,000] common units, which included [removed: 1,080,000] [added: 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 [removed: 59%] [added: 54%] of Viper’s total units then outstanding.

[removed: Viper received net proceeds from this offering] of approximately [removed: $303.1] [added: $341] million, after deducting underwriting discounts and commissions and estimated offering expenses.

Viper used the net proceeds to purchase units of [removed: the Operating Company.][added: Viper LLC.]

[removed: The Operating Company] [added: Viper LLC] in turn used the net proceeds to repay a portion of the [removed: $361.5 million then] outstanding borrowings under its revolving credit [removed: facility.][added: facility and finance acquisitions during the period.]

[removed: Operational Update][added: Operational Update]

We are operating [removed: 21] [added: 23 drilling] rigs now [added: including two rigs drilling produced water disposal wells] and currently intend to operate between [removed: 18] [added: 20] and [removed: 22] [added: 23] drilling rigs in [removed: 2019] [added: 2020 on average] across our asset base in the Midland and Delaware Basins.

In the Midland Basin, we [removed: continue] [added: 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 [removed: multiple] [added: 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.

To combat [removed: rising] [added: 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 [removed: 2019] [added: 2020] drilling and completion budget accounts for capital costs that we believe [removed: will] cover potential increases in our service costs during the year.

[removed: 2019 Capital Budget][added: 2020 Capital Budget]

We have currently budgeted a [removed: 2019] [added: 2020] total capital spend of [removed: $2.7] [added: $2.8] billion to $3.0 billion, consisting of [removed: $2.3] [added: $2.45] billion to [removed: $2.55] [added: $2.6] billion for horizontal drilling and completions including non-operated activity, [removed: $400.0] [added: $200] million to [removed: $450.0] [added: $225] million for midstream [added: investments, excluding joint venture investments,] and [added: $150 million to $175 million for] infrastructure [removed: investments,] [added: and other expenditures,] excluding [removed: equity investments in long-haul pipelines or] the cost of any leasehold and mineral [removed: rights] [added: interest] acquisitions.

We expect to drill and complete [removed: 290 to] 320 [added: to 360] gross horizontal wells in [removed: 2019.][added: 2020.]

| | [removed: Year] [added: Year] Ended December [removed: 31,] [added: 31,] | | | | | [added: | |]

[removed: Reserves] [added: Reserves] and [removed: pricing][added: pricing]

Ryder Scott prepared estimates of our proved reserves at December 31, [removed: 2018, 2017] [added: 2019] and [removed: 2016] [added: 2018] (which include estimated proved reserves attributable to Viper).

[added: 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.

| [removed: Estimated] [added: Estimated] Net Proved [removed: Reserves: | | |] [added: Reserves:] | | | | | |

| Oil (MBbls) | [removed: 626,936 | | | 233,181] [added: 710,903] | | | [removed: 139,174] [added: 626,936] | |

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

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.

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.

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.

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.

| | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | |

| | 2018 | | | 2017 | | | 2016 | |

On December 31, 2018, our acreage position in the Permian Basin was approximately 604,367 gross (461,218 net) acres, which consisted primarily of approximately 231,100 gross (194,661 net) acres in the Midland Basin and approximately 232,143 gross (170,205 net) acres in the Delaware Basin.

2018 was another transformational year for us.

We successfully closed three acquisitions in the fourth quarter of 2018, including our acquisition of Energen Corporation, or Energen, which acquisitions, on a combined basis, almost doubled our core acreage position.

During the same period, oil prices declined dramatically, and we quickly addressed the issue by announcing a reduction in activity levels in late 2018 and acting on that plan immediately in 2019.

At current commodity prices, we expect to grow production by over 27% year over year within cash flow in 2019, while increasing our dividend by 50% beginning with the first quarter of 2019.

By remaining focused on corporate returns and prudent capital allocation, we believe that in the current commodity price environment we are positioned to generate significant free cash flow while continuing to grow production at industry leading rates in 2020 and beyond.

We are operating 21 rigs now and currently intend to operate between 18 and 22 rigs in 2019.

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.

Merger with Energen Corporation

On November 29, 2018, we completed our acquisition of Energen in an all-stock transaction, which we refer to as the merger.

We consolidate our results of operations with those of Energen and its subsidiaries acquired by us in the merger beginning with November 29, 2019, the closing date of the merger.

We accounted for the merger as a business combination.

The addition of Energen’s assets increased our assets to: (i) over 273,000 net Tier One acres in the Permian Basin, an increase of 57% from third quarter 2018 Tier One acreage of approximately 174,000 net acres, (ii) over 7,200 estimated total net horizontal Permian locations, an increase of over 120% from third quarter 2018 estimated net locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins, an increase of 82% from our approximately 216,000 net acres as September 30, 2018, in each after giving effect to our recently completed Ajax acquisition and ExL acquisition discussed below.

Under the terms of the merger agreement, we assumed Energen’s outstanding debt, which at the effective time of the merger was approximately $1.1 billion.

This amount consisted of $559.0 million of borrowings under Energen’s existing credit facility, $400.0 million aggregate principal amount of 4.625% Notes, due September 1, 2021, $20.0 million aggregate principal amount of 7.32% Medium-term Notes, Series A, due July 28, 2022, $10.0 million aggregate principal amount of 7.35% Medium-term Notes, Series A, due July 28, 2027, and $100.0 million aggregate principal amount of 7.125% Medium-term Notes, Series B, due February 15, 2028, which we collectively refer to as the Energen Notes.

In connection with the closing of the Merger, we repaid the outstanding borrowings of $559.0 million under the Energen credit facility using cash on hand and borrowings under our revolving credit facility.

Ajax Resources, LLC

On October 31, 2018, we acquired certain leasehold interests and related assets of Ajax Resources, LLC, which we refer to as Ajax, which included approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of our common stock, which we refer to as the Ajax acquisition.

The Ajax acquisition 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 Energy Partners LP, which we refer to as Viper or the Partnership, described below, borrowings under our revolving credit facility and proceeds from our September 2018 senior note offering.

See “—New Senior Notes” below.

In connection with the closing of the Ajax acquisition on October 31, 2018, we entered into a registration rights agreement with Ajax and certain other holders of our common stock pursuant to which we filed a shelf registration statement with the SEC to facilitate the resale of common stock issued in the Ajax acquisition.

The shelf registration statement became automatically effective on November 30, 2018.

Pursuant to this registration rights agreement, we also agreed to provide certain demand and piggyback registration rights to such holders.

On December 11, 2018, we entered into an ATM Equity Offering SM Sales Agreement with Ajax, certain other holders of our common stock and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as sales agent, in connection with potential sales from time to time during the term of the sales agreement by Ajax of up to approximately 2.0 million shares of our common stock under the above-referenced shelf registration statement.

ExL Petroleum Management, LLC and EnergyQuest II LLC Acquisition

On October 31, 2018, we acquired certain leasehold interests and related assets of ExL Petroleum Management, LLC, ExL Petroleum Operating, Inc. and EnergyQuest II LLC, which included an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $312.5 million in cash, subject to certain adjustments.

These acquisitions which we collectively refer to as the ExL acquisition, were effective as of August 1, 2018, and were funded through a combination of cash on hand, proceeds from the sale of assets to the Partnership (described below) and borrowing under our revolving credit facility.

On August 15, 2018, we sold to the Partnership 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 us, for $175.0 million, which we refer to as the Drop-down Transaction.

Alliance with Obsidian Resources, L.L.C.

We entered into a participation and development agreement, which we refer to as the DrillCo agreement, dated September 10, 2018, with Obsidian Resources, L.L.C., which we refer to as CEMOF, to fund oil and natural gas development.

Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300.0 million, to fund drilling programs on locations provided by us.

Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return.

Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15%, while our interest will increase to 85%.

Transportation Contracts

[removed: Commodity] [added: Commodity] Price [removed: Risk][added: Risk]

We use price swap derivatives, including basis [added: 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.

Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX [removed: WTI][added: 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, [added: 2019 and December 31,] 2018, we had a net asset derivative position of [removed: $215.3 million as compared to a net liability derivative position of $106.1] [added: $26] million [removed: at December 31, 2017,] [added: 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, [removed: 2018,] [added: 2019,] a 10% increase in forward curves associated with the underlying commodity would have decreased the net asset position to [removed: $157.8] [added: a net liability position of $178] million, [removed: an increase] [added: a decrease] of [removed: $57.6] [added: $204] million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset derivative position to [removed: $272.9] [added: $232] million, [removed: a decrease] [added: an increase] of [removed: $57.6] [added: $206] million.

[removed: Counterparty] [added: Counterparty] and Customer Credit [removed: Risk][added: Risk]

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately [removed: $95.5] [added: $186] million at December 31, [removed: 2018)] [added: 2019)] and receivables from the sale of our oil and natural gas production (approximately [removed: $296.5] [added: $429] million at December 31, [removed: 2018).][added: 2019).]

For the year ended December 31, 2018, three purchasers each accounted for more than 10% of our revenue: Shell [removed: Trading (US) Company] (26%); Koch [removed: Supply & Trading LP] (15%); and Occidental Energy Marketing [removed: Inc] [added: Inc.] (11%).

For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell [removed: Trading (US) Company] (31%); Koch [removed: Supply & Trading LP] (19%); and Enterprise Crude Oil LLC (11%).

For the year ended December 31, [removed: 2016,] [added: 2019,] three purchasers each accounted for more than 10% of our revenue: Shell [removed: Trading (US) Company (45%); Koch Supply & Trading LP (15%);] [added: (27%); Plains (23%);] and [removed: Enterprise Crude Oil LLC (13%).][added: Vitol (15%).]

At December 31, 2018, we had four [removed: customers] [added: customer] that represented approximately 82% of our total joint operations receivables.

At December 31, [removed: 2017,] [added: 2019,] we had [removed: three customer] [added: 15 customers] that represented approximately [removed: 74%] [added: 80%] of our total joint operations receivables.

[removed: Interest] [added: Interest] Rate [removed: Risk][added: Risk]

The [removed: terms of our revolving] [added: outstanding borrowings under the] credit [removed: facility provide for] [added: agreement bear] interest [removed: on borrowings] at a [removed: floating] [added: per annum] rate [added: elected by us that is] equal [removed: to] an [removed: alternative] [added: alternate] base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus [removed: 0.5%] [added: 0.50%] and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin.

As of December 31, [removed: 2018,] [added: 2019,] we had [removed: $1.5 billion] [added: $13 million] borrowings outstanding under our revolving credit facility.

Our weighted average interest rate on borrowings under our revolving credit facility was [removed: 4.10%] [added: 3.20%] on December 31, [removed: 2018.][added: 2019.]

An increase or decrease of 1% in the interest rate would have a corresponding [removed: decrease or] increase [added: or decrease] in our interest expense of approximately [removed: $14.9 million] [added: $130,000] based on the [removed: $1.5 billion] [added: $13 million] outstanding in the aggregate under our revolving credit facility as of such date.

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, 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.

(Cushing and Magellan East Houston) and Crude Oil - Brent and with natural gas derivative settlements based on NYMEX Henry Hub and Waha Hub.

The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base.

[removed: Overview][added: Overview]

At December 31, [removed: 2018,] [added: 2019,] our total acreage position in the Permian Basin was approximately [removed: 604,367] [added: 455,378] gross [removed: (461,218] [added: (382,337] net) acres, which consisted primarily of approximately [removed: 231,100] [added: 218,138] gross [removed: (194,661] [added: (195,461] net) acres in the Midland Basin and approximately [removed: 232,143] [added: 196,171] gross [removed: (170,205] [added: (155,296] net) acres in the Delaware Basin.

In addition, [removed: we, through] our publicly traded subsidiary Viper Energy Partners LP, which we refer to as [removed: Viper or the Partnership, own] [added: Viper, owns] mineral interests underlying approximately [removed: 532,295] [added: 814,224] gross acres and [removed: 14,841] [added: 24,304] net royalty acres in the Permian Basin and Eagle Ford Shale.

Approximately [removed: 37%] [added: 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 [removed: the] [added: Viper’s] general partner, and we own approximately [removed: 59%] [added: 58%] of the limited partner interest in Viper.

As of December 31, [removed: 2018,] [added: 2019,] our estimated proved oil and natural gas reserves were [removed: 992,001] [added: 1,127,575] MBOE (which includes estimated reserves of [removed: 63,136] [added: 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 [removed: 65%] [added: 67%] are classified as proved developed producing.

Proved undeveloped, or PUD, reserves included in this estimate are from [removed: 416] [added: 477] gross [removed: (374] [added: (434] net) horizontal well locations in which we have a working interest, and [removed: 25] [added: 22] horizontal wells in which we own only a mineral interest through our subsidiary, Viper.

As of December 31, [removed: 2018,] [added: 2019,] our estimated proved reserves were approximately 63% oil, [removed: 18%] [added: 20%] natural gas liquids and [removed: 19%] [added: 17%] natural gas.

Based on our evaluation of applicable geologic and engineering data, we currently have approximately [removed: 11,868] [added: 12,310] gross [removed: (7,633] [added: (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.

[removed: Drop-down Transaction][added: Drop-Down]

[removed: Our] [added: Our] Business [removed: Strategy][added: Strategy]

| [removed: •] [added: •] | [removed: Grow] [added: Grow] production and reserves by developing our oil-rich resource [removed: base.] [added: 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. |

| [removed: •] [added: •] | [removed: Focus] [added: Focus] on increasing hydrocarbon recovery through horizontal development of stacked [removed: horizons.] [added: 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. [removed: As of December 31, 2018, we are the operator of 1,193 producing horizontal wells and have a non-operated working interest in 253 additional wells. Of these 1,446 total horizontal wells, 952 wells are in the Midland Basin, 493 wells are in the Delaware Basin and one well is in the Central Basin platform.] We believe that our significant experience drilling, completing and operating horizontal wells will allow us to efficiently develop our remaining inventory and ultimately target other horizons that have limited development to date. [removed: During the year ended December 31, 2018, we were able to drill our] [added: The following table presents] horizontal wells in [removed: the Midland Basin with approximately 7,500 foot lateral lengths to total depth, or TD, in an average of 13 days, we drilled approximately 10,000 foot lateral wells in 15 days and we drilled approximately 13,000 foot wells in 23 days. During the year ended December 31, 2018,] [added: which] we [removed: were able to drill our horizontal wells in the Delaware Basin with approximately 7,500 foot lateral lengths to total depth in] [added: have] an [removed: average of 24 days and we drilled approximately 10,000 foot lateral wells in 31 days. Further advances in drilling and completion technology may result] [added: interest] in [removed: economic development] [added: as] of [removed: zones that are not currently viable.] [added: December 31, 2019:] |

| • | [removed: Leverage] [added: Leverage] our experience operating in the Permian [removed: Basin.] [added: 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. |

| [removed: •] [added: •] | [removed: Enhance] [added: Enhance] returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost [removed: efficiencies.] [added: efficiencies.] Our acreage position [removed: in the Wolfberry play] is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately [removed: 89%] [added: 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 [removed: 76%] [added: 84%] working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies. |

| [removed: •] [added: •] | [removed: Pursue] [added: Pursue] strategic acquisitions with substantial resource [removed: potential.] [added: 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. [removed: During the year ended December 31, 2018, we completed multiple acquisitions in the Midland Basin through our acquisitions of Ajax, ExL and EnergyQuest, as well as Energen. As a result, our Midland Basin acreage footprint increased from approximately 101,941 net acres to approximately 194,661 net acres as of December 31, 2018, with our Delaware Basin acreage increasing from approximately 104,719 net acres to approximately 170,205 net acres over the same period.] |

| [removed: •] [added: •] | [removed: Maintain] [added: Maintain] financial [removed: flexibility.] [added: flexibility.] We seek to maintain a conservative financial position. [removed: In connection with our fall 2018 borrowing base redetermination,] [added: As of December 31, 2019,] our borrowing base was set at [removed: $2.65 billion,] [added: $2.0 billion] and we [removed: elected a commitment amount of $2.0 billion, of which $0.5] [added: had $1.99] billion [removed: was] available for [removed: borrowing as] [added: borrowing. As] of December 31, [removed: 2018.] [added: 2019, Viper LLC had $97 million in outstanding borrowings, and $678 million available for borrowing, under its revolving credit facility.] As of December 31, [removed: 2018, Viper] [added: 2019, Rattler LLC] had [removed: $411.0] [added: $424] million in outstanding borrowings, and [removed: $144.0] [added: $176] million available for borrowing, under its revolving credit facility. |

[removed: Our Strengths][added: Our Strengths]

| [removed: •] [added: •] | [removed: Oil] [added: Oil] rich resource base in one of North America’s leading resource [removed: plays.] [added: 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, [removed: 2018] [added: 2019] was approximately [removed: 72%] [added: 66%] oil, [removed: 16%] [added: 18%] natural gas liquids and [removed: 12%] [added: 16%] natural gas. As of December 31, [removed: 2018,] [added: 2019,] our [removed: estimated net proved reserves were comprised of approximately 63% oil, 18% natural gas liquids and 19% natural gas.] |

| • | [removed: Multi-year] [added: Multi-year] drilling inventory in one of North America’s leading oil resource [removed: plays.] [added: 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 [removed: 11,868] [added: 12,310] gross [removed: (7,633] [added: (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 [removed: 7,200] [added: 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. [removed: Of these 11,868 locations, 6,479 are in the Midland Basin and 5,389 are in the Delaware Basin. In the Midland Basin, 2,465 are in the Lower Spraberry or Wolfcamp B horizons where we have drilled a large number of wells, 2,200 are in the Wolfcamp A or Middle Spraberry horizons where we have drilled a limited number of wells and 1,814 are in the Clearfork, Jo Mill or Cline horizons where we have drilled very few wells. Our current location count for the Lower Spraberry horizon is based on 660 foot to 880 foot spacing in Midland, Martin, northeast Andrews, Howard and Glasscock counties, depending on the prospect area and 880 foot spacing in all other counties. For the Wolfcamp B horizon, the horizontal location count is based on 660 foot to 880 foot spacing between wells in Midland, Martin, northeast Andrews, Howard, and Glasscock counties, and 880 foot spacing in all other counties. In the Wolfcamp A horizon, the horizontal location count in based on 660 foot to 880 foot spacing in Midland, Howard and Glasscock counties, 880 foot spacing in southwest Martin county and 1,320 foot spacing in other counties.] The [removed: horizontal location count for the Middle Spraberry is based on 880 foot spacing in Midland, Martin and northeast Andrews counties and 1,320 foot spacing in other counties. In the Cline and Clearfork and Jo Mill horizons, the horizontal location count is based on 880 foot to 1,320 foot spacing. In the Delaware Basin, 2,219 locations are in the Wolfcamp A or Wolfcamp B horizons, and 1,789 locations are in the 2nd Bone Spring or 3rd Bone Spring horizon and 1,381 locations are in other horizons including the Brushy Canyon, Avalon, 1st Bone Spring and Wolfcamp C. The horizontal location counts are based on 880 foot spacing in the Wolfcamp A and Wolfcamp B horizons, and 1,320 foot spacing in the Bone Spring horizons. The] ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count. In addition, we have approximately [removed: 2,617] [added: 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. |

| • | [removed: Experienced,] [added: Experienced,] incentivized and proven management [removed: team.] [added: 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 [added: 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.] |

| [removed: •] [added: •] | [removed: Favorable] [added: Favorable] operating [removed: environment.] [added: 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. |

| • | [removed: High] [added: High] degree of operational [removed: control.] [added: control.] We are the operator of approximately [removed: 89%] [added: 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. |

[removed: Our Properties][added: Our Properties]

[removed: Location] [added: Location] and [removed: Land][added: Land]

Our total acreage position in the Permian Basin was approximately [removed: 604,367] [added: 455,378] gross [removed: (461,218] [added: (382,337] net) acres, which consisted primarily of approximately [removed: 231,100] [added: 218,138] gross [removed: (194,661] [added: (195,461] net) acres in the Midland Basin and approximately [removed: 232,143] [added: 196,171] gross [removed: (170,205] [added: (155,296] net) acres in the Delaware Basin at December 31, [removed: 2018.][added: 2019.]

We are the operator of approximately [removed: 89%] [added: 97%] of this Permian Basin acreage.

In addition, [removed: we, through] our [added: publicly traded] subsidiary [removed: Viper, own] [added: Viper owns] mineral interests underlying approximately [removed: 532,295] [added: 814,224] gross acres and [removed: 14,841] [added: 24,304] net royalty acres in the Permian Basin and Eagle Ford Shale.

Approximately [removed: 37%] [added: 50%] of these net royalty acres are operated by us.

[removed: Area History][added: Area History]

As of December 31, [removed: 2018,] [added: 2019,] we held working interests in [removed: 7,279] [added: 2,656] gross [removed: (4,678] [added: (2,202] net) producing wells and only royalty interests in [removed: 2,645] [added: 4,161] additional wells.

[removed: Geology][added: Geology]

The [added: Greater] Permian Basin formed as an area of rapid Pennsylvanian-Permian subsidence in response to dynamic structural [removed: influence.][added: influence of the Marathon Uplift and Ancestral Rockies.]

It is one of the [removed: largest] [added: most productive] sedimentary basins in the U.S., with established oil and gas production from several [added: stacked] reservoirs [removed: from] [added: of varying age ranges, most notably] Permian [removed: through Ordovician in age.][added: aged sediments.]

The Spraberry/Bone Spring was deposited as siliciclastic [added: and carbonate] turbidites [added: and debris flows along with pelagic mudstones] in a [removed: deep water submarine fan] [added: deep-water, basinal] environment, while the Wolfcamp reservoirs consist of [removed: debris-flow and] [added: debris-flow,] grain-flow [added: and fine-grained pelagic] sediments, which were also deposited in a [removed: submarine fan] [added: basinal] setting.

The best carbonate reservoirs within the Wolfcamp [added: and Spraberry/Bone Spring] are generally found in [added: close] proximity to the Central Basin Platform, while [removed: the shale] [added: mudstone] reservoirs [removed: within the Wolfcamp] thicken [removed: basinward] [added: basin-ward,] away from the Central Basin Platform.

[removed: Both the Spraberry/Bone Spring and Wolfcamp contain organic-rich mudstones and shales which,] [added: The mudstone within these reservoirs is organically rich, which] when buried to sufficient depth for [added: thermal] maturation, became the source of the hydrocarbons found both within the [removed: shales] [added: mudstones] themselves and in the [removed: more] [added: interbedded] conventional clastic and carbonate [removed: reservoirs between the shales.][added: reservoirs.]

We have successfully developed several [removed: shale] [added: hybrid reservoir] intervals within the Clearfork, Spraberry/Bone [removed: Spring and] [added: Spring,] Wolfcamp [added: and Barnett/Meramec] formations since we began horizontal drilling in 2012.

The [removed: shales] [added: 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.

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.

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.

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.

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.

| Basin | Number of Horizontal Wells | |

| Midland | 1,125 | |

| Delaware | 645 | |

| 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.

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 lateral | 14 | |

| 10,000 foot lateral | 15 | |

| 13,000 foot lateral | 17 | |

| Delaware Basin | | |

| 7,500 foot lateral | 20 | |

| 10,000 foot lateral | 25 | |

| 13,000 foot lateral | 27 | |

Further advances in drilling and completion technology may result in economic development of zones that are not currently viable.

estimated net proved reserves were comprised of approximately 63% oil, 20% natural gas liquids and 17% natural gas.

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 |

| Other | 2,237 |

Merger with Energen Corporation and Other Significant 2018 Transactions

Merger with Energen Corporation

On November 29, 2018, we completed our acquisition of Energen Corporation, or Energen, in an all-stock transaction, which we refer to as the merger.

The addition of Energen’s assets increased our assets to: (i) over 273,000 net Tier One acres in the Permian Basin, an increase of 57% from third quarter 2018 Tier One acreage of approximately 174,000 net acres, (ii) over 7,200 estimated total net horizontal Permian locations, an increase of over 120% from third quarter 2018 estimated net locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins.

Ajax Resources, LLC

On October 31, 2018, we acquired certain leasehold interests and related assets of Ajax Resources, LLC, which we refer to as Ajax, which acquisition included approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of our common stock, which we refer to as the Ajax acquisition.

The Ajax acquisition was effective as of July 1, 2018.

ExL Petroleum Management, LLC and EnergyQuest II LLC Acquisition

On October 31, 2018, we acquired certain leasehold interests and related assets of ExL Petroleum Management, LLC, ExL Petroleum Operating, Inc. and EnergyQuest II LLC, which included an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin, for a total of $312.5 million in cash, subject to certain adjustments.

These acquisitions, which we collectively refer to as the ExL acquisition, were effective as of August 1, 2018.

On August 15, 2018, we sold 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 us, for $175.0 million, which we refer to as the Drop-down Transaction.

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.

The term “Wolfberry” was coined initially to indicate commingled production from the Permian Spraberry, Dean and Wolfcamp formations.

Time equivalent in the Delaware Basin, the “Wolfbone” play describes vertically commingled production from the Permian Bone Spring and Wolfcamp formations.

The Wolfberry and Wolfbone are unconventional “basin-centered oil” resource plays, in the sense that there is no regional downdip oil/water contact.

| Revisions | 338 | |

The increase in proved undeveloped reserves was primarily attributable to purchases of 165,426 MBOE mostly from the acquisition of Energen.

Upward revisions of 338 MBOE resulted from commodity price improvement and type curve performance.

| | | | | | | | | | | | |

| Combined volumes (MBOE) | 47,610 | | | | 28,917 | | | | 15,749 | | |

| Daily combined volumes (BOE/d) | 130,439 | | | | 79,224 | | | | 43,031 | | |

| Conventional Permian | 103,155 | | | 70,410 | | | 14,795 | | | 4,178 | | | 117,950 | | | 74,588 | |

| Delaware | 127,819 | | | 90,554 | | | 104,324 | | | 79,651 | | | 232,143 | | | 170,205 | |

| Exploration | — | | | — | | | 23,174 | | | 21,764 | | | 23,174 | | | 21,764 | |

| Midland | 198,408 | | | 162,370 | | | 32,692 | | | 32,291 | | | 231,100 | | | 194,661 | |

| Total | 429,382 | | | 323,334 | | | 174,985 | | | 137,884 | | | 604,367 | | | 461,218 | |

| Delaware | 43,963 | | | 31,130 | | | 13,779 | | | 6,474 | | | 7,447 | | | 3,447 | | | — | | | — | | | — | | | — | |

| Exploration | — | | | — | | | 18,713 | | | 18,713 | | | 4,405 | | | 3,035 | | | — | | | — | | | — | | | — | |

| Midland | 9,246 | | | 6,406 | | | 4,443 | | | 2,503 | | | 172 | | | 385 | | | 308 | | | 254 | | | — | | | — | |

| Total | 53,209 | | | 37,536 | | | 36,935 | | | 27,690 | | | 12,024 | | | 6,867 | | | 308 | | | 254 | | | — | | | — | |

| | 2018 | | | | | | 2017 | | | | | | 2016 | | | | |

We were party to a five-year oil purchase agreement with Shell Trading (US) Company that expired on September 30, 2018.

Our delivery obligations during the pre-commencement terms range from 30,000 to 40,000 barrels per day and, during the full service term, our maximum delivery obligation is 50,000 barrels per day, determined based on the amount of crude petroleum we are obligated to transport on the EPIC Crude Pipeline under our transportation agreement with such pipeline.

During the full service term, the price per barrel of oil payable by Shell Trading (US) Company to us is subject to negotiation.

We have also entered into an oil purchase agreement with Vitol Inc., which we refer to as Vitol.

The agreement provides for different delivery obligations before and after the Gray Oak Pipeline is in full service, ranging from 23,750 barrels per day during the period from November 1, 2018 to September 30, 2019, to 50,000 barrels per day (up to a maximum of 100,000 barrels per day) once the Gray Oak Pipeline is in full service, determined based on the amount of crude petroleum we are obligated to transport on the Gray Oak Pipeline under our transportation agreement with such pipeline.

The agreement with Vitol provides for a seven-year term commencing on the date when the Gray Oak Pipeline is in full service.

The agreement contemplates variable prices depending on the delivery periods specified in the agreement.

The agreement also provides for a five-year term commencing on the date the EPIC Crude Pipeline is ready to perform transportation services from the EPIC Midway Terminal, during which we agreed to sell crude petroleum to Vitol opportunistically at negotiated prices.

While the [added: ultimate] outcome of the pending [removed: litigation,] [added: proceedings,] disputes or [removed: claims] [added: claims, and any resulting impact on us,] cannot be predicted with certainty, [removed: in the opinion of our management,] [added: we believe that] none of these matters, if [added: ultimately] decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

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.

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.

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities.

[removed: UNITED STATES][added: UNITED STATES]

[removed: SECURITIES] [added: SECURITIES] AND EXCHANGE [removed: COMMISSION][added: COMMISSION]

[removed: Washington,] [added: Washington,] D.C. [removed: 20549][added: 20549]

[removed: FORM 10-K][added: FORM 10-K]

| [removed: ý] [added: ☒] | [removed: ANNUAL] [added: ANNUAL] REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF [removed: 1934] [added: 1934] |

[removed: For] [added: For] the fiscal year [removed: ended December] [added: ended December] 31, [removed: 2018][added: 2019]

| [removed: ¨] [added: ☐] | [removed: TRANSITION] [added: TRANSITION] REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF [removed: 1934] [added: 1934] |

[removed: Commission] [added: Commission] File [removed: Number 001-35700][added: Number 001-35700]

[removed: Diamondback] [added: Diamondback] Energy, [removed: Inc.][added: Inc.]

[removed: (Exact] [added: (Exact] Name of Registrant As Specified in Its [removed: Charter)][added: Charter)]

| [removed: Delaware] [added: DE] | | | [removed: 45-4502447] [added: 45-4502447] |

| [removed: (State] [added: (State] or Other Jurisdiction of Incorporation or [removed: Organization)] [added: Organization)] | | | [removed: (IRS] [added: (I.R.S.] Employer Identification [removed: Number)] [added: Number)] |

| [removed: 500] [added: 500] West [removed: Texas, Suite 1200 Midland, Texas] [added: Texas] | | | [removed: 79701] |

| [removed: (Address] [added: (Address] of [removed: Principal Executive Offices)] [added: principal executive offices)] | | | [removed: (Zip Code)] [added: (Zip code)] |

[removed: (Registrant] [added: (Registrant] Telephone Number, Including Area [removed: Code): (432) 221-7400][added: Code): (432) 221-7400]

| | | [removed: Securities] [added: Securities] registered pursuant to Section 12(b) of the [removed: Act:] [added: Act:] | | | | |

| | [removed: Title] [added: Title] of Each [removed: Class] [added: Class] | | [added: Trading Symbol(s)] | | [removed: Name] [added: Name] of Each Exchange on Which [removed: Registered] [added: Registered] | |

| | Common Stock, par value $0.01 per share | | [added: FANG] | | The Nasdaq Stock Market LLC | |

| | | [removed: Securities] [added: Securities] registered pursuant to Section 12(g) of the Act: [removed: None] [added: None] | | | | |

Yes [removed: ý] [added: ☒] No [removed: ¨][added: ☐]

Yes [removed: ¨] [added: ☐] No [removed: ý][added: ☒]

Yes [removed: ý] [added: ☒] No [removed: ¨][added: ☐]

Yes [removed: ý] [added: ☒] No [removed: ¨][added: ☐]

See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange [removed: Act.][added: Act:]

| Large Accelerated Filer | | [removed: ý] [added: ☒] | | Accelerated Filer | | [removed: ¨] [added: ☐] |

| Non-Accelerated Filer | | [removed: ¨] [added: ☐] | | Smaller Reporting Company | | [removed: ¨] [added: ☐] |

| | | | | Emerging Growth Company | | [removed: o] [added: ☐] |

Yes [removed: ¨] [added: ☐] No [removed: ý][added: ☒]

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June [removed: 29, 2018] [added: 28, 2019] was approximately [removed: $11,455,114,815.][added: $15.9 billion.]

As of February [removed: 15, 2019, 164,381,522] [added: 14, 2020, 158,284,486] shares of the registrant’s common stock were outstanding.

[removed: DOCUMENTS] [added: DOCUMENTS] INCORPORATED BY [removed: REFERENCE][added: REFERENCE]

Portions of Diamondback Energy, Inc.’s Proxy Statement for the [removed: 2019] [added: 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

[removed: DIAMONDBACK] [added: DIAMONDBACK] ENERGY, [removed: INC.][added: INC.]

[removed: FORM 10-K][added: FORM 10-K]

[removed: FOR] [added: FOR] THE YEAR [removed: ENDED DECEMBER] [added: ENDED DECEMBER] 31, [removed: 2018][added: 2019]

[removed: TABLE] [added: TABLE] OF [removed: CONTENTS][added: CONTENTS]

[removed: | [Glossary of Oil and Natural Gas Terms](#s0B79EFBDB32854DD964BE300A4BD633B) | [ii](#s0B79EFBDB32854DD964BE300A4BD633B) |][added: GLOSSARY OF OIL AND NATURAL GAS TERMS]

[removed: | [Glossary of Certain Other Terms](#sB18A0B55FB6C51B79BA8F7C220E3C75A) | [v](#sB18A0B55FB6C51B79BA8F7C220E3C75A) |][added: GLOSSARY OF CERTAIN OTHER TERMS]

[removed: | [Cautionary Statement Regarding Forward-Looking Statements](#sEAD8D3874A265D2E8044B93FC151AC71) | [vi](#sEAD8D3874A265D2E8044B93FC151AC71) |][added: CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS]

| [removed: PART I] [added: PART I] | |

OR

| Suite 1200 | | | |

| Midland, | TX | | 79701 |

| | | | | | (NASDAQ Global Select Market) | |

| [Signatures](#s42409549FF1D522C94C4A777C86E04CF) | [S-1](#s42409549FF1D522C94C4A777C86E04CF) |

| WTI MEH | West Texas Intermediate Magellan East Houston. |

| WTL | West Texas Light |

| ASU | Accounting Standards Update |

| Dodd-Frank Act | Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173). |

| FASB | Financial Accounting Standards Board |

| December 2019 Notes Indenture | The 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. |

| Rattler | Rattler Midstream LP, a Delaware limited partnership. |

| Rattler’s general partner | Rattler Midstream GP LLC, a Delaware limited liability company; the general partner of Rattler Midstream LP and a wholly-owned subsidiary of the Company. |

| Rattler LLC | Rattler Midstream Operating LLC, a Delaware limited liability company and a subsidiary of Rattler. |

| Rattler LTIP | Rattler Midstream LP Long-Term Incentive Plan. |

| Rattler Offering | Rattler’s initial public offering. |

| Rattler’s Partnership Agreement | The first amended and restated agreement of limited partnership, dated May 28, 2019. |

| December 2019 Notes | The 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. |

| Wexford | Wexford Capital LP |

| • | competition in the oil and natural gas industry; |

| • | acquisitions; |

| • | our recently completed drop-down transaction with our subsidiary Viper Energy Partners LP, or Viper; |

| • | the impact of reduced drilling activity; |

| • | regional supply and demand factors, delays or interruptions of production; |

| | |

| --- | --- |

| | |

| --- | --- |

| | |

| --- | --- |

| • | 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 |

| | |

| --- | --- |

vii

10-K 1 diamondback201810-k.htm DIAMONDBACK 10-K

OR

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

| [Signatures](#s8DD39508132453AE9AB9FC1BE65666D9) | [S-1](#s8DD39508132453AE9AB9FC1BE65666D9) |

| Stratigraphic play | An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process. |

| Structural play | An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata. |

| Bison | Bison Drilling and Field Services, LLC. |

| Viper | Viper Energy Partners L.P. |

In particular, the factors discussed in this Annual Report on Form 10–K, including under Part I, Item 1A.

| • | acquisitions, including our recent acquisition of certain leasehold acres and other assets from Ajax Resources, LLC and our recent acquisition of Energen Corporation discussed elsewhere in this report; |

| • | our ability to achieve the anticipated synergies, operational efficiencies and returns from our recent acquisition of Energen Corporation; |

[removed: PART II][added: PART II]

[added: Listing and] Holders of [removed: Record][added: Record]

There were 20 holders of record of our common stock on February [removed: 15, 2019.][added: 13, 2020.]

[removed: Dividend Policy][added: Dividend Policy]

[removed: Repurchases] [added: Repurchases] of Equity [removed: Securities][added: Securities]

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.

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. |

Price Range of Common Stock

The following table sets forth the range of high and low sales prices of our common stock and dividends payable per share of our common stock for the periods presented:

| | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | | | | |

| | High | | | | Low | | | | Cash Dividends per Share of Common Stock | | |

| 2018 | | | | | | | | | | | |

| 1st Quarter | $ | 134.60 | | | $ | 105.66 | | | $ | 0.125 | |

| 2nd Quarter | $ | 138.14 | | | $ | 107.78 | | | $ | 0.125 | |

| 3rd Quarter | $ | 138.25 | | | $ | 111.31 | | | $ | 0.125 | |

| 4th Quarter(2) | $ | 140.78 | | | $ | 85.19 | | | $ | 0.125 | |

| 2017 | | | | | | | | | | | |

| 1st Quarter | $ | 114.00 | | | $ | 96.05 | | | $ | — | |

| 2nd Quarter | $ | 108.17 | | | $ | 83.22 | | | $ | — | |

| 3rd Quarter | $ | 98.36 | | | $ | 82.77 | | | $ | — | |

| 4th Quarter | $ | 127.45 | | | $ | 95.69 | | | $ | — | |

| (1) | The Q4 2018 distribution is payable on February 28, 2918 to unitholders of record at the close of business on February 21, 2019. |

We have not paid any cash dividends since our inception.

Covenants contained in our revolving credit facility restrict the payment of cash dividends on our common stock.

See Item 1A.

“Risk Factors–Risks Related to the Oil and Natural Gas Industry and Our Business–Our revolving credit facility contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.” and Item 7.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations–Liquidity and Capital Resources–Credit Facility.”

Recent Sales of Unregistered Securities

On October 31, 2018, we issued approximately 2.6 million shares of our common stock to Ajax and certain other holders as part of the consideration for the Ajax acquisition.

These shares were issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act, as sales by an issuer not involving any public offering.

In connection with the closing of the Ajax acquisition on October 31, 2018, we entered into a registration rights agreement with Ajax and certain other holders of our common stock pursuant to which we filed a shelf registration statement with the SEC to facilitate the resale of common stock issued in the Ajax acquisition.

The shelf registration statement became automatically effective on November 30, 2018.

Pursuant to this registration rights agreement, we also agreed to provide certain demand and piggyback registration rights to such holders.

None.

The historical financial data for the years ended December 31, [removed: 2018, 2017] [added: 2019, 2018] and [removed: 2016] [added: 2017] and the balance sheet data as of December 31, [removed: 2018] [added: 2019] and [removed: 2017] [added: 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, [removed: 2015] [added: 2016] and [removed: 2014] [added: 2015] and the balance sheet data as of December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014] [added: 2015] are derived from our audited financial statements not included in this Annual Report on Form 10-K.

| | [removed: Year] [added: Year] Ended December [removed: 31,] [added: 31,] | | | | | | | | | | | | | | | | | | |

| [removed: (In thousands,] [added: (In millions,] except per share [removed: amounts)] [added: amounts, shares in thousands)] | [removed: 2018(1)] [added: 2019] | | | | [removed: 2017] [added: 2018(1)] | | | | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | |

| [removed: Statements] [added: Statements] of Operations [removed: Data:] [added: Data:] | | | | | | | | | | | | | | | | | | | |

| Total costs and expenses | [removed: 1,165,468] [added: 3,269] | | | | [removed: 600,091] [added: 1,165] | | | | [removed: 595,724] [added: 600] | | | | [removed: 1,187,002] [added: 596] | | | | [removed: 283,048] [added: 1,187] | | |

| Income (loss) from operations | [removed: 1,010,788] [added: 695] | | | | [removed: 605,020] [added: 1,011] | | | | [removed: (68,617] [added: 605] | | [removed: )] | | [removed: (740,269] [added: (69] | | ) | | [removed: 212,670] [added: (740] | | [added: )] |

| Income (loss) before income taxes | [removed: 1,113,257] [added: 362] | | | | [removed: 497,189] [added: 1,113] | | | | [removed: (164,716] [added: 497] | | [removed: )] | | [removed: (749,100] [added: (165] | | ) | | [removed: 304,956] [added: (749] | | [added: )] |

| Provision for (benefit from) income taxes | [removed: 168,362] [added: 47] | | | | [removed: (19,568] [added: 168] | | [removed: )] | | [removed: 192] [added: (20] | | [added: )] | | [removed: (201,310] [added: —] | | [removed: )] | | [removed: 108,985] [added: (201] | | [added: )] |

| Less: Net income attributable to non-controlling interest | [removed: 99,223] [added: 75] | | | | [removed: 34,496] [added: 99] | | | | [removed: 126] [added: 35] | | | | [removed: 2,838] [added: —] | | | | [removed: 2,216] [added: 3] | | |

| Net income (loss) attributable to Diamondback Energy, Inc. | $ | [removed: 845,672] [added: 240] | | | $ | [removed: 482,261] [added: 846] | | | $ | [removed: (165,034] [added: 482] | [removed: )] | | $ | [removed: (550,628] [added: (165] | ) | | $ | [removed: 193,755] [added: (551] | [added: )] |

| Earnings per common [removed: share] [added: share:] | | | | | | | | | | | | | | | | | | | |

| Basic | $ | [removed: 8.09] [added: 1.47] | | | $ | [removed: 4.95] [added: 8.09] | | | $ | [removed: (2.20] [added: 4.95] | [removed: )] | | $ | [removed: (8.74] [added: (2.20] | ) | | $ | [removed: 3.67] [added: (8.74] | [added: )] |

| Diluted | $ | [removed: 8.06] [added: 1.47] | | | $ | [removed: 4.94] [added: 8.06] | | | $ | [removed: (2.20] [added: 4.94] | [removed: )] | | $ | [removed: (8.74] [added: (2.20] | ) | | $ | [removed: 3.64] [added: (8.74] | [added: )] |

| Weighted average common shares [removed: outstanding] [added: outstanding:] | | | | | | | | | | | | | | | | | | | |

| Basic | [removed: 104,622] [added: 163,493] | | | | [removed: 97,458] [added: 104,622] | | | | [removed: 75,077] [added: 97,458] | | | | [removed: 63,019] [added: 75,077] | | | | [removed: 52,826] [added: 63,019] | | |

| Diluted | [removed: 104,929] [added: 163,843] | | | | [removed: 97,688] [added: 104,929] | | | | [removed: 75,077] [added: 97,688] | | | | [removed: 63,019] [added: 75,077] | | | | [removed: 53,297] [added: 63,019] | | |

| Cash dividends declared per common share | $ | [removed: 0.500] [added: 0.9375] | | | $ | [removed: —] [added: 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 [added: Energen] merger, through December 31, 2018. |

| | [removed: As] [added: As] of December [removed: 31,] [added: 31,] | | | | | | | | | | | | | | | | | | |

| [removed: (In thousands)] [added: (In millions)] | [removed: 2018] [added: 2019] | | | | [removed: 2017] [added: 2018] | | | | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | |

| [removed: Balance] [added: Balance] Sheet [removed: Data:] [added: Data:] | | | | | | | | | | | | | | | | | | | |

| Current liabilities | [removed: 1,019,612] [added: 1,263] | | | | [removed: 577,428] [added: 1,019] | | | | [removed: 209,342] [added: 577] | | | | [removed: 141,421] [added: 209] | | | | [removed: 266,729] [added: 141] | | |

| | [removed: Year] [added: Year] Ended December [removed: 31,] [added: 31,] | | | | | | | | | | | | | | | | | | |

| [removed: (In thousands)] [added: (In millions)] | [removed: 2018] [added: 2019] | | | | [removed: 2017] [added: 2018] | | | | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | |

| [removed: Other] [added: Other] Financial [removed: Data:] [added: Data:] | | | | | | | | | | | | | | | | | | | |

| Net cash used in investing activities | [removed: (3,503,043] [added: $] | [added: (3,888] | ) | | [removed: (3,132,282] [added: $] | [added: (3,503] | ) | | [removed: (1,310,242] [added: $] | [added: (3,132] | ) | | [removed: (895,050] [added: $] | [added: (1,310] | ) | | [removed: (1,481,997] [added: $] | [added: (895] | ) |

| | [removed: Year] [added: Year] Ended December [removed: 31,] [added: 31,] | | | | | | | | | | | | | | | | | | |

| [removed: (In thousands)] [added: (In millions)] | [removed: 2018] [added: 2019] | | | | [removed: 2017] [added: 2018] | | | | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | |

| (1) | For the years ended December 31, [added: 2019,] 2018, 2017, [removed: 2016, 2015] [added: 2016] and [removed: 2014,] [added: 2015,] total stockholders’ equity excludes [removed: $467.0] [added: $738] million, [removed: $326.9] [added: $467] million, [removed: $320.8 million $233.0] [added: $327 million, $321] million and [removed: $234.2] [added: $233] million, respectively, of non-controlling interest related to Viper Energy Partners LP. [added: For the year ended December 31, 2019, total stockholders’ equity excludes $919 million of non-controlling interest related to Rattler Midstream LP.] |

[removed: Non-GAAP] [added: Non-GAAP] financial measure and [removed: reconciliation][added: reconciliation]

[removed: Consolidated] 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 [removed: Consolidated] 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, [added: (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.

[removed: Consolidated] Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP.

Management believes [removed: Consolidated] 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 [removed: Consolidated] 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.

[removed: Consolidated] 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 [removed: Consolidated] 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 [removed: Consolidated] Adjusted EBITDA.

Our computations of [removed: Consolidated] 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.

The following presents a reconciliation of the non-GAAP financial measure of [removed: Consolidated] Adjusted EBITDA to the GAAP financial measure of net income (loss):

| Total revenues | $ | 3,964 | | | $ | 2,176 | | | $ | 1,205 | | | $ | 527 | | | $ | 447 | |

| Other income (expense) | (333 | | ) | | 102 | | | | (108 | | ) | | (96 | | ) | | (9 | | ) |

| Net income (loss) | 315 | | | | 945 | | | | 517 | | | | (165 | | ) | | (548 | | ) |

| Cash and cash equivalents | $ | 123 | | | $ | 215 | | | $ | 112 | | | $ | 1,666 | | | $ | 20 | |

| Net property and equipment | 21,835 | | | | 20,372 | | | | 7,344 | | | | 3,391 | | | | 2,598 | | |

| Total assets | 23,531 | | | | 21,596 | | | | 7,771 | | | | 5,350 | | | | 2,751 | | |

| Long-term debt | 5,371 | | | | 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 | |

| Net cash provided by operating activities | $ | 2,734 | | | $ | 1,565 | | | $ | 889 | | | $ | 332 | | | $ | 417 | |

| Net cash provided by financing activities | $ | 1,062 | | | $ | 2,041 | | | $ | 689 | | | $ | 2,625 | | | $ | 468 | |

| Consolidated Adjusted EBITDA(2) | $ | 2,949 | | | $ | 1,538 | | | $ | 928 | | | $ | 388 | | | $ | 449 | |

| Net income (loss) | $ | 315 | | | $ | 945 | | | $ | 517 | | | $ | (165 | ) | | $ | (548 | ) |

| Non-cash loss (gain) on derivative instruments, net | 188 | | | | (222 | | ) | | 84 | | | | 27 | | | | 113 | | |

| Interest expense, net | 172 | | | | 87 | | | | 41 | | | | 41 | | | | 41 | | |

| Depreciation, depletion and amortization | 1,447 | | | | 623 | | | | 327 | | | | 178 | | | | 218 | | |

| Consolidated Adjusted EBITDA | 3,065 | | | | 1,667 | | | | 975 | | | | 387 | | | | 457 | | |

| Adjusted EBITDA attributable to Diamondback Energy, Inc. | $ | 2,949 | | | $ | 1,538 | | | $ | 928 | | | $ | 388 | | | $ | 449 | |

| Total revenues | $ | 2,176,256 | | | $ | 1,205,111 | | | $ | 527,107 | | | $ | 446,733 | | | $ | 495,718 | |

| Other income (expense) | 102,469 | | | | (107,831 | | ) | | (96,099 | | ) | | (8,831 | | ) | | 92,286 | | |

| Net income (loss) | 944,895 | | | | 516,757 | | | | (164,908 | | ) | | (547,790 | | ) | | 195,971 | | |

| Cash and cash equivalents | $ | 214,516 | | | $ | 112,446 | | | $ | 1,666,574 | | | $ | 20,115 | | | $ | 30,183 | |

| Net property and equipment | 20,371,975 | | | | 7,343,617 | | | | 3,390,857 | | | | 2,597,625 | | | | 2,791,807 | | |

| Total assets | 21,595,687 | | | | 7,770,985 | | | | 5,349,680 | | | | 2,750,719 | | | | 3,095,481 | | |

| Long-term debt | 4,464,338 | | | | 1,477,347 | | | | 1,105,912 | | | | 487,807 | | | | 673,500 | | |

| Total stockholders’/ members’ equity(1) | 13,699,287 | | | | 5,254,860 | | | | 3,697,462 | | | | 1,875,972 | | | | 1,751,011 | | |

| Total equity | 14,166,262 | | | | 5,581,737 | | | | 4,018,292 | | | | 2,108,973 | | | | 1,985,213 | | |

| Net cash provided by operating activities | $ | 1,564,505 | | | $ | 888,625 | | | $ | 332,080 | | | $ | 416,501 | | | $ | 356,389 | |

| Net cash provided by financing activities | 2,040,608 | | | | 689,529 | | | | 2,624,621 | | | | 468,481 | | | | 1,140,236 | | |

| Consolidated Adjusted EBITDA(2) | $ | 1,539,031 | | | $ | 928,039 | | | $ | 387,535 | | | $ | 449,245 | | | $ | 398,334 | |

| Net income (loss) | $ | 944,895 | | | $ | 516,757 | | | $ | (164,908 | ) | | $ | (547,790 | ) | | $ | 195,971 | |

| Non-cash loss (gain) on derivative instruments, net | (221,732 | | ) | | 84,240 | | | | 26,522 | | | | 112,918 | | | | (117,109 | | ) |

| Interest expense, net | 87,276 | | | | 40,554 | | | | 40,684 | | | | 41,510 | | | | 34,515 | | |

| Depreciation, depletion and amortization | 623,039 | | | | 326,759 | | | | 178,015 | | | | 217,697 | | | | 170,005 | | |

| Consolidated Adjusted EBITDA | $ | 1,539,031 | | | $ | 928,039 | | | $ | 387,535 | | | $ | 449,245 | | | $ | 398,334 | |

[removed: Evaluation] [added: Evaluation] of Disclosure Control and [removed: Procedures][added: Procedures]

As of December 31, [removed: 2018,] [added: 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, [removed: 2018,] [added: 2019,] our disclosure controls and procedures are effective.

[removed: Changes] [added: Changes] in Internal Control over Financial [removed: Reporting][added: Reporting]

[removed: Except as noted above, there were no] [added: There have not been any] changes in our internal control over financial reporting that occurred during the [removed: fourth] quarter [removed: of 2018] [added: ended December 31, 2019] that have materially affected, or are reasonably likely to materially affect, [removed: our] internal [removed: control] [added: controls] over financial reporting.

[removed: MANAGEMENT’S] [added: MANAGEMENT’S] REPORT ON INTERNAL CONTROL OVER FINANCIAL [removed: REPORTING][added: REPORTING]

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, [removed: 2018.][added: 2019.]

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, [removed: 2018.][added: 2019.]

The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, [removed: 2018,] [added: 2019,] is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

[removed: REPORT] [added: REPORT] OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING [removed: FIRM][added: FIRM]

[removed: Opinion] [added: Opinion] on internal control over financial [removed: reporting][added: 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, [removed: 2018,] [added: 2019,] based on criteria established in the 2013 [removed: Internal] [added: *Internal] Control-Integrated [removed: Framework] [added: 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, [removed: 2018,] [added: 2019,] based on the criteria established in the 2013 [removed: Internal] [added: *Internal] Control-Integrated [removed: Framework] [added: 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, [removed: 2018,] [added: 2019,] and our report dated February [removed: 22, 2019] [added: 26, 2020] expressed an unqualified opinion on those financial statements.

[removed: Basis] [added: Basis] for [removed: opinion][added: opinion]

[removed: Definition] [added: Definition] and limitations of internal control over financial [removed: reporting][added: reporting]

February 26, 2020

As noted under “Management’s Report on Internal Control over Financial Reporting,” management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the merger with Energen on November 29, 2018.

Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company.

The Company is in the process of integrating Energen’s and our internal controls over financial reporting.

As a result of these integration activities, certain controls will be evaluated and may be changed.

Management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the merger with Energen on November 29, 2018.

Energen’s total assets and total operating revenue represented approximately 47% of the Company’s consolidated total assets at December 31, 2018 and 4.7% of the Company’s consolidated total operating revenue for the year ended December 31, 2018.

Our audit of, and opinion on, the Company’s internal control over financial reporting does not include the internal control over financial reporting of Energen Corporation, a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 47.0 and 4.7 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2018.

As indicated in Management’s Report, Energen Corporation was acquired during 2018.

Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of Energen Corporation.

February 22, 2019

[removed: PART III][added: PART III]

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.

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.