Diamondback Energy (FANG) 10-K risk factor changes: FY2020 vs FY2019

“Business and [removed: Properties” and] [added: Properties,”] Item [removed: 7A.][added: 7.]

We could also face additional risks and uncertainties not currently known to [removed: the Company] [added: us] or that we currently deem to be immaterial.

During [removed: 2019,] [added: 2020, NYMEX] WTI [removed: Futures Contract 1] prices ranged from [removed: $46.54] [added: $(37.63)] to [removed: $66.30] [added: $63.27] per Bbl and the [removed: Natural Gas Futures Contract 1 spot market] [added: NYMEX Henry Hub] price of natural gas ranged from [removed: $2.07] [added: $1.48] to [removed: $3.59] [added: $3.35] per MMBtu.

If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to [removed: write down,] [added: write-down,] as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.

[added: 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.

In [removed: 2019,] [added: 2020,] our total capital expenditures, including expenditures for [removed: leasehold acquisitions, drilling] [added: drilling, infrastructure] and [removed: infrastructure,] [added: additions to midstream assets,] were approximately [removed: $3.1] [added: $1.9] billion.

Our [removed: 2020] [added: 2021] capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately [removed: $2.8] [added: $1.4] billion to [removed: $3.0] [added: $1.6] billion, representing [removed: an increase] [added: a decrease] of [removed: 1% over] [added: 50% from] our [removed: 2019] [added: 2020] capital budget.

We intend to finance our future capital expenditures [added: for our drilling operations] with cash flow from operations, [added: while future acquisitions may also be funded from operations as well as] proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility.

Further, our actual capital expenditures in [removed: 2020] [added: 2021] 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 [added: financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means.]

The accuracy of these assessments is inherently [removed: uncertain] [added: uncertain,] and we may not be able to identify attractive acquisition opportunities.

[removed: Further,] [added: If] these acquisitions [removed: may be in] [added: include] geographic regions in which we do not currently operate, [removed: which could result] [added: as] in [added: the case of the pending merger with QEP, we could be subject to] unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities.

The inability to effectively manage the integration of acquisitions, including our [removed: recently completed and] pending acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth.

[removed: Acquiring oil and natural gas] [added: The successful acquisition of producing] properties requires [removed: us to assess reservoir and infrastructure characteristics, including] [added: an assessment of several factors, including;] recoverable reserves, [removed: development] [added: future oil] and [added: natural gas prices and their applicable differentials,] operating [removed: costs] [added: costs,] and potential environmental and other liabilities.

At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately [removed: 12,310] [added: 10,413] gross [removed: (8,141] [added: (6,863] net) identified economic potential horizontal drilling locations in multiple horizons on our acreage.

As of December 31, [removed: 2019,] [added: 2020,] only [removed: 477] [added: 628] of our gross identified potential horizontal drilling locations were attributed to proved reserves.

In addition, we have identified approximately [removed: 3,382] [added: 2,708] 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 [added: completion costs or to be economically viable.]

Through December 31, [removed: 2019,] [added: 2020,] we are the operator of, have participated in, or have acquired [added: working interest in] a total of [removed: 1,770] [added: 2,380] 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.

Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our [removed: quarterly] operating results.

In addition, in order to hold our current leases expiring in [removed: 2020,] [added: 2021,] we will need to operate at least a one-rig program.

Although we have hedged a portion of our estimated [removed: 2020 and] 2021 [added: and 2022] production, we may still be adversely affected by continuing and prolonged declines in the price of [removed: oil.][added: oil and may be exposed to other risks, including counterparty credit risk.]

We use [removed: fixed price swap contracts, fixed] [added: commodity] price [removed: basis swap contracts, double-up swap contracts and three-way collars with corresponding put, short put and call options] [added: derivatives] to reduce price volatility associated with certain of our oil and natural gas sales.

For additional information regarding our outstanding derivative contracts as of December 31, [removed: 2019,] [added: 2020,] see Note [removed: 15—Derivatives] [added: 15—[Derivatives](#i4b770a66acfe418cb1b377f3d113fa9f_208)] to our consolidated financial statements included elsewhere in this report.

We are a party to long-term crude oil agreements [removed: with Trafigura, Plains, Shell and Vitol] under which, subject to certain terms and conditions, we are obligated to deliver specified quantities of oil to such companies.

Our maximum delivery obligation under these agreements varies for different periods and depends in some cases upon certain [removed: conditions, such as the in-service dates for the Gray Oak pipeline and the EPIC pipeline as described in this report.][added: conditions beyond our control.]

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately [removed: $186] [added: $56] million at December 31, [removed: 2019)] [added: 2020)] and receivables from purchasers of our oil and natural gas production (approximately [removed: $429] [added: $281] million at December 31, [removed: 2019).][added: 2020).]

For [added: each of] the [removed: year] [added: years] ended December 31, [removed: 2019,] [added: 2019 and 2018,] three purchasers each accounted for more than 10% of our [removed: revenue: Shell (27%); Plains (23%); and Vitol (15%).][added: revenue.]

For [added: each of] the [removed: year] [added: years] ended December 31, [added: 2019 and] 2018, three purchasers each accounted for more than 10% of our [removed: revenue: Shell (26%); Koch (15%); and Occidental Energy Marketing Inc. (11%).][added: revenue.]

For the year ended December 31, [removed: 2017, three] [added: 2020, four] purchasers each accounted for more than 10% of our [removed: revenue: Shell (31%); Koch (19%); and Enterprise Crude Oil LLC (11%).][added: revenue.]

The average depletion rate per barrel equivalent unit of production was [removed: $13.54, $12.62] [added: $11.30, $13.54] and [removed: $11.11] [added: $12.62] for the years ended December 31, [removed: 2019, 2018] [added: 2020, 2019] and [removed: 2017,] [added: 2018,] respectively.

[removed: Depreciation, depletion and amortization expense] [added: Depletion] for oil and natural gas properties for the years ended December 31, [removed: 2019, 2018] [added: 2020, 2019] and [removed: 2017] [added: 2018] was [removed: $1.4] [added: $1.2] billion, [removed: $595 million] [added: $1.4 billion] and [removed: $321] [added: $595] million, respectively.

[added: To the extent capitalized costs of] evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense.

[removed: Beginning December 31, 2009, we have used] [added: We use] the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.

An impairment on proved oil and natural gas properties of [added: $6.0 billion and] $790 million was recorded for the [removed: year] [added: years] ended December 31, [removed: 2019.][added: 2020 and 2019, respectively.]

No impairments on proved oil and natural gas properties were recorded for the [removed: years] [added: year] ended December 31, [removed: 2018 and 2017.][added: 2018.]

Our estimated [removed: reserves and EURs are] [added: reserves and EURs are] based on many assumptions that may turn out to be inaccurate.

Approximately [removed: 33%] [added: 38%] of our total estimated proved reserves as of December 31, [removed: 2019,] [added: 2020,] were proved undeveloped reserves and may not be ultimately developed or produced.

[removed: All of our] [added: Our] producing properties are currently geographically concentrated in the Permian Basin of West Texas.

As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas [removed: liquids.][added: liquids and extreme weather conditions, such as the recent severe winter storms in the Permian Basin, and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities.]

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A.

Risks Relating to the Pending Merger

The pending merger may not be completed and the merger agreement may be terminated in accordance with its terms.

Failure to complete the pending merger could negatively impact the price of shares of our common stock and our future businesses and financial results.

The pending merger is subject to a number of conditions that must be satisfied, including the approval by QEP stockholders of the merger agreement proposal, or, to the extent permitted by applicable law, waived, in each case prior to the completion of the pending merger.

The conditions to the completion of the pending merger, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all, and, accordingly, the pending merger may be delayed or may not be completed.

In addition, if the pending merger is not completed by June 30, 2021, or, in certain instances, on or before September 30, 2021, either we or QEP may choose not to proceed with the pending merger by terminating the merger agreement, and the parties can mutually decide to terminate the merger agreement at any time, before or after stockholder approval.

Further, either we or QEP may elect to terminate the merger agreement in certain other circumstances specified in the merger agreement.

If the transactions contemplated by the merger agreement are not completed for any reason, our ongoing business, financial condition and financial results may be adversely affected.

Without realizing any of the benefits of having completed the transactions, we will be subject to a number of risks, including the following:

- we may be required to pay our costs relating to the transactions, which are substantial, such as legal, accounting, financial advisory and printing fees, whether or not the transactions are completed;

- time and resources committed by our management to matters relating to the transactions could otherwise have been devoted to pursuing other beneficial opportunities;

- we may experience negative reactions from financial markets, including negative impacts on the price of our common stock, including to the extent that the current market price reflects a market assumption that the transactions will be completed;

- we may experience negative reactions from employees, customers or vendors; and

- since the merger agreement restricts the conduct of our business prior to completion of the pending merger, we may not have been able to take certain actions during the pendency of the merger that would have benefitted us as an independent company and the opportunity to take such actions may no longer be available.

We will be subject to business uncertainties while the merger is pending, which could adversely affect our business.

Uncertainty about the effect of the pending merger on employees, industry contacts and business partners may have an adverse effect on us.

These uncertainties may impair our ability to attract, retain and motivate key personnel until the pending merger is completed and for a period of time thereafter and could cause industry contacts, business partners and others that deal with us to seek to change their existing business relationships with us.

In addition, the merger agreement restricts the parties to the merger agreement from entering into certain corporate transactions and taking other specified actions without the consent of the other party.

These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of the pending merger.

We will incur significant transaction and merger-related costs in connection with the pending merger, which may be in excess of those anticipated by us.

We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the pending merger, combining the operations of the two companies and achieving desired synergies.

These fees and costs have been, and will continue to be, substantial.

The substantial majority of non-recurring expenses will consist of transaction costs related to the pending merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees.

We will also incur transaction fees and costs related to the integration of the companies, which may be substantial.

Moreover, we may incur additional unanticipated expenses in connection with the pending merger and the integration, including costs associated with any stockholder litigation related to the pending merger.

Although we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, should allow us to offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all.

The costs described above, as well as other unanticipated costs and expenses, could have a material adverse effect on the financial condition and operating results of the combined company following the completion of the pending merger.

We and our subsidiaries will have substantial indebtedness after giving effect to the pending merger, which may limit our financial flexibility and adversely affect our financial results.

Under the merger agreement, QEP’s outstanding debt (other than its existing credit facility) will remain outstanding, which debt, as of December 31, 2020 was approximately $1.6 billion and consisted of amounts outstanding under QEP’s senior notes.

As of December 31, 2020, we had total long-term debt of approximately $5.6 billion, consisting primarily of the amounts outstanding under our revolving credit facility, our senior unsecured notes, the notes issued by our subsidiary Energen Corporation, the senior notes issued by our publicly traded subsidiaries, Viper and Rattler, and the amounts outstanding under Viper’s and Rattler’s revolving credit facilities.

Our pro forma indebtedness as of December 31, 2020, assuming consummation of the pending merger had occurred on such date and QEP’s senior notes remain outstanding, would have been approximately $7.4 billion, representing an increase in comparison to our indebtedness on a recent historical basis.

We believe that post-merger we will retain our investment grade credit ratings and retire the combined company’s pro forma debt at a faster rate than either company would have been able to do absent the pending merger.

However, any increase in our indebtedness could have adverse effects on our financial condition and results of operations, including:

We believe that the combined company will have flexibility to repay, refinance, repurchase, redeem, exchange or otherwise terminate large portions of our outstanding debt obligations.

However, there can be no guarantee that we would be able to execute such refinancings on favorable terms or at all, and a high level of indebtedness increases the risk that we may default on our debt obligations, including from the debt obligations of QEP.

Our future performance depends on many factors independent of the pending merger, some of which are beyond our control, such as general economic conditions and oil and natural gas prices.

Lawsuits have been filed against QEP, us, Merger Sub and the members of the QEP board in connection with the merger and additional lawsuits may be filed in the future.

An adverse ruling in any such lawsuit could result in an injunction preventing the completion of the merger and/or substantial costs to us and QEP.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements like the merger agreement.

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:

| | |

| --- | --- |

| • | the domestic and foreign supply of oil and natural gas; |

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

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

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

| • | the price and quantity of foreign imports; |

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

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

| • | speculative trading in crude oil and natural gas derivative contracts; |

| • | the level of consumer product demand; |

| • | weather conditions and other natural disasters; |

| • | risks associated with operating drilling rigs; |

| • | technological advances affecting energy consumption; |

| • | the price and availability of alternative fuels; |

| • | domestic and foreign governmental regulations and taxes; |

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

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

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

| • | overall domestic and global economic conditions. |

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

The Natural Gas Futures Contract 1 price spot market price of natural gas has ranged from a low of $1.64 per MMBtu in March 2016 to a high of $4.84 per MMBtu in November 2018.

On January 31, 2020, the WTI Futures Contract 1 posted price for crude oil was $51.56 per Bbl and the Natural Gas Futures Contract 1 spot market price of natural gas was $1.84 per MMBtu, representing decreases of 22% and 49%, respectively, from the high of $66.30 per Bbl of oil and $3.59 per MMBtu for natural gas during 2019.

In response to recent volatility in commodity prices, many producers have reduced their capital expenditure budgets.

Reductions in our

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

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations for the global economy.

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

These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, may precipitate an economic slowdown.

Concerns about global economic growth may have an adverse impact on global financial markets and commodity prices.

If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

Our cash flow from operations and access to capital are subject to a number of variables, including:

| • | our proved reserves; |

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

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

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

| • | our ability to borrow under our credit facility. |

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

*The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto appearing elsewhere in this Annual [removed: Report on Form 10–K.][added: Report.]

We operate in two [removed: business] [added: operating] segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves [added: primarily] 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.

As of December 31, [removed: 2019,] [added: 2020,] we had approximately [removed: 382,337] [added: 378,678] net acres, which primarily consisted of approximately [removed: 195,461] [added: 194,591] net acres in the Midland Basin and approximately [removed: 155,296] [added: 152,587] net acres in the Delaware Basin.

As of December 31, [removed: 2019,] [added: 2020,] we had an estimated [removed: 12,310] [added: 10,413] gross horizontal locations that we believe to be economic at $60.00 per Bbl [removed: West Texas Intermediate, or] WTI.

In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately [removed: 814,224] [added: 787,264] gross acres and [removed: 24,304] [added: 24,350] net royalty acres in the Permian Basin and Eagle Ford Shale.

Approximately [removed: 50%] [added: 52%] of these net royalty acres are operated by us.

Rattler’s gathering and disposal system spans approximately [removed: 474] [added: 517] 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.

[removed: 2019 Transactions] [added: 2020 Transactions] and Recent Developments

Fourth Quarter [removed: 2019 Dividend] [added: 2020 Dividend] Declaration and Increase

On February [removed: 14, 2020,] [added: 18, 2021,] our board of directors declared a cash dividend for the fourth quarter of [removed: 2019] [added: 2020] of [removed: $0.3750] [added: $0.40] per share of common stock, payable on March [removed: 10, 2020] [added: 11, 2021] to our stockholders of record at the close of business on March [removed: 3, 2020,] [added: 4, 2021,] representing [removed: an] [added: a 6.7%] increase [removed: of $0.1875] per share from the previously paid quarterly dividend.

During the year ended December 31, [removed: 2019, we] [added: 2020, Rattler] repurchased approximately [removed: $598] [added: $15] million of [added: its] common stock under [removed: our] [added: its] repurchase program.

[removed: Viper’s] [added: Rattler] Notes Offering

On [removed: October 16, 2019, Viper] [added: July 14, 2020, Rattler] completed an offering, which we refer to as the [removed: Viper] [added: Rattler] Notes Offering, of [removed: $500 million] [added: its 5.625% senior notes due 2025] in [added: the] aggregate principal amount of [removed: its 5.375% senior notes due 2027,] [added: $500 million,] which we refer to as the [removed: Viper] [added: Rattler] Notes.

[removed: Viper] [added: Rattler] received net proceeds of approximately $490 million from the [removed: Viper] [added: Rattler] Notes Offering.

[removed: Viper LLC used the] [added: Rattler received net] proceeds [added: of approximately $490 million] from the [removed: Viper] [added: Rattler] Notes Offering [added: and loaned the gross proceeds of the Rattler Notes Offering] to [added: Rattler LLC to] pay down borrowings under its revolving credit facility.

[removed: We are] [added: As of December 31, 2020, we were] operating [removed: 23] [added: eight] drilling rigs [removed: now including two rigs drilling produced water disposal wells] and currently intend to operate between [removed: 20] [added: eight] and [removed: 23] [added: 12] drilling rigs in [removed: 2020] [added: 2021] on average across our [removed: asset base] [added: current acreage position] in the Midland and Delaware Basins.

In [removed: 2020,] [added: 2021,] we expect to focus development on these areas.

To combat potential fluctuation in service costs, we have [removed: looked] [added: worked] to [removed: lock in pricing for dedicated activity levels] [added: implement new] and [added: more efficient drilling and completions methodologies and] will continue to seek opportunities to control additional well cost where possible.

Our [removed: 2020] [added: 2021] drilling and completion budget accounts for capital costs that we [removed: believe cover potential increases in our service costs] [added: expect to occur] during the year.

In [removed: 2020,] [added: 2021,] we remain focused on navigating our industry challenges by staying disciplined, improving our industry-leading cost structure, [removed: growing production,] [added: maintaining production and] increasing environmental [removed: transparency and returning more cash to our stockholders as evidenced by our quarterly dividend increase beginning with the fourth quarter of 2019.][added: transparency.]

[removed: 2020 Capital] [added: 2021 Capital] Budget

We have currently budgeted [removed: a 2020] [added: 2021] total capital spend of [removed: $2.8] [added: $1.4] billion to [removed: $3.0] [added: $1.6] billion, consisting of [removed: $2.45] [added: $1.2] billion to [removed: $2.6] [added: $1.4] billion for horizontal drilling and completions including non-operated activity, [removed: $200] [added: $60] million to [removed: $225] [added: $80] million for midstream investments, excluding joint venture investments, and [removed: $150] [added: $70] million to [removed: $175] [added: $90] million for infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

We expect to drill and complete [removed: 320] [added: 215] to [removed: 360] [added: 235] gross horizontal wells in [removed: 2020.][added: 2021.]

Should commodity prices [removed: weaken further or remain weak for an extended period of time,] [added: weaken,] we intend to act responsibly and, consistent with our prior practices, reduce capital spending.

If commodity prices strengthen, we intend to grow oil production within our [removed: 2020 budget] [added: 2021 budget, pay down indebtedness] and return cash to our [removed: stockholders or pay down indebtedness.][added: stockholders.]

| Natural gas (MMcf) | [removed: 1,118,811] | | [added: 20] | [removed: 1,048,649] | [added: %] | [added: | | | 16 | | % | | | | | | |]

| Natural gas liquids (MBbls) | [removed: 230,203] | | [added: 20] | [removed: 190,291] | [added: %] | [added: | | | 18 | | % | | | | | | |]

| Oil [removed: (per] [added: ($ per] Bbl) | [added: | |] $ | [removed: 51.88] [added: 36.41] | | | [added: | |] $ | [removed: 59.63] [added: 51.87] | | [added: | | | | | |]

| Natural gas [removed: (per] [added: ($ per] Mcf) | [added: | |] $ | [removed: 0.18] [added: 0.82] | | | [added: | |] $ | [removed: 1.47] [added: 0.68] | | [added: | | | | | |]

| Natural gas liquids [removed: (per] [added: ($ per] Bbl) | [added: | |] $ | [removed: 15.65] [added: 10.87] | | | [added: | |] $ | [removed: 24.43] [added: 14.42] | | [added: | | | | | |]

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

| [removed: Revenues:] [added: Revenues (in millions):] | | | | | | [added: | | | | | | | | | | | |]

| Oil sales | [removed: 91] | [removed: %] | [added: $] | [removed: 88] [added: 2,410] | [removed: %] | [added: | | | $ | 3,554 | | | | | | | |]

| Natural gas sales | [removed: 2] | [removed: %] | [added: 107] | [removed: 3] | [removed: %] | [added: | | | 66 | | | | | | | | |]

| Natural gas liquid sales | [removed: 7] | [removed: %] | [added: 239] | [removed: 9] | [removed: %] | [added: | | | 267 | | | | | | | | |]

| | [added: | |] 100 | [added: |] % | | [added: | |] 100 | [added: |] % | [added: | | | | | |]

[removed: Commodity] [added: COVID-19 and Collapse in Commodity] Prices

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

| [removed: Average realized natural] [added: Natural] gas liquids [removed: price ($/Bbl)] | [added: | | 3,483 | | | | | |] $ | 14.42 | | | [added: | |] $ | [removed: 25.47] [added: 50] | |

On [removed: December 31, 2019,] [added: January 29, 2021,] the [added: NYMEX] WTI [removed: Futures Contract 1] price for crude oil was [removed: $61.06] [added: $52.20] per Bbl and the [removed: Natural Gas Futures Contract 1] [added: NYMEX Henry Hub] price [added: of natural gas] was [removed: $2.19] [added: $2.56] per MMBtu.

On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a “pandemic.” To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers.

Although many stay-at-home orders have expired and certain restrictions on conducting business have been lifted, the COVID-19 pandemic resulted in a

widespread health crisis and a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets.

In early March 2020, oil prices dropped sharply and continued to decline reaching negative levels.

During 2020, the posted price for the WTI price for crude oil ranged from $(37.63) to $63.27 per barrel, or Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $3.35 per MMBtu.

In response to recent volatility in commodity prices, many producers have reduced their capital expenditure budgets.

This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic.

While OPEC members and certain other nations agreed in April 2020 to cut production and subsequently extended such production cuts through December 2020, which helped to reduce a portion of the excess supply in the market and improve crude oil prices, they agreed to increase production by 500,000 barrels per day beginning in January 2021.

We cannot predict if or when commodity prices will stabilize and at what levels.

As a result of the reduction in crude oil demand caused by factors discussed above, in 2020, we lowered our 2020 capital budgets and production guidance, curtailed near term production and reduced rig count, all of which may be subject to further reductions or curtailment if the commodity markets and macroeconomic conditions worsen.

Although we have restored curtailed production, actions taken in response to the COVID-19 pandemic and depressed commodity pricing environment have had and are expected to continue to have an adverse effect on our business, financial results and cash flows.

In addition, as a result of the sharp decline in commodity prices in early March 2020, and the continued depressed oil pricing throughout the second and third quarters of 2020, we recorded $6.0 billion of aggregate non-cash ceiling test impairments for the year ended December 31, 2020.

These impairment charges adversely affected our results of operations but did not reduce our cash flows.

If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters.

Our production, proved reserves and cash flows will also be adversely impacted.

Our results of operations may be further adversely impacted by any government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic, the depressed commodity prices and the adverse macroeconomic conditions will persist, the full extent of the impact they will have on our industry and our business, financial condition, results of operations or cash flows, or the pace or extent of any subsequent recovery.

Pending Merger with QEP Resources, Inc.

On December 20, 2020, we, QEP and the Merger Sub, entered into the merger agreement under which the Merger Sub will be merged with and into QEP, with QEP surviving as our wholly owned subsidiary.

If the pending merger is completed, each QEP stockholder will receive, in exchange for each share of QEP common stock held by such stockholder immediately prior to the closing of the pending merger, 0.050 of a share of our common stock.

The completion of the pending merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including the receipt of the required approvals from QEP’s stockholders.

The pending merger is expected to close shortly following the special meeting of the QEP stockholders, which is scheduled for March 16, 2021, subject to QEP stockholder approval and other customary closing conditions.

See “[Items 1 and 2.

Business and Properties—Overview—Pending Merger with QEP Resources, Inc.](#i4b770a66acfe418cb1b377f3d113fa9f_22)” for additional information regarding the pending merger.

We expect that the pending merger will:

- add material Tier-1 Midland Basin inventory;

- be accretive on all relevant 2021 per share metrics including cash flow per share, free cash flow per share and leverage, before accounting for synergies;

- lower 2021 reinvestment ratio and enhance ability to generate free cash flow, de-lever and return capital to our stockholders; and

- realize significant, tangible annual synergies of $60 to $80 million comprised of general and administrative expense savings, cost of capital and interest expense savings, improved capital efficiency from high-graded development of

combined acreage, physical adjacencies to increase lateral lengths and significant adjacent Permian Basin midstream assets.

In addition, we expect to maintain our investment grade credit ratings following the completion of the pending merger.

Pending Guidon Acquisition

On December 18, 2020, we entered into a definitive purchase and sale agreement with Guidon and certain of Guidon’s affiliates to acquire approximately 32,500 net acres in the Northern Midland Basin and certain related oil and natural gas assets, which we refer to as the Pending Guidon Acquisition.

Consideration for the Pending Guidon Acquisition consists of $375 million in cash and 10.6 million shares of our common stock, subject to adjustment.

The cash portion of this transaction is expected to be funded through a combination of cash on hand and borrowings under our credit facility.

The Pending Guidon Acquisition is expected to close on February 26, 2021.

Implementation of Viper’s Common Unit Repurchase Program

On November 6, 2020, the board of directors of Viper’s general partner approved an expansion of Viper’s return of capital program with the implementation of a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units through December 31, 2021.

During the year ended December 31, 2020, Viper repurchased approximately $24 million of its common units under its repurchase program.

As of December 31, 2020, $76 million remained available for use to repurchase common units under Viper’s common unit repurchase program.

We own Viper’s general partner and, together with one of our subsidiaries, approximately 58% of the limited partner interest in Viper, represented by common units and Class B units.

We, as the holder of the Class B units in Viper and Viper’s general partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective capital contributions payable quarterly.

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.

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.

As of December 31, 2019, $1.4 billion remains available for use to repurchase shares under our common stock repurchase program.

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

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

This divestiture did not result in a gain or loss because it did not have a significant effect on our reserve base or depreciation, depletion and amortization rate.

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

Viper’s Equity Offering

On March 1, 2019, Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters.

Following this offering, we owned approximately 54% of Viper’s total units then outstanding.

Viper received net proceeds from this offering

of approximately $341 million, after deducting underwriting discounts and commissions and estimated offering expenses.

Viper used the net proceeds to purchase units of Viper LLC.

Viper LLC in turn used the net proceeds to repay a portion of the outstanding borrowings under its revolving credit facility and finance acquisitions during the period.

Drop-Down

On October 1, 2019, we completed a transaction to divest certain mineral and royalty interests to Viper for 18.3 million of Viper’s newly-issued Class B units, 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits, which we refer to as the Drop-Down.

The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by us, and have an average net royalty interest of approximately 3.2%.

Increase in the Borrowing Base under Viper LLC’s Revolving Credit Facility

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

Viper loaned the gross proceeds to Viper LLC.

December 2019 Notes Offering

On December 5, 2019, we issued $1.0 billion in aggregate principal amount of 2.875% senior notes due 2024, which we refer to as the 2024 notes, $800 million in aggregate principal amount of 3.250% senior notes due 2026, which we refer to as the 2026 notes, and $1.2 billion aggregate principal amount of 3.500% senior notes due 2029, which we refer to as the 2029 notes and, together with the 2024 notes and the 2026 notes, the December 2019 Notes.

Our major market risk exposure [added: in our exploration and production business] is in the pricing applicable to our oil and natural gas production.

We use [removed: price swap] derivatives, including [removed: basis] swaps, [removed: double-up] [added: basis] swaps, [removed: put spreads, interest rate swaps] [added: swaptions, roll hedges] and [removed: three-way] [added: costless] collars, to reduce price volatility associated with certain of our oil and natural gas sales.

Utilizing actual derivative contractual volumes under our [removed: fixed price swaps and fixed] [added: commodity] price [removed: basis swaps] [added: derivatives] as of December 31, [removed: 2019,] [added: 2020,] a 10% increase in forward curves associated with the underlying commodity would have [removed: decreased] [added: increased] the net [removed: asset position to a net] liability position [removed: of $178] [added: to $284] million, [removed: a decrease] [added: an increase] of [removed: $204] [added: $29] million, while a 10% decrease in forward curves associated with the underlying commodity would have [removed: increased] [added: decreased] the net [removed: asset] [added: liability] derivative position to [removed: $232] [added: $226] million, [removed: an increase] [added: a decrease] of [removed: $206] [added: $29] million.

Our principal exposures to credit risk are [removed: through receivables resulting from joint interest receivables (approximately $186 million at December 31, 2019) and] [added: due to the concentration of] receivables from the sale of our oil and natural gas production (approximately [removed: $429] [added: $281] million at December 31, [removed: 2019).][added: 2020), and to a lesser extent, receivables resulting from joint interest receivables (approximately $56 million at December 31, 2020).]

We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us [removed: or] [added: due to] their [added: liquidity issues, bankruptcy,] insolvency or liquidation may adversely affect our financial results.

For [added: each of] the [removed: year] [added: years] ended December 31, [removed: 2019,] [added: 2019 and 2018,] three purchasers each accounted for more than 10% of our [removed: revenue: Shell (27%); Plains (23%); and Vitol (15%).][added: revenue.]

For the year ended December 31, [removed: 2018, three] [added: 2020, four] purchasers each accounted for more than 10% of our [removed: revenue: Shell (26%); Koch (15%); and Occidental Energy Marketing Inc. (11%).][added: revenue.]

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

The applicable margin ranges from 0.125% to 1.0% per annum [added: in the case of the alternative base rate] and from 1.125% to 2.0% per annum in the case of LIBOR, in each [removed: case,] [added: case] depending on the [removed: pricing level, which] [added: amount of the loan outstanding] in [removed: turn depends on] [added: relation to] the [removed: rating agencies’ rating of our unsecured debt.][added: borrowing base.]

At December 31, 2020, we had a net liability derivative position of $255 million related to our commodity price risk derivatives.

In our midstream operations business, we have indirect exposure to commodity price risk in that persistent low commodity prices may cause us or Rattler’s other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets.

If we or Rattler’s other customers delay drilling or temporarily shut in production due to persistently low commodity prices or for any other reason, our revenue in the midstream operations segment could decrease, as Rattler’s commercial agreements do not contain minimum volume commitments.

For additional information on our open commodity derivative instruments at December 31, 2020, see Note 15—[Derivatives](#i4b770a66acfe418cb1b377f3d113fa9f_208).

Our allowances for credit losses were insignificant at December 31, 2020.

The ongoing COVID-19 pandemic, depressed commodity pricing environment and adverse macroeconomic conditions may enhance our customer credit risk.

Historically, we have used interest rate swaps and treasury locks to reduce our exposure to variable rate interest payments associated with our revolving credit facility.

The following table summarizes the Company’s interest rate swaps as of December 31, 2020:

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

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

| Type | | | Effective Date | | | Contractual Termination Date | | | Notional Amount (in millions) | | | Interest Rate | | |

| Interest Rate Swap | | | December 31, 2024 | | | December 31, 2054 | | | $ | 250 | | 1.692 | | % |

| Interest Rate Swap | | | December 31, 2024 | | | December 31, 2054 | | | $ | 250 | | 1.8361 | | % |

| Interest Rate Swap | | | December 31, 2024 | | | December 31, 2054 | | | $ | 250 | | 1.852 | | % |

| Interest Rate Swap | | | December 31, 2024 | | | December 31, 2054 | | | $ | 250 | | 1.722 | | % |

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

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

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

For additional information on our variable interest rate debt at December 31, 2020, see Note 11—[Debt](#i4b770a66acfe418cb1b377f3d113fa9f_184).

See Note 18—[Subsequent Events](#i4b770a66acfe418cb1b377f3d113fa9f_229) for discussion of derivative transactions which occurred subsequent to December 31, 2020.

With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price.

Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil - Brent and with natural gas derivative settlements based on NYMEX Henry Hub and Waha Hub pricing.

At December 31, 2019 and December 31, 2018, we had a net asset derivative position of $26 million and $216 million, respectively, related to our price swap, price basis swap derivatives and three-way collars.

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers.

For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell (31%); Koch (19%); and Enterprise Crude Oil LLC (11%).

At December 31, 2019, we had 15 customers that represented approximately 80% of our total joint operations receivables.

At December 31, 2018, we had four customer that represented approximately 82% of our total joint operations receivables.

We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt.

As of December 31, 2019, we had $13 million borrowings outstanding under our revolving credit facility.

Our weighted average interest rate on borrowings under our revolving credit facility was 3.20% on December 31, 2019.

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

As of December 31, 2019, Viper LLC had $97 million in outstanding borrowings.

Viper LLC’s weighted average interest rate was 4.30%.

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

As of December 31, 2019, Rattler LLC had $424 million of outstanding borrowings.

Rattler LLC’s weighted average interest rate was 2.98%.

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

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas.

This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators.

We began operations in December 2007 with our acquisition of 4,174 net acres in the Permian Basin.

At December 31, 2019, our total acreage position in the Permian Basin was approximately 455,378 gross (382,337 net) acres, which consisted primarily of approximately 218,138 gross (195,461 net) acres in the Midland Basin and approximately 196,171 gross (155,296 net) acres in the Delaware Basin.

In addition, our publicly traded subsidiary Viper Energy Partners LP, which we refer to as Viper, owns mineral interests underlying approximately 814,224 gross acres and 24,304 net royalty acres in the Permian Basin and Eagle Ford Shale.

Approximately 50% of these net royalty acres are operated by us.

We own Viper Energy Partners GP LLC, the general partner of Viper, which we refer to as Viper’s general partner, and we own approximately 58% of the limited partner interest in Viper.

Further, our publicly traded subsidiary Rattler Midstream Partners LP, which we refer to as Rattler, is focused on ownership, operation, development and acquisition of midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.

We own Rattler Midstream GP LLC, the general partner of Rattler, which we refer to as Rattler’s general partner, and we own approximately 71% of the limited partner interest in Rattler.

As of December 31, 2019, Rattler owned and operated 867 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays our seven core Midland and Delaware Basin development areas.

To facilitate the transportation of produced water and hydrocarbon volumes away from the producing wellhead to ensuring the efficient operations of a crude oil or natural gas well, Rattler’s midstream infrastructure includes a network of gathering pipelines that collect and transport crude oil, natural gas and produced water from our operations in the Midland and Delaware Basins.

Our activities are primarily focused on horizontal development of the Spraberry and Wolfcamp formations of the Midland Basin and the Wolfcamp and Bone Spring formations of the Delaware Basin, both of which are part of the larger Permian Basin in West Texas and New Mexico.

The Permian Basin is characterized by high oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates.

As of December 31, 2019, our estimated proved oil and natural gas reserves were 1,127,575 MBOE (which includes estimated reserves of 88,946 MBOE attributable to the mineral interests owned by Viper), based on reserve reports prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers.

Of these reserves, approximately 67% are classified as proved developed producing.

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

As of December 31, 2019, our estimated proved reserves were approximately 63% oil, 20% natural gas liquids and 17% natural gas.

Based on our evaluation of applicable geologic and engineering data, we currently have approximately 12,310 gross (8,141 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $60.00 per Bbl WTI.

We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through additional acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

Significant 2019 Transactions

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

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

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

Drop-Down

On October 1, 2019, we completed a transaction to divest certain mineral and royalty interests to Viper for approximately 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits, which we refer to as the Drop-Down.

The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by us, and have an average net royalty interest of approximately 3.2%.

Rattler’s Initial Public Offering

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

Our Business Strategy

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

| | |

| --- | --- |

| • | Grow production and reserves by developing our oil-rich resource base. We intend to drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital. |

| | |

| --- | --- |

| • | Focus on increasing hydrocarbon recovery through horizontal development of stacked horizons. We have been developing multiple pay intervals in the Permian Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. Our initial horizontal wells were completed in 2012, and since then we have been an active horizontal driller in the basin. We believe that our significant experience drilling, completing and operating horizontal wells will allow us to efficiently develop our remaining inventory and ultimately target other horizons that have limited development to date. The following table presents horizontal wells in which we have an interest in as of December 31, 2019: |

| | | |

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

| | | |

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 [added: natural] 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 [removed: 18—Commitments] [added: 17—Commitments] and Contingencies included in [removed: Notes] [added: notes] to the [removed: Consolidated Financial Statements] [added: consolidated financial statements] included elsewhere in this [removed: Form 10-K.][added: Annual Report.]

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

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

For the fiscal year [removed: ended December] [added: ended December] 31, [removed: 2019][added: 2020]

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

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

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

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

| 500 West Texas | | | | [added: | | | | | | | |]

| Suite 1200 | | | | [added: | | | | | | | |]

| Midland, | [added: | |] TX | | [added: | | | |] 79701 | [added: | |]

| (Address of principal executive offices) | | | [added: | | | | | |] (Zip code) | [added: | |]

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

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

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

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

| | | | | | [added: | | | | | | | | | |] (NASDAQ Global Select Market) | | [added: | | | |]

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

| Large Accelerated Filer | | [added: | | | |] ☒ | | [added: | | | |] Accelerated Filer | | [added: | | | |] ☐ | [added: | |]

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

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June [removed: 28, 2019] [added: 30, 2020] was approximately [removed: $15.9] [added: $6.6] billion.

As of February [removed: 14, 2020, 158,284,486] [added: 19, 2021, 158,015,647] shares of the registrant’s common stock were outstanding.

Portions of Diamondback Energy, Inc.’s Proxy Statement for the [removed: 2020] [added: 2021] Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form [removed: 10-K][added: 10-K.]

FOR THE YEAR [removed: ENDED DECEMBER] [added: ENDED DECEMBER] 31, [removed: 2019][added: 2020]

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| [Glossary of Oil and Natural Gas [removed: Terms](#sDEF798E6C9C15C6FAFB6E444AEE4FF6B)] [added: Terms](#i4b770a66acfe418cb1b377f3d113fa9f_10)] | [removed: [ii](#sDEF798E6C9C15C6FAFB6E444AEE4FF6B)] | [added: | [ii](#i4b770a66acfe418cb1b377f3d113fa9f_10) | | |]

| [Glossary of Certain Other [removed: Terms](#sC6DE412526525F8A8268BB1B61280AD6)] [added: Terms](#i4b770a66acfe418cb1b377f3d113fa9f_13)] | [removed: [v](#sC6DE412526525F8A8268BB1B61280AD6)] | [added: | [iv](#i4b770a66acfe418cb1b377f3d113fa9f_13) | | |]

| [Cautionary Statement Regarding Forward-Looking [removed: Statements](#sF69C520980BE5AD0B505EDC3342E6E06)] [added: Statements](#i4b770a66acfe418cb1b377f3d113fa9f_16)] | [removed: [vi](#sF69C520980BE5AD0B505EDC3342E6E06)] | [added: | [v](#i4b770a66acfe418cb1b377f3d113fa9f_16) | | |]

| [removed: PART I] [added: [PART I](#i4b770a66acfe418cb1b377f3d113fa9f_19)] | | [added: | | | |]

| [Items 1 and 2. Business and [removed: Properties](#s37226CFEA69055F39905BFDC61C30933)] [added: Properties](#i4b770a66acfe418cb1b377f3d113fa9f_22)] | [removed: [1](#s37226CFEA69055F39905BFDC61C30933)] | [added: | [1](#i4b770a66acfe418cb1b377f3d113fa9f_22) | | |]

| [Item 1A. Risk [removed: Factors](#s966CA9510BB25389A3233616777CB381)] [added: Factors](#i4b770a66acfe418cb1b377f3d113fa9f_25)] | [removed: [26](#s966CA9510BB25389A3233616777CB381)] | [added: | [28](#i4b770a66acfe418cb1b377f3d113fa9f_25) | | |]

| [Item 1B. Unresolved Staff [removed: Comments](#s6FF7822F4B6455D9B41CAECE2AEC214E)] [added: Comments](#i4b770a66acfe418cb1b377f3d113fa9f_28)] | [removed: [53](#s6FF7822F4B6455D9B41CAECE2AEC214E)] | [added: | [52](#i4b770a66acfe418cb1b377f3d113fa9f_28) | | |]

| [Item 3. Legal [removed: Proceedings](#s862F35CDED205C089F6618D42CAAED05)] [added: Proceedings](#i4b770a66acfe418cb1b377f3d113fa9f_31)] | [removed: [53](#s862F35CDED205C089F6618D42CAAED05)] | [added: | [52](#i4b770a66acfe418cb1b377f3d113fa9f_31) | | |]

| [Item 4. Mine Safety [removed: Disclosures](#s9B71BE2B0C415CFEB42DD505F1D5E2AE)] [added: Disclosures](#i4b770a66acfe418cb1b377f3d113fa9f_34)] | [removed: [53](#s9B71BE2B0C415CFEB42DD505F1D5E2AE)] | [added: | [52](#i4b770a66acfe418cb1b377f3d113fa9f_34) | | |]

| [removed: PART II] [added: [PART II](#i4b770a66acfe418cb1b377f3d113fa9f_37)] | | [added: | | | |]

| [Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity [removed: Securities](#s55454EBEC6295B9A8FB865FDB125421F)] [added: Securities](#i4b770a66acfe418cb1b377f3d113fa9f_40)] | [removed: [54](#s55454EBEC6295B9A8FB865FDB125421F)] | [added: | [52](#i4b770a66acfe418cb1b377f3d113fa9f_40) | | |]

| [Item 6. Selected Financial [removed: Data](#sE39F189BDEE5518283DEB36B1AC8D08B)] [added: Data](#i4b770a66acfe418cb1b377f3d113fa9f_2420)] | [removed: [55](#sE39F189BDEE5518283DEB36B1AC8D08B)] | [added: | [53](#i4b770a66acfe418cb1b377f3d113fa9f_2420) | | |]

| [Item 7. Management's Discussion and Analysis of Financial Condition and Results of [removed: Operations](#s416DBF78571B530B9EE9551B2CFFBBD8)] [added: Operations](#i4b770a66acfe418cb1b377f3d113fa9f_46)] | [removed: [57](#s416DBF78571B530B9EE9551B2CFFBBD8)] | [added: | [54](#i4b770a66acfe418cb1b377f3d113fa9f_46) | | |]

| [Item 7A. Quantitative and Qualitative Disclosures about Market [removed: Risk](#s939C7D8E79E25257B8294D482112E3D9)] [added: Risk](#i4b770a66acfe418cb1b377f3d113fa9f_61)] | [removed: [80](#s939C7D8E79E25257B8294D482112E3D9)] | [added: | [71](#i4b770a66acfe418cb1b377f3d113fa9f_61) | | |]

| [Item 8. Financial Statements and Supplementary [removed: Data](#s43D1D6D554F35837A4EB588943371513)] [added: Data](#i4b770a66acfe418cb1b377f3d113fa9f_67)] | [removed: [81](#s43D1D6D554F35837A4EB588943371513)] | [added: | [72](#i4b770a66acfe418cb1b377f3d113fa9f_67) | | |]

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Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

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| [PART IV](#i4b770a66acfe418cb1b377f3d113fa9f_106) | | | | | |

| [Signatures](#i4b770a66acfe418cb1b377f3d113fa9f_115) | | | S-[1](#i4b770a66acfe418cb1b377f3d113fa9f_115) | | |

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| May 2020 Notes | | | The Company’s 4.750% Senior Notes due 2025 in the aggregate principal amount of $500.0 million issued on May 26, 2020 under the December 2019 Notes Indenture (defined above) and the related second supplemental indenture. | | |

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| PART IV | |

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

| BOE/d | Barrels of oil equivalent per day. |

| Mb/d | Thousand barrels per day. |

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

| WTL | West Texas Light |

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

| 2025 Senior Notes | The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 million. |

| Viper LTIP | Viper Energy Partners LP Long Term Incentive Plan. |

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

| Viper’s Partnership Agreement | The second amended and restated agreement of limited partnership, dated May 9, 2018, as amended as of May 10, 2018. |

| Wexford | Wexford Capital LP |

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act.

In particular, the factors discussed in this Annual Report on Form 10–K, including under *Part I, Item 1A.* “Risk Factors” in this report, could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

| • | acquisitions; |

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

| • | technology; |

| • | financial strategy; |

| • | the impact of reduced drilling activity; |

These forward-looking statements are subject to a number of risks, uncertainties and assumptions.

vii

Our common stock is listed on the Nasdaq [removed: Select] Global [added: Select] Market under the symbol “FANG”.

There were [removed: 20] [added: 2,564] holders of record of our common stock on February [removed: 13, 2020.][added: 19, 2021.]

Beginning with the first quarter of 2019, the annual cash dividend was [removed: increased to] [added: set at] $0.75 per share of our common stock.

[removed: Additionally,] [added: Then,] beginning with the fourth quarter of 2019, the annual cash dividend was increased to $1.50 per share [added: for our common stock and, beginning with the fourth quarter] of [added: 2020, the annual cash dividend was further increased to $1.60 per share of] our common stock.

Our common stock repurchase activity for the [removed: year] [added: three months] ended December 31, [removed: 2019] [added: 2020] was as follows:

| Period | | [added: | | | |] Total Number of Shares Purchased | | [added: | | | |] Average Price Paid Per Share(1) | | | | [added: | |] Total Number of Shares Purchased as Part of Publicly Announced Plan | | [added: | | | |] Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(2) | | |

| | | [added: | | | |] ($ in millions, except per share amounts, shares in thousands) | | | | | | | | | | | [added: | | | | | | | | | |]

[removed: | (1) | The] [added: (1)The] average price paid per share is net of any commissions paid to repurchase stock. [removed: |]

[removed: | (2) | In] [added: (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. [removed: This repurchase program may be suspended from time to time, modified, extended or discontinued by our board of directors at any time. |]

Unregistered Sales of Equity Securities

As previously disclosed in our Current Report on Form 8-K filed with the SEC on December 21, 2020, we entered into a definitive purchase and sale agreement, dated as of December 18, 2020, with Guidon and certain of Guidon’s affiliates to acquire approximately 32,500 net acres in the Northern Midland Basin and certain related oil and gas assets.

Consideration for the Pending Guidon Acquisition consists of $375 million in cash and 10.6 million shares of our common stock, subject to adjustment.

The shares to be issued in the Pending Guidon Acquisition will be 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.

We have agreed to file with the SEC, and use our reasonable best efforts to cause to be declared effective, a shelf registration statement registering for resale these shares within 60 days following the closing of the Pending Guidon Acquisition, which is expected to occur on February 26, 2021.

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| October 1, 2020 - October 31, 2020 | | | | | | — | | | | | | $ | — | | | | | — | | | | | | $ | 1,304 | |

| November 1, 2020 - November 30, 2020 | | | | | | — | | | | | | $ | — | | | | | — | | | | | | $ | 1,304 | |

| December 1, 2020 - December 31, 2020 | | | | | | — | | | | | | $ | — | | | | | — | | | | | | $ | — | |

| Total | | | | | | — | | | | | | $ | — | | | | | — | | | | | | | | |

This repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020.

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| 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 | | | | |

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| (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. |

\[Reserved.\]

This section presents our selected historical combined consolidated financial data.

The selected historical combined consolidated financial data presented below is not intended to replace our historical consolidated financial statements.

You should read the following data along with Item 7.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report on Form 10-K.

Presented below is our historical financial data for the periods and as of the dates indicated.

The historical financial data for the years ended December 31, 2019, 2018 and 2017 and the balance sheet data as of December 31, 2019 and 2018 are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

The historical financial data for the year ended December 31, 2016 and 2015 and the balance sheet data as of December 31, 2017, 2016 and 2015 are derived from our audited financial statements not included in this Annual Report on Form 10-K.

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| | Year Ended December 31, | | | | | | | | | | | | | | | | | | |

| (In millions, except per share amounts, shares in thousands) | 2019 | | | | 2018(1) | | | | 2017 | | | | 2016 | | | | 2015 | | |

| Statements of Operations Data: | | | | | | | | | | | | | | | | | | | |

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

| Total costs and expenses | 3,269 | | | | 1,165 | | | | 600 | | | | 596 | | | | 1,187 | | |

| Income (loss) from operations | 695 | | | | 1,011 | | | | 605 | | | | (69 | | ) | | (740 | | ) |

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

| Income (loss) before income taxes | 362 | | | | 1,113 | | | | 497 | | | | (165 | | ) | | (749 | | ) |

| Provision for (benefit from) income taxes | 47 | | | | 168 | | | | (20 | | ) | | — | | | | (201 | | ) |

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

| Less: Net income attributable to non-controlling interest | 75 | | | | 99 | | | | 35 | | | | — | | | | 3 | | |

| Net income (loss) attributable to Diamondback Energy, Inc. | $ | 240 | | | $ | 846 | | | $ | 482 | | | $ | (165 | ) | | $ | (551 | ) |

| Earnings per common share: | | | | | | | | | | | | | | | | | | | |

| Basic | $ | 1.47 | | | $ | 8.09 | | | $ | 4.95 | | | $ | (2.20 | ) | | $ | (8.74 | ) |

| Diluted | $ | 1.47 | | | $ | 8.06 | | | $ | 4.94 | | | $ | (2.20 | ) | | $ | (8.74 | ) |

| Weighted average common shares outstanding: | | | | | | | | | | | | | | | | | | | |

| Basic | 163,493 | | | | 104,622 | | | | 97,458 | | | | 75,077 | | | | 63,019 | | |

| Diluted | 163,843 | | | | 104,929 | | | | 97,688 | | | | 75,077 | | | | 63,019 | | |

| Cash dividends declared per common share | $ | 0.9375 | | | $ | 0.5000 | | | $ | — | | | $ | — | | | $ | — | |

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| (1) | Our results of operations for 2018 include those of Energen and its subsidiaries acquired by us in the merger from the period of November 29, 2018, the closing date of the Energen merger, through December 31, 2018. |

| | As of December 31, | | | | | | | | | | | | | | | | | | |

| (In millions) | 2019 | | | | 2018 | | | | 2017 | | | | 2016 | | | | 2015 | | |

| Balance Sheet Data: | | | | | | | | | | | | | | | | | | | |

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

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

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

| Current liabilities | 1,263 | | | | 1,019 | | | | 577 | | | | 209 | | | | 141 | | |

| 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 | | |

As of December 31, [removed: 2019,] [added: 2020,] 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: 2019,] [added: 2020,] our disclosure controls and procedures are effective.

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, [removed: 2019] [added: 2020] that have materially affected, or are reasonably likely to materially affect, internal controls over financial 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: 2019.][added: 2020.]

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: 2019.][added: 2020.]

The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, [removed: 2019,] [added: 2020,] is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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: 2019,] [added: 2020,] based on criteria established in the 2013 *Internal Control-Integrated Framework* issued by the Committee of Sponsoring Organizations of the Treadway Commission [removed: (COSO).][added: (“COSO”).]

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, [removed: 2019,] [added: 2020,] based on [removed: the] criteria established in the 2013 *Internal Control-Integrated Framework* issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, [removed: 2019,] [added: 2020,] and our report dated February [removed: 26, 2020] [added: 25, 2021] expressed an unqualified opinion on those financial statements.

February 25, 2021

February 26, 2020

None.

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:

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| --- | --- |

| (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.

We also believe that these benefits provide important protection to our named executive officers, are consistent with the prior employment protections and the practices of peer group companies and are appropriate for the attraction and retention of executive talent.

Appointment of Executive Vice President-Operations

On February 20, 2020, our board of directors promoted Daniel N.

Wesson to serve as our Executive Vice President-Operations, effective March 1, 2020.

Until the effective date of this promotion, Mr. Wesson will continue to serve as our Senior Vice President of Operations, a position he has held since February 2019.

Mr. Wesson served as our Vice President of Operations from April 2017 to February 2019 and as our Completions Manager from January 2013 to April 2017.

He joined us as an Operations Engineer in February 2012.

Before joining our company, Mr. Wesson served in various operations and engineering roles for BOPCO L.P. from 2010 to 2012 and ConocoPhillips from 2007 to 2010.

Mr. Wesson received his Bachelor of Science degree in Mechanical Engineering from Louisiana State University and is a member of the Permian Basin Society of Petroleum Engineers.

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

Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, [removed: 2019.][added: 2020.]

Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, [removed: 2019.][added: 2020.]

Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, [removed: 2019.][added: 2020.]

Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, [removed: 2019.][added: 2020.]

Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, [removed: 2019.][added: 2020.]

PART IV

| (a) | [added: | |] Documents included in this report: | | [added: | | | |]

| | [added: | |] *1. Financial Statements* | | [added: | | | |]

| | [added: | |] [Report of Independent Registered Public Accounting [removed: Firm](#s6AD80F4B350A55A7999161ECE3117221)] [added: Firm](#i4b770a66acfe418cb1b377f3d113fa9f_118)] | [removed: [F-1](#s6AD80F4B350A55A7999161ECE3117221)] | [added: | F-[1](#i4b770a66acfe418cb1b377f3d113fa9f_118) | | |]

| | [added: | |] [Consolidated Balance [removed: Sheets](#s53BFC45F44F8514FB6D216B0D9295E91)] [added: Sheets](#i4b770a66acfe418cb1b377f3d113fa9f_124)] | [removed: [F-4](#s53BFC45F44F8514FB6D216B0D9295E91)] | [added: | F-[3](#i4b770a66acfe418cb1b377f3d113fa9f_124) | | |]

| | [added: | |] [Consolidated Statements of [removed: Operations](#sBC33627955D953AEB91EB9212DA461B8)] [added: Operations](#i4b770a66acfe418cb1b377f3d113fa9f_130)] | [removed: [F-6](#sBC33627955D953AEB91EB9212DA461B8)] | [added: | F-[4](#i4b770a66acfe418cb1b377f3d113fa9f_130) | | |]

| | [added: | |] [Consolidated Statement of Stockholders' [removed: Equity](#s077622E88C785686AF50A4E6A5866C51)] [added: Equity](#i4b770a66acfe418cb1b377f3d113fa9f_133)] | [removed: [F-7](#s077622E88C785686AF50A4E6A5866C51)] | [added: | F-[5](#i4b770a66acfe418cb1b377f3d113fa9f_133) | | |]

| | [added: | |] [Consolidated Statements of Cash [removed: Flows](#sA1A861484B585E5DBA836587A8E57773)] [added: Flows](#i4b770a66acfe418cb1b377f3d113fa9f_136)] | [removed: [F-9](#sA1A861484B585E5DBA836587A8E57773)] | [added: | F-[6](#i4b770a66acfe418cb1b377f3d113fa9f_136) | | |]

| | [added: | |] [Notes to Consolidated Financial [removed: Statements](#s6DC5F63926635D6AA2643A349770EF85)] [added: Statements](#i4b770a66acfe418cb1b377f3d113fa9f_139)] | [removed: [F-11](#s6DC5F63926635D6AA2643A349770EF85)] | [added: | F-[8](#i4b770a66acfe418cb1b377f3d113fa9f_139) | | |]

| | [added: | |] *2. Financial Statement Schedules* | | [added: | | | |]

| | [added: | |] Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s consolidated financial statements and related notes. | | [added: | | | |]

| *3. Exhibits* | | | [added: | | | | | |]

| Exhibit Number | | [added: | | | |] Description | [added: | |]

| 2.1# | | [added: | | | |] [Agreement and Plan of Merger, dated as of [removed: August 14, 2018,] [added: December 20, 2020,] by and among Diamondback Energy, Inc., [removed: Sidewinder] [added: Bohemia] Merger [removed: Sub] [added: Sub,] Inc. and [removed: Energen Corporation] [added: QEP Resources, Inc.] (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on [removed: August 15, 2018).](http://www.sec.gov/Archives/edgar/data/1539838/000119312518249523/d593162dex21.htm)] [added: December 21, 2020).](https://www.sec.gov/Archives/edgar/data/1539838/000119312520322296/d93715dex21.htm)] | [added: | |]

| 3.1 | | [added: | | | |] [Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).](http://www.sec.gov/Archives/edgar/data/1539838/000153983812000004/exhibit31amendcertofincorp.htm) | [added: | |]

| 3.2 | | [added: | | | |] [Certificate of Amendment No. 1 of the Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 12, 2016).](http://www.sec.gov/Archives/edgar/data/1539838/000153983816000266/diamondbackex31-12x12x16.htm) | [added: | |]

| 3.3 | | [removed: [Amended] [added: | | | | [Second Amended] and Restated Bylaws of the Company (incorporated by reference to Exhibit [removed: 3.2] [added: 3.1] to the Form [removed: 10-Q,] [added: 8-K,] File No. 001-35700, filed by the Company with the SEC on November [removed: 16, 2012).](http://www.sec.gov/Archives/edgar/data/1539838/000153983812000004/exhibit32amendandrestatedb.htm)] [added: 19, 2019).](https://www.sec.gov/Archives/edgar/data/1539838/000153983819000122/diamondbackex31-11x19x.htm)] | [added: | |]

| [removed: 3.4] [added: 4.1] | | [removed: [First Amendment to] [added: | | | | [Description of] the [removed: Amended and Restated Bylaws] [added: Company’s Securities] (incorporated by reference to Exhibit [removed: 3.1] [added: 4.1] to the Form [removed: 8-K,] [added: 10-K,] File No. 000-35700, filed by the Company with the SEC on [removed: April] [added: February] 27, [removed: 2018).](http://www.sec.gov/Archives/edgar/data/1539838/000153983818000048/diamondbackex31-4x27x18.htm)] [added: 2020).](https://www.sec.gov/Archives/edgar/data/1539838/000153983820000021/diamondback201910-kxex41.htm)] | [added: | |]

| 4.2 | | [added: | | | |] [Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).](http://www.sec.gov/Archives/edgar/data/1539838/000119312512360997/d295327dex41.htm) | [added: | |]

| 4.3 | | [added: | | | |] [Indenture, dated as of December 20, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Diamondback Energy, Inc.’s 5.375% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 21, 2016).](http://www.sec.gov/Archives/edgar/data/1539838/000153983816000272/diamondbackex41-12x21x16.htm) | [added: | |]

| 4.4 | | [added: | | | |] [First Supplemental Indenture for the 5.375% Senior Notes due 2025, dated as of January 29, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on January 30, 2018).](http://www.sec.gov/Archives/edgar/data/1539838/000153983818000006/diamondbackex43-1x30x18.htm) | [added: | |]

| 4.5 | | [added: | | | |] [Second Supplemental Indenture for the 5.375% Senior Notes due 2025, dated as of October 12, 2018, among Sidewinder Merger Sub Inc., a subsidiary of the Company, the Company, the other guarantors and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.8 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2019).](http://www.sec.gov/Archives/edgar/data/1539838/000153983819000008/diamondback201810-kxex48.htm) | [added: | |]

| 4.6 | | [added: | | | |] [Third Supplemental Indenture for the 5.375% Senior Notes due 2025, dated as of January 28, 2019, among Energen Corporation, Energen Resources Corporation, and EGN Services, Inc., each a direct or indirect subsidiary of the Company, the Company, the other guarantors under the indenture and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.9 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2019).](http://www.sec.gov/Archives/edgar/data/1539838/000153983819000008/diamondback201810-kxex49.htm) | [added: | |]

| 4.7 | | [added: | | | |] [Indenture, dated as of December 5, 2019, between Diamondback Energy, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 5, 2019).](http://www.sec.gov/Archives/edgar/data/1539838/000153983819000127/diamondbackex41-12x5x19.htm) | [added: | |]

| 4.8 | | [added: | | | |] [First Supplemental Indenture, dated as of December 5, 2019, among Diamondback Energy, Inc., Diamondback O&G LLC and Wells Fargo Bank, National Association, as trustee (including the form of 2024 Notes, 2026 Notes and 2029 Notes) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 5, 2019).](http://www.sec.gov/Archives/edgar/data/1539838/000153983819000127/diamondbackex42-12x5x19.htm) | [added: | |]

| [removed: 4.9] [added: 4.10] | | [added: | | | |] [Indenture, dated as of October 16, 2019, among Viper Energy Partners LP, as issuer, Viper Energy Partners LLC, as guarantor, and Wells Fargo Bank, National Association, as trustee (including the form of Viper Energy Partners LP’s 5.375% Senior Notes due 2027) (incorporated by reference to Exhibit 4.1 of Viper Energy Partners LP’s Current Report on Form 8-K (File 001-36505) filed on October 17, 2019).](http://www.sec.gov/Archives/edgar/data/1602065/000110465919054635/tm19193893_ex4-1.htm) | [added: | |]

| [removed: 4.10] [added: 4.11] | | [added: | | | |] [Consent Letter, dated August 28, 2019, between Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc. as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File 001-35700) filed on September 4, 2019).](http://www.sec.gov/Archives/edgar/data/1539838/000153983819000103/diamondbackex101-9x4x19.htm) | [added: | |]

| [removed: 4.11] [added: 4.12] | | [added: | | | |] [Subordinated Promissory Note, dated as of October 16, 2019, by Viper Energy Partners LLC in favor of Viper Energy Partners LP (incorporated by reference to Exhibit 10.2 of Viper Energy Partners LP’s Current Report on Form 8-K (File 001-36505) filed on October 17, 2019).](http://www.sec.gov/Archives/edgar/data/1602065/000110465919054635/tm19193893_ex10-2.htm) | [added: | |]

| [removed: 4.13] [added: 10.12] | | [removed: [Registration Rights] [added: | | | | [Second Amended and Restated Credit] Agreement, dated [removed: October 31, 2018, by and between] [added: as of November 1, 2013, among] Diamondback Energy, [removed: Inc.] [added: Inc., as parent guarantor, Diamondback O&G LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent,] and [removed: Ajax Resources, LLC] [added: the lenders party thereto] (incorporated by reference to Exhibit [removed: 4.1] [added: 10.3] to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November [removed: 7, 2018).](http://www.sec.gov/Archives/edgar/data/1539838/000153983818000117/exhibit410.htm)] [added: 5, 2013).](http://www.sec.gov/Archives/edgar/data/1539838/000153983813000093/ex10_3diamondbacksecondame.htm)] | [added: | |]

| 4.14 | | [added: | | | |] [Form of Indenture, dated September 1, 1996, between Energen and The Bank of New York as trustee (incorporated by reference to Exhibit 4(i) to Energen’s Registration Statement on Form S-3 (Registration No. 333-11239), filed with the SEC on August 30, 1996).](http://www.sec.gov/Archives/edgar/data/277595/0000950109-96-005681.txt) | [added: | |]

| 10.1 | | [added: | | | |] [Diamondback Energy, Inc. [removed: 2016] [added: 2019] Amended and Restated Equity Incentive Plan (incorporated by reference to Appendix A to Schedule DEFA 14A filed by the Company with the SEC on [removed: May 25, 2016).](http://www.sec.gov/Archives/edgar/data/1539838/000153983816000181/a2016additionalproxymateri.htm)] [added: April 26, 2020).](http://www.sec.gov/Archives/edgar/data/1539838/000153983816000181/a2016additionalproxymateri.htm)] | [added: | |]

| [removed: 10.2+*] [added: 10.4+*] | | [removed: [2020] [added: | | | | [2021] Form of Time Vesting Restricted Stock Unit Award [removed: Agreement.](https://www.sec.gov/Archives/edgar/data/1539838/000153983820000021/diamondback201910-kxex102.htm)] [added: Agreement.](https://www.sec.gov/Archives/edgar/data/1539838/000153983821000015/diamondback202010-kxex104.htm)] | [added: | |]

| [removed: 10.3+*] [added: 10.3+] | | [added: | | | |] [2020 Form of Performance Vesting Restricted Stock Unit Award [removed: Agreement.](https://www.sec.gov/Archives/edgar/data/1539838/000153983820000021/diamondback201910-kxex103.htm)] [added: Agreement (incorporated by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K (File 001-35700) filed on February 27, 2020).](https://www.sec.gov/Archives/edgar/data/1539838/000153983820000021/diamondback201910-kxex103.htm)] | [added: | |]

| [removed: 10.4+] [added: 10.8+] | | [added: | | | |] [Form of Director and Officer Indemnification Agreement (incorporated by reference [removed: to Exhibit] [added: to](http://www.sec.gov/Archives/edgar/data/1539838/000119312512360997/d295327dex1015.htm)[ ](http://www.sec.gov/Archives/edgar/data/1539838/000119312512360997/d295327dex1015.htm)[Exhibit] 10.15 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).](http://www.sec.gov/Archives/edgar/data/1539838/000119312512360997/d295327dex1015.htm) | [added: | |]

| [removed: 10.5+*] [added: 10.9+] | | [added: | | | |] [Diamondback Energy, Inc. Senior Management Severance Plan (including forms of participation agreements attached thereto as Schedules C-1 and [removed: C-2).](https://www.sec.gov/Archives/edgar/data/1539838/000153983820000021/diamondback201910-kxex105.htm)] [added: C-2) (incorporated by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-K (File 001-35700) filed on February 27, 2020).](https://www.sec.gov/Archives/edgar/data/1539838/000153983820000021/diamondback201910-kxex103.htm)] | [added: | |]

| [removed: 10.6+] [added: 10.10+] | | [added: | | | |] [2014 Executive Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on April 2, 2014).](http://www.sec.gov/Archives/edgar/data/1539838/000153983814000043/ex10_1diamondback2014ex.htm) | [added: | |]

| [removed: 10.7+] [added: 10.6+] | | [removed: [2014 Form] [added: | | | | [Form] of Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, [removed: 2014).](http://www.sec.gov/Archives/edgar/data/1539838/000153983814000018/ex10_1db2014awardstimebase.htm)] [added: 2014).](https://www.sec.gov/Archives/edgar/data/1539838/000153983814000018/ex10_1db2014awardstimebase.htm)] | [added: | |]

| [removed: 10.8+] [added: 10.7+] | | [removed: [2014 Form] [added: | | | | [Form] of Performance-Based Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, [removed: 2014).](http://www.sec.gov/Archives/edgar/data/1539838/000153983814000018/ex10_2db2014tsrperformance.htm)] [added: 2014).](https://www.sec.gov/Archives/edgar/data/1539838/000153983814000018/ex10_2db2014tsrperformance.htm)] | [added: | |]

| [removed: 10.9+] [added: 10.32+] | | [removed: [Form of Amendment] [added: | | | | [Amendment] to [removed: Restricted] [added: the Energen Corporation] Stock [removed: Unit Certificate] [added: Incentive Plan, dated November 27, 2018] (incorporated by reference to Exhibit [removed: 10.38] [added: 4.7] to the [added: Registration Statement on] Form [removed: 10-K/A, file] [added: S-8, File] No. [removed: 001-35700,] [added: 333-228637,] filed by the Company with the SEC on [removed: April 10, 2013).](http://www.sec.gov/Archives/edgar/data/1539838/000153983813000013/ex1038-formofamendemnttors.htm)] [added: November 30, 2018).](http://www.sec.gov/Archives/edgar/data/1539838/000119312518339924/d667200dex47.htm)] | [added: | |]

| [removed: 10.10] [added: 10.14] | | [added: | | | |] [Second [added: Amendment to the Second] Amended and Restated Credit Agreement, dated as of November [removed: 1, 2103,] [added: 13, 2014,] among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, [added: the guarantors,] Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit [removed: 10.3] [added: 10.2] to the Form [removed: 10-Q,] [added: 8-K,] File No. 001-35700, filed by the Company with the SEC on November [removed: 5, 2013).](http://www.sec.gov/Archives/edgar/data/1539838/000153983813000093/ex10_3diamondbacksecondame.htm)] [added: 18, 2014).](http://www.sec.gov/Archives/edgar/data/1539838/000119312514416704/d822128dex102.htm)] | [added: | |]

| [removed: 10.11] [added: 10.13] | | [added: | | | |] [First Amendment, dated June 9, 2014, to the Second Amended and Restated Credit Agreement, originally dated November 1, 2013, by and among the Company, as parent guarantor, Diamondback O&G LLC, as borrower, each of the guarantors party thereto, each of the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 7, 2014).](http://www.sec.gov/Archives/edgar/data/1539838/000153983814000081/ex10_4firstamendmenttoseco.htm) | [added: | |]

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

| *3. Exhibits* | | | | | | | | |

| Exhibit Number | | | | | | Description | | |

| 4.13 | | | | | | [Indenture, dated as of July 14, 2020, among Rattler Midstream LP, as issuer, Rattler Midstream Operating LLC, Tall City Towers LLC, Rattler Ajax Processing LLC, and Rattler OMOG LLC, as guarantors, and Wells Fargo Bank, National Association, as trustee (including the form of Rattler Midstream LP’s 5.625% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-38919, filed by Rattler Midstream LP with the SEC on July 14, 2020).](https://www.sec.gov/Archives/edgar/data/1748773/000119312520192623/d939793dex41.htm) | | |

| | | | | | | | | |

| | | | | | | | | |

| 10.2+ | | | | | | [2020 Form of Time Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 of the Company’s Annual Report on Form 10-K (File 001-35700) filed on February 27, 2020).](https://www.sec.gov/Archives/edgar/data/1539838/000153983820000021/diamondback201910-kxex102.htm) | | |

| 10.5+* | | | | | | [2021 Form of Performance Vesting Restricted Stock Unit Agreement.](https://www.sec.gov/Archives/edgar/data/1539838/000153983821000015/diamondback202010-kxex105.htm) | | |

| | | | | | | | | |

| | | | | | | | | |

| 10.11+* | | | | | | [Executive Annual Incentive Compensation Plan adopted in February 2021.](https://www.sec.gov/Archives/edgar/data/1539838/000153983821000015/diamondback202010-kxex1011.htm) | | |

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

| *3. Exhibits* | | | | | | | | |

| Exhibit Number | | | | | | Description | | |

| | | | | | | | | |

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

| *3. Exhibits* | | | | | | | | |

| Exhibit Number | | | | | | Description | | |

| 10.26 | | | | | | [Fifth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 11, 2020, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2020).](https://www.sec.gov/Archives/edgar/data/1602065/000160206520000024/viperex101-51520.htm) | | |

| 10.27 | | | | | | [Sixth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of November 6, 2020, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on November 12, 2020).](https://www.sec.gov/Archives/edgar/data/1602065/000160206520000056/viperex101-11x12x20.htm) | | |

| 10.30 | | | | | | [Second Amendment, dated as of November 2, 2020, to the Credit Agreement, dated May 28, 2019, as amended on October 23, 2019, by and among Rattler Midstream Operating LLC, as borrower, Rattler Midstream LP, as parent, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party thereto. (incorporated by reference to Exhibit 10.3 of the Partnership’s Quarterly Report on Form 10-Q (File 001-38919) filed on November 5, 2020).](https://www.sec.gov/Archives/edgar/data/1748773/000174877320000046/rattlerex103-11x5x20.htm) | | |

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

| *3. Exhibits* | | | | | | | | |

| Exhibit Number | | | | | | Description | | |

| | | | | | |

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

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| 4.1* | | [Description of the Company’s Securities.](https://www.sec.gov/Archives/edgar/data/1539838/000153983820000021/diamondback201910-kxex41.htm) |

| 4.12 | | [Registration Rights Agreement, dated as of February 28, 2017, among Diamondback Energy, Inc., Brigham Resources, LLC, Brigham Resources Operating, LLC and Brigham Resources Upstream Holdings, LP. (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001.35700, filed by the Company with the SEC on March 6, 2017).](http://www.sec.gov/Archives/edgar/data/1539838/000153983817000040/diamondbackex41-3x6x17.htm) |

| 10.26 | | [ATM Equity OfferingSM Sales Agreement, dated December 11, 2018, by and among Diamondback Energy, Inc., Ajax Resources, LLC, F&A Wylie Investments, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as sales agent (incorporated by reference to 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 12, 2018).](http://www.sec.gov/Archives/edgar/data/1539838/000119312518347161/d672709dex101.htm) |

| 10.28+ | | [Amendment to the Energen Corporation Stock Incentive Plan, dated November 27, 2018 (incorporated by reference to Exhibit 4.7 to the Registration Statement on Form S-8, File No. 333-228637, filed by the Company with the SEC on November 30, 2018).](http://www.sec.gov/Archives/edgar/data/1539838/000119312518339924/d667200dex47.htm) |

| 10.32+ | | [Form of Performance Share Award under the Energen Corporation Stock Incentive Plan (incorporated by reference to Exhibit 10(t) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012).](http://www.sec.gov/Archives/edgar/data/3146/000027759513000012/exhibit10t.htm) |

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

| Date: | [added: | |] February [removed: 26, 2020] [added: 25, 2021] | | | [added: | | | | | |]

| | | | [added: | | | | | |] /s/ Travis D. Stice | [added: | |]

| | | | [added: | | | | | |] Travis D. Stice | [added: | |]

| | | | [added: | | | | | |] Chief Executive Officer | [added: | |]

| | | | [added: | | | | | |] (Principal Executive Officer) | [added: | |]

| Signature | | [added: | | | |] Title | | [added: | | | |] Date | [added: | |]

| /s/ Steven E. West | | [added: | | | |] Chairman of the Board and Director | | [added: | | | |] February [removed: 26, 2020] [added: 25, 2021] | [added: | |]

| Steven E. West | | | | | [added: | | | | | | | | | |]

| /s/ Travis D. Stice | | [added: | | | |] Chief Executive Officer and Director | | [added: | | | |] February [removed: 26, 2020] [added: 25, 2021] | [added: | |]

| Travis D. Stice | | [added: | | | |] (Principal Executive Officer) | | | [added: | | | | | |]

| /s/ Michael P. Cross | | [added: | | | |] Director | | [added: | | | |] February [removed: 26, 2020] [added: 25, 2021] | [added: | |]

| Michael P. Cross | | | | | [added: | | | | | | | | | |]

| /s/ David L. Houston | | [added: | | | |] Director | | [added: | | | |] February [removed: 26, 2020] [added: 25, 2021] | [added: | |]

| David L. Houston | | | | | [added: | | | | | | | | | |]

| /s/ Mark L. Plaumann | | [added: | | | |] Director | | [added: | | | |] February [removed: 26, 2020] [added: 25, 2021] | [added: | |]

| Mark L. Plaumann | | | | | [added: | | | | | | | | | |]

| /s/ Melanie M. Trent | | [added: | | | |] Director | | [added: | | | |] February [removed: 26, 2020] [added: 25, 2021] | [added: | |]

| Melanie M. Trent | | | | | [added: | | | | | | | | | |]

| /s/ Kaes Van’t Hof | | [added: | | | |] Chief Financial Officer and Executive Vice President—Business Development | | [added: | | | |] February [removed: 26, 2020] [added: 25, 2021] | [added: | |]

| Kaes Van’t Hof | | [added: | | | |] (Principal Financial Officer) | | | [added: | | | | | |]

| /s/ Teresa L. Dick | | [added: | | | |] Chief Accounting Officer, Executive Vice President and Assistant Secretary | | [added: | | | |] February [removed: 26, 2020] [added: 25, 2021] | [added: | |]

| Teresa L. Dick | | [added: | | | |] (Principal Accounting Officer) | | | [added: | | | | | |]

We have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (collectively the “Company”) as of December 31, [removed: 2019] [added: 2020] and [removed: 2018,] [added: 2019,] and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, [removed: 2019,] [added: 2020,] and the related notes (collectively referred to as the “financial statements”).

In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, [removed: 2019] [added: 2020] and [removed: 2018,] [added: 2019,] and the results of its operations and its cash flows for each of the three years in the period ended December 31, [removed: 2019,] [added: 2020,] in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, [removed: 2019,] [added: 2020,] based on criteria established in the 2013 *Internal Control-Integrated Framework* issued by the Committee of Sponsoring Organizations of the Treadway Commission [removed: (COSO),] [added: (“COSO”),] and our report dated February [removed: 26, 2020] [added: 25, 2021] expressed an unqualified opinion.

Such procedures included examining, on a test basis, evidence [removed: supporting] [added: regarding] the amounts and disclosures in the financial statements.

The communication of critical audit matters does not alter in any way our opinion on the financial [removed: statements,] [added: statements] taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

[removed: *Depletion expense, impairment evaluation and acquisition] [added: | Impairment] of oil and [added: natural] gas [removed: properties*][added: properties | | | $ | 6,021 | | | | | $ | — | | | | | | | | | | | $ | — | | | | | $ | 6,021 | |]

To estimate the volume of proved reserves and future revenues, management makes significant estimates and [removed: assumptions] [added: assumptions,] including forecasting the production decline rate of producing [removed: properties,] [added: properties and] forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped [removed: properties, and for acquisitions that included proved developed producing properties using an estimated fair value pricing model for the valuation of proved producing reserves.][added: properties.]

We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion [removed: expense, impairment evaluation and acquisition valuation of oil] [added: expense] and [removed: gas properties,] [added: impairment evaluation,] as a critical audit matter.

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

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

[removed: | ◦ | For acquisitions of oil and gas properties during the year in which proved developed producing properties are significant and to] [added: - To] the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, [added: operating costs, estimated capital costs and] working and net revenue [removed: interests and future capital expenditures and operating costs,] [added: interests,] we tested management’s process for determining the assumptions, including examining the underlying [removed: support. Specifically, our audit procedures involved testing management’s assumptions as follows: |][added: support, on a sample basis.]

[removed: | ◦ | Evaluated] [added: –Evaluated] the working and net revenue interests used in the [removed: acquisition] reserve report by inspecting a sample of land and division order records; [removed: |]

[removed: | ◦ | Compared] [added: –Compared] the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials; [removed: |]

[removed: | ◦ | Evaluated] [added: –Evaluated] the models used to estimate the operating costs at year-end compared to historical operating costs; [removed: |]

[removed: | ◦ | Compared] [added: –Compared] the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations; [removed: |]

[removed: | ◦ | Evaluated] [added: –Evaluated] the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the [added: Company’s or the] operator’s intent to develop the proved undeveloped properties; [removed: |]

[removed: | ◦ | Evaluated] [added: –Evaluated] the estimated ultimate recovery of proved undeveloped properties to the estimated ultimate recovery of comparable proved developed producing properties; and [removed: |]

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| /s/ Vincent K. Brooks | | | | | | Director | | | | | | February 25, 2021 | | |

| Vincent K. Brooks | | | | | | | | | | | | | | |

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| /s/ Stephanie K. Mains | | | | | | Director | | | | | | February 25, 2021 | | |

| Stephanie K. Mains | | | | | | | | | | | | | | |

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*Estimation of proved reserves as it relates to the calculation and recognition of depletion expense and the evaluation of impairment*

- We tested the design and operating effectiveness of key controls relating to the preparation of the ceiling test calculation and management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment.

Specifically, our audit procedures involved testing management’s assumptions as follows:

| | | | (In millions, except par value and share amounts) | | | | | | | | |

| Deferred income taxes, net | | | 73 | | | | | | 142 | | |

| Current maturities of long-term debt | | | 191 | | | | | | — | | |

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| Distribution equivalent rights payments | | | — | | | | | | — | | | | | | — | | | | | | (1) | | | | | | | | | | | | (2) | | | | | | (3) | | |

| Repurchased shares under buyback program | | | (1,280) | | | | | | — | | | | | | (98) | | | | | | — | | | | | | | | | | | | — | | | | | | (98) | | |

| Repurchased units under buyback programs | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | | | | | | | (39) | | | | | | (39) | | |

| Dividend paid | | | — | | | | | | — | | | | | | — | | | | | | (236) | | | | | | | | | | | | — | | | | | | (236) | | |

| Change in ownership of consolidated subsidiaries, net | | | — | | | | | | — | | | | | | 358 | | | | | | — | | | | | | | | | | | | (366) | | | | | | (8) | | |

| Balance at December 31, 2020 | | | 158,088 | | | | | | $ | 2 | | | | | $ | 12,656 | | | | | $ | (3,864) | | | | | | | | | | | $ | 1,010 | | | | | $ | 9,804 | |

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Additionally, as described in Note 3 to the financial statements, the Company acquired significant oil and gas properties throughout the year.

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| ◦ | Analyzed the appropriateness of fair value pricing used in the acquisition reserve report to published product pricing on the acquisition closing date; |

| ◦ | Analyzed the appropriateness of the future operating cost and capital expenditure assumptions used in the acquisition reserve report to historical operating costs and capital expenditures of similarly located properties |

| ◦ | Analyzed, on a sample basis, the appropriateness of management’s estimated future production volumes and the production decline curves; and |

| ◦ | Utilized valuation specialists to compare the acreage value allocated, on a per acre basis, to undeveloped properties and to other recent acquisitions in the same or similar locations. |

| ◦ | To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows: |

| ◦ | Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of land and division order records; |

February 26, 2020

Diamondback Energy, Inc. and Subsidiaries

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Consolidated Balance Sheets - Continued

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| Lease bonus | 4 | | | | 3 | | | | 12 | | |

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| Balance December 31, 2016 | 90,144 | | $ | 1 | | | $ | 4,216 | | | $ | (520 | ) | | $ | 321 | | | $ | 4,018 | |

| Net proceeds from issuance of common units - Rattler Midstream LP | | | | | | | | | | | | | | | 720 | | | | 720 | | |

| Common units issued for acquisition | | | — | | | | — | | | | | | | | 124 | | | | 124 | | |

Consolidated Statement of Stockholders’ Equity - Continued

| Change in fair value of derivative instruments | 188 | | | | (222 | | ) | | 84 | | |

| (Gain) loss on revaluation of investment | (5 | | ) | | 1 | | | | — | | |

| Gain on sale of inventory | (1 | | ) | | — | | | | — | | |

| Restricted cash | (5 | | ) | | — | | | | — | | |

| Inventories | (10 | | ) | | (14 | | ) | | (2 | | ) |

| Accrued interest | (5 | | ) | | (22 | | ) | | (21 | | ) |

| Proceeds from exercise of stock options | 9 | | | | — | | | | — | | |

| Repurchased as part of share buyback | (593 | | ) | | — | | | | — | | |

| Cash paid for income taxes | $ | — | | | $ | 1 | | | $ | — | |

| Change in accrued capital expenditures | $ | (20 | ) | | $ | 274 | | | $ | 161 | |

| Common stock issued for Brigham | $ | — | | | $ | — | | | $ | 809 | |

| Common stock issued for business combination(1) | $ | — | | | $ | 7,136 | | | $ | — | |

Diamondback was incorporated in Delaware on December 30, 2011.