Diamondback Energy (FANG) 10-K risk factor changes: FY2017 vs FY2016

If any of these risks actually occurs, it could materially harm our business, financial [removed: conditional] [added: condition] or results of operations and the trading price of our shares could decline.

Our review [removed: may] [added: will] not reveal all existing or potential problems [removed: or] [added: nor will it] permit us to become sufficiently familiar with the properties to [removed: fully] assess [added: fully] their deficiencies and [removed: potential recoverable reserves.][added: capabilities.]

Market conditions for oil and natural gas, and particularly [removed: the ongoing decline] [added: volatility] in prices for oil and natural [removed: gas have,] [added: gas, have in the past adversely affected,] and may [removed: continue to,] [added: in the future] adversely [removed: affect] [added: affect,] our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.

During the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $26.19 per barrel, or Bbl, in February 2016 [removed: to a high of $110.62 per Bbl in September 2013.]

During [removed: 2016,] [added: 2017,] WTI prices ranged from [removed: $26.19] [added: $42.48] to [removed: $54.01] [added: $60.46] per Bbl and the Henry Hub spot market price of natural gas ranged from [removed: $1.49] [added: $2.44] to [removed: $3.80] [added: $3.71] per MMBtu.

On January [removed: 31, 2017,] [added: 29, 2018,] the WTI posted price for crude oil was [removed: $52.75] [added: $65.71] per Bbl and the Henry Hub spot market price of natural gas was [removed: $3.00] [added: $3.60] per MMBtu, representing [removed: decreases] [added: increases] of [removed: 2%] [added: 9%] and [removed: 21%,] [added: 3%,] respectively, from the high of [removed: $54.01] [added: $60.46] per Bbl of oil and [removed: $3.80] [added: $3.71] per MMBtu for natural gas during [removed: 2016.][added: 2017.]

If the prices of oil and natural gas [removed: continue at current levels or decline further,] [added: decline,] our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.

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 [removed: contributed] [added: in the past contributed, and may in the future contribute,] to [removed: increased] economic uncertainty and diminished expectations for the global economy.

These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, [removed: have precipitated] [added: may precipitate] an economic slowdown.

Concerns about global economic growth [added: may] have [removed: had a significant] [added: 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 [removed: diminish further,] [added: 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.

In [removed: 2016,] [added: 2017,] our total capital expenditures, including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately [removed: $1,180.1 million.][added: $3.2 billion.]

Our [removed: 2017] [added: 2018] capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately [removed: $800.0 million] [added: $1.3 billion] to [removed: $1.0] [added: $1.5] billion, representing an increase of [removed: 132%] [added: 60%] over our [removed: 2016] [added: 2017] capital budget.

Further, our actual capital expenditures in [removed: 2017] [added: 2018] could exceed our capital expenditure budget.

From inception through December 31, [removed: 2016,] [added: 2017,] we drilled a total of [removed: 523] [added: 412] gross [added: horizontal wells and 262 gross] vertical wells and participated in an additional [removed: 62] [added: 61] gross [removed: non-operated] [added: horizontal wells and 18 gross] vertical [added: non-operated] wells, of which [removed: 533] [added: 670] wells were completed as producing wells and [removed: 52] [added: 83] wells were in various stages of completion.

At an assumed price of approximately [removed: $50.00] [added: $60.00] per Bbl WTI, we currently have approximately [removed: 2,722] [added: 3,800] gross [removed: (1,802] [added: (2,750] net) identified economic potential horizontal drilling locations in multiple horizons on our acreage.

As of December 31, [removed: 2016,] [added: 2017,] only [removed: 120] [added: 168] of our gross identified potential horizontal drilling locations were attributed to proved reserves.

In addition, we have identified approximately [removed: 854] [added: 873] 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.

Through December 31, [removed: 2016,] [added: 2017,] we are the operator of or have participated in a total of [removed: 277] [added: 466] 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.

As of December 31, [removed: 2016,] [added: 2017,] we had leases representing [removed: 15,439] [added: 22,913] net acres expiring in [removed: 2017, 1,845] [added: 2018, 19,670] net acres expiring in [removed: 2018, 1,772] [added: 2019, 20,219] net acres expiring in [removed: 2019, 23] [added: 2020, 719] net acres expiring in [removed: 2020] [added: 2021] and no net acres expiring in [removed: 2021.][added: 2022.]

In addition, in order to hold our current leases expiring in [removed: 2017,] [added: 2018,] we will need to operate at least a one-rig program.

Although we have hedged a portion of our estimated [removed: 2017 and] 2018 [added: and 2019] production, we may still be adversely affected by continuing and prolonged declines in the price of oil.

[removed: The counterparty is required] to [removed: make a payment to] us if the settlement price for any settlement period is less than the put option price.

As of December 31, [removed: 2016,] [added: 2017,] we had the following commodity contracts in place covering NYMEX WTI crude [added: oil, Brent crude] oil and NYMEX Henry Hub natural gas for the production period of January [removed: 2017] [added: 2018] through December [removed: 2017:][added: 2018:]

| • | crude oil swap contracts priced at a weighted average price of [removed: $51.79] [added: $51.10 WTI] for [removed: 2,920,000] [added: 9,761,000] aggregate Bbls; |

| • | crude oil basis swap contracts priced at a weighted average price of [removed: $(0.72)] [added: $0.88] for [removed: 8,760,000] [added: 5,475,000] aggregate Bbls for the spread between the WTI Midland price and the WTI Cushing price; |

| • | natural gas swap contracts priced at a weighted average price of [removed: $3.19] [added: $3.14] for [removed: 7,300,000] [added: 7,750,000] aggregate MMBtu; and |

| • | crude oil costless collars contracts with a floor price of [removed: $46.30] [added: $47.00] for [removed: 4,374,000] [added: 540,000] aggregate Bbls and a ceiling price of [removed: $55.42] [added: $56.34] for [removed: 2,187,000] [added: 270,000] aggregate Bbls. |

We have crude oil [removed: basis] swap contracts priced at a weighted average price of [removed: $(0.88)] [added: $49.82 WTI] for [removed: 5,475,000] [added: 1,095,000] aggregate Bbls [removed: for the spread between the WTI Midland price and the WTI Cushing price] with a production period of January [removed: 2018] [added: 2019] through December [removed: 2018.][added: 2019.]

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: $49.5] [added: $73.0] million at December 31, [removed: 2016)] [added: 2017)] and receivables from purchasers of our oil and natural gas production (approximately [removed: $70.6] [added: $158.6] million at December 31, [removed: 2016).][added: 2017).]

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

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

For the year ended December 31, [removed: 2014, two] [added: 2017, three] purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company [removed: (64%);] [added: (31%); Koch Supply & Trading LP (19%)] and Enterprise Crude Oil LLC [removed: (16%).][added: (11%).]

The average depletion rate per barrel equivalent unit of production was [removed: $11.23, $17.84] [added: $11.11, $11.23] and [removed: $23.79] [added: $17.84] for the years ended December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014,] [added: 2015,] respectively.

Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014] [added: 2015] was [removed: $176.4] [added: $321.9] million, [removed: $216.1] [added: $176.4] million and [removed: $168.7] [added: $216.1] million, respectively.

No impairment on proved oil and natural gas properties was recorded for the year ended December 31, [removed: 2014.][added: 2017.]

Our historical estimates of proved reserves as of December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014] [added: 2015] (which include those attributable to Viper) are based on reports prepared by Ryder Scott, which conducted a well-by-well review of all our properties for the periods covered by its reserve reports using information provided by us.

[added: Reserve] estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

The estimates of reserves as of December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014] [added: 2015] included in this report were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014,] [added: 2015,] respectively, in accordance with the SEC guidelines applicable to reserve estimates for such periods.

Approximately [removed: 42.0%] [added: 37.8%] of our total estimated proved reserves as of December 31, [removed: 2016,] [added: 2017,] were proved undeveloped reserves and may not be ultimately developed or produced.

to a high of $110.62 per Bbl in September 2013.

The counterparty is required to make a payment

| • | crude oil swap contracts priced at a weighted average price of $54.89 Brent for 1,830,000 aggregate Bbls; |

Our business operations have grown substantially since our initial public offering in October 2012 and we expect our business operations to continue to grow in the future.

Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels.

have evaluated or are evaluating various other aspects of hydraulic fracturing.

operations and materially increase our operating and capital costs.

Recently enacted U.S. tax legislation as well as future U.S. tax legislations may adversely affect our business, results of operations, financial condition and cash flow.

On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Ac, which we refer to as the Tax Act, that significantly reforms the Internal Revenue Code of 1986, as amended, which we refer to as the Code.

Among other changes, the Tax Act (i) reduces the maximum U.S. corporate income tax rate from 35% to 21%, (ii) preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling, (iii) allows for immediate expensing of capital expenditures for tangible personal property for a period of time, (iv) modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations and (v) enacts new limitations regarding the deductibility of interest expense.

The Tax Act is complex and far-reaching, and we cannot predict with certainty the resulting impact its enactment will have on us.

The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional

regulatory guidance that may be issued, and any such changes in our interpretations and assumptions could have an adverse effect on our business, results of operations, financial condition and cash flow.

While these specific changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be.

However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States.

The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice.

It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement.

Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves.

Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital.

insured.

for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

Our ability to acquire additional properties and to

affect our net income.

On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% Senior Notes due 2025, which we refer to as the new 2025 notes, as additional notes under our existing indenture, and repaid $308.5 million of our outstanding borrowings under the revolving credit facility with the net proceeds from the issuance of our new 2025 notes.

Immediately following the issuance of the new 2025 notes and the application of our net proceeds thereof, we had total long-term debt of $1.39 billion (including $1.3 billion attributable to all of our outstanding senior notes), our borrowing base remained $1.8 billion (as the lenders waived the borrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion, and we had $911.4 million of available borrowing capacity under our revolving credit facility.

On January 29, 2018, we repaid $308.5 million of our outstanding borrowings under the revolving credit facility with the net proceeds from the issuance of our new 2025 notes.

Immediately following the issuance of the new 2025 notes and the application of our net proceeds thereof, our borrowing base remained $1.8 billion (as the lenders waived the borrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion, and we had $911.4 million of available borrowing capacity under our revolving credit facility.

If we are unable to generate such cash flow, we may be required to adopt one or more

As of December 31, 2017, we had $397.0 million borrowings outstanding under our revolving credit facility.

Our weighted average interest rate on borrowings under our revolving credit facility was 2.97% on December 31, 2017.

In the past, we have engaged in transactions with affiliated companies and may do so again in the future.

without regard to specific operating performance.

The declaration of dividends on our common stock is within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends in the future or at levels anticipated by our stockholders.

On February 13, 2018, we announced that we are initiating an annual cash dividend in the amount of $0.50 per share of our common stock payable quarterly beginning with the first quarter of 2018.

The decision to pay this first dividend or any future dividends, however, is solely within the discretion of, and subject to approval by, our board of directors.

Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.

Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns to our stockholders.

If we were to experience an “ownership change,” as determined under Section 382 of the Code, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially.

Risks Related to the Pending Acquisition

We may not consummate the Pending Acquisition.

We intend to use the net proceeds from our December 2016 underwritten offering of common stock, together with the net proceeds from our concurrent offering of the 2025 Senior Notes, cash on hand and other financing sources, to fund the cash consideration for the Pending Acquisition, as described under “Item 1.

Business and Properties-Our Pending Acquisition.” However, we may not consummate the Pending Acquisition, which is subject to the satisfaction of customary closing conditions.

There can be no assurance that such conditions will be satisfied or that the Pending Acquisition will be consummated.

If the Pending Acquisition is consummated, we may be unable to successfully integrate the acquired properties or to realize anticipated revenues or other benefits of the Pending Acquisition.

Our ability to achieve the anticipated benefits of the Pending Acquisition will depend in part upon whether we can integrate the acquired properties into our existing businesses in an efficient and effective manner.

We may not be able to accomplish this integration process successfully.

The successful acquisition of producing properties, including those to be acquired in the Pending Acquisition, requires an assessment of several factors, including:

| | |

| --- | --- |

| • | recoverable reserves; |

| • | future natural gas and oil prices and their appropriate differentials; |

| • | availability and cost of transportation of production to markets; |

| • | availability and cost of drilling equipment and of skilled personnel; |

| • | development and operating costs and potential environmental and other liabilities; |

| • | regulatory, permitting and similar matters; and |

| • | our ability to obtain external financing to fund the purchase price. |

The accuracy of these assessments is inherently uncertain.

In connection with these assessments, we have performed a review of the subject properties that we believe to be generally consistent with industry practices.

Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken.

Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies.

The integration process may be subject to delays or changed circumstances, and we can give no assurance that the acquired properties will perform in accordance with our expectations.

Significant acquisitions, including the Pending Acquisition, and other strategic transactions may involve other risks that may cause our business to suffer, including:

| • | diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions; and |

| • | the failure to realize the full benefit that we expect in estimated proved reserves, production volume or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame. |

We will incur significant transaction and acquisition-related costs in connection with the Pending Acquisition.

We expect to incur significant costs associated with the Pending Acquisition and integration and/or development of the assets subject to the Pending Acquisition as part of our operations.

The substantial majority of the expenses resulting from the Pending Acquisition will be composed of transaction costs related to the Pending Acquisition and the costs involved in financing of the Pending Acquisition.

We may also incur transaction fees and costs related to formulating integration and/or development plans for the assets subject to the Pending Acquisition.

Fraudulent conveyance laws may allow courts, under specific circumstances, to void the Pending Acquisition and require the seller to return the consideration received for the Pending Acquisition.

The Pending Acquisition may be subject to claims that it should be limited, subordinated or voided under applicable law in favor of the seller.

These laws include those that relate to fraudulent conveyance or transfer, voidable preference, financial assistance, corporate purpose or benefit, preservation of share capital, thin capitalization and defenses affecting the rights of creditors generally.

In general, under fraudulent conveyance and similar laws, a court might void or otherwise decline to enforce the Pending Acquisition if it found that when we entered into the Pending Acquisition, the seller received less than reasonably equivalent value or fair consideration for the Pending Acquisition and one of the following is true:

| • | the seller was insolvent or rendered insolvent by reason of the consummation of the Pending Acquisition; |

| • | the seller was engaged in a business or transaction for which its remaining assets constituted unreasonably small capital; |

| • | the seller intended to, or believed or reasonably should have believed that it would, incur debts beyond its ability to pay such debts as they mature; or |

| • | the seller was a defendant in an action for money damages, or had a judgment for money damages docketed against it if, in either case, after final judgment, the judgment is unsatisfied (as all of the foregoing terms may be defined in or interpreted under the relevant fraudulent transfer or conveyance statutes). |

A court might also void the Pending Acquisition without regard to the above factors if such court found that the seller consummated the Pending Acquisition with actual intent to hinder, delay or defraud its creditors.

The measures of insolvency applied by courts will vary depending upon the particular fraudulent transfer law applied in any proceeding to determine whether a fraudulent transfer has occurred.

| | [removed: 2016] [added: 2017] | | | [removed: 2015] [added: 2016] | | | [removed: 2014] [added: 2015] | |

| Oil [removed: (Bbls) | 73 | % |] [added: (Bbls)/d] | [removed: 75] [added: 58,678] | [removed: %] | [added: 31,590] | [removed: 76] | [removed: %] [added: 24,880] |

| Natural gas [removed: (Mcf)] [added: (MMcf)] | [removed: 11] [added: 12] | % | | 11 | % | | [removed: 10] [added: 11] | % |

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

[removed: 2016] [added: 2017] Transactions and Recent Developments

[removed: Our] [added: Viper] Equity Offerings

In [removed: January 2016, we] [added: July 2017, Viper] completed an underwritten public offering of [removed: 4,600,000 shares of] [added: 16,100,000] common [removed: stock,] [added: units,] which included [removed: 600,000 shares of] [added: 2,100,000] common [removed: stock] [added: units] issued pursuant to an option to purchase additional [removed: shares] [added: common units] granted to the [removed: underwriter.][added: underwriters.]

[removed: The stock was sold to the underwriter at $55.33 per share and we] [added: Viper] received [added: net] proceeds [removed: of approximately $254.5 million] from [removed: the sale of these shares of common stock, net of] [added: this] offering [removed: expenses and] [added: of approximately $232.5 million, after deducting] underwriting discounts and [removed: commissions,] [added: commissions and estimated offering expenses, of] which [removed: we] [added: Viper] used [added: $152.8 million] to repay [added: all of] the [added: then-outstanding] borrowings [removed: outstanding] under [removed: our] [added: Viper’s] revolving credit facility and [added: the balance was used] to fund a portion of [removed: our exploration and development activities] [added: the purchase price for acquisitions] and for general [removed: corporate] [added: partnership] purposes.

We [removed: intend to use these net proceeds, together with] [added: used] the net proceeds from our [removed: offering of the 2025 senior notes,] [added: December 2016 equity offering, net proceeds from our December 2016 debt offering,] cash on hand and other financing [removed: sources,] [added: sources] to fund the cash [removed: consideration for] [added: portion of] the [removed: Pending Acquisition.][added: purchase price for this acquisition.]

Following this [removed: public] offering, we had an approximate [removed: 83%] [added: 64%] limited partner interest in Viper.

Viper received [added: net] proceeds from this offering of approximately [removed: $125.0] [added: $147.5] million, [removed: net of estimated offering expenses and] [added: after deducting] underwriting discounts and [removed: commissions,] [added: commissions and estimated offering expenses, of] which Viper used [added: $120.5 million] to repay [added: the] outstanding borrowings under [removed: Viper’s] [added: its] revolving credit [removed: facility] [added: agreement] and [removed: fund] the [removed: acquisition of mineral interests.][added: balance was used for general partnership purposes, which included additional acquisitions.]

On [removed: December 20, 2016,] [added: January 29, 2018,] we [removed: completed an offering of $500.0] [added: issued $300.0] million [removed: in] aggregate principal amount of [removed: our] [added: new] 5.375% senior notes due 2025, which we refer to as the [added: new] 2025 [removed: senior notes.][added: notes, as additional notes under the 2025 Indenture.]

Our [removed: Recent] [added: Delaware Basin] Acquisition

We are operating [removed: six] [added: ten] rigs now and currently intend to operate between [removed: six and] ten [added: and twelve] drilling rigs in [removed: 2017] [added: 2018] across our asset base in the Midland and Delaware Basins.

We plan to operate [removed: four to] six [added: to seven] of these rigs in the Midland Basin targeting horizontal development of the Wolfcamp and Spraberry formations, [removed: while the remainder of the] [added: with four to five] rigs are expected to operate in the Delaware Basin targeting the Wolfcamp and Bone Spring [removed: formations following the closing of our Pending Acquisition, which is expected to occur in February 2017.][added: formations.]

In doing so, we are focused on controlling oilfield service costs as our service providers seek to increase pricing [removed: after two years of declining service costs during the downturn] [added: following continued strength] in the oil market.

Our [removed: 2017] [added: 2018] drilling and completion budget [removed: includes amount] [added: accounts for rising capital costs] that we believe will cover potential increases in our service costs during the year.

[removed: 2017] [added: 2018] Capital Budget

We have currently budgeted a [removed: 2017] [added: 2018] total capital spend of [removed: $800.0 million] [added: $1.3 billion] to [removed: $1.0] [added: $1.5] billion, consisting of [removed: $650.0 million] [added: $1.175 billion] to [removed: $825.0 million] [added: $1.325 billion] for horizontal drilling and completions including non-operated activity and [removed: $150.0] [added: $125.0] million to $175.0 million for infrastructure and other expenditures, but excluding the cost of any leasehold and mineral interest acquisitions.

We expect to drill and complete [removed: 130] [added: 170] to [removed: 165] [added: 190] gross horizontal wells in [removed: 2017.][added: 2018.]

| | [removed: 2016] [added: 2017] | | [removed: 2015] [added: 2016] | | [removed: 2014] [added: 2015] |

| Natural Gas (Mcf)/d | [removed: 29,313] [added: 56,602] | | [removed: 21,729] [added: 29,313] | | [removed: 11,907] [added: 21,729] |

| Natural Gas Liquids (Bbls)/d | [removed: 6,556] [added: 11,112] | | [removed: 4,596] [added: 6,556] | | [removed: 2,745] [added: 4,596] |

| Total average production per day | [removed: 43,031] [added: 79,224] | | [removed: 33,098] [added: 43,031] | | [removed: 19,474] [added: 33,098] |

Our average daily production for the year ended December 31, [removed: 2016] [added: 2017] as compared to the year ended December 31, [removed: 2015] [added: 2016] increased [removed: 9,933] [added: by 36,193] BOE/d, or [removed: 30%.][added: 84%.]

During the year ended December 31, [removed: 2016,] [added: 2017,] we drilled [removed: 73] [added: 150] gross [removed: (61] [added: (130] net) horizontal wells and [removed: two gross (one net) vertical wells and] participated in the drilling of [removed: 19] [added: 16] gross [removed: (five] [added: (two] net) non-operated [added: horizontal] wells in the Permian Basin.

Ryder Scott prepared estimates of our proved reserves at December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014] [added: 2015] (which include estimated proved reserves attributable to Viper).

| Natural gas liquids [removed: (Bbls)] [added: (MBbls)] | [removed: 37,134,000] [added: 54,610] | | | [removed: 26,004,144] [added: 37,134] | | | [removed: 18,541,932] [added: 26,004] | |

| | [removed: 2016 | | |] [added: 2017] | [removed: 2015] | | [added: 2016] | | [removed: 2014] | [added: 2015] | |

| Oil (per Bbl) | $ | [removed: 39.94] [added: 48.03] | | | $ | [removed: 45.07] [added: 39.94] | | | $ | [removed: 87.15] [added: 45.07] | |

| Natural gas (per Mcf) | $ | [removed: 1.36] [added: 2.06] | | | $ | [removed: 1.83] [added: 1.36] | | | $ | [removed: 4.85] [added: 1.83] | |

| Natural gas liquids (per Bbl) | $ | [removed: 12.91] [added: 20.79] | | | $ | [removed: 12.56] [added: 12.91] | | | $ | [removed: 30.09] [added: 12.56] | |

| Oil sales | [removed: 89] [added: 88] | % | | [removed: 91] [added: 89] | % | | 91 | % |

| Natural gas sales | 4 | % | | 4 | % | | [removed: 3] [added: 4] | % |

| Natural gas liquid sales | [removed: 7] [added: 8] | % | | [removed: 5] [added: 7] | % | | [removed: 6] [added: 5] | % |

During [removed: 2016,] [added: 2017,] WTI posted prices ranged from [removed: $26.19] [added: $42.48] to [removed: $54.01] [added: $60.46] per Bbl and the Henry Hub spot market price of natural gas ranged from [removed: $1.49] [added: $2.44] to [removed: $3.80] [added: $3.71] per MMBtu.

On December [removed: 30, 2016,] [added: 29, 2017,] the WTI posted price for crude oil was [removed: $53.75] [added: $60.46] per Bbl and the Henry Hub spot market price of natural gas was [removed: $3.71] [added: $3.69] per MMBtu.

[added: Where available, we benefit] from tax credits and exemptions in our various taxing jurisdictions.

| Oil, natural gas liquids and natural gas | $ | [removed: 527,107] [added: 1,186,275] | | | $ | [removed: 446,733] [added: 527,107] | | | $ | [removed: 495,718] [added: 446,733] | |

| Lease operating expenses | [removed: 82,428] [added: 126,524] | | | | [removed: 82,625] [added: 82,428] | | | | [removed: 55,384] [added: 82,625] | | |

| Oil (MBbls) | 74 | % | | 73 | % | | 75 | % |

On December 31, 2017, our acreage position in the Permian Basin was approximately 246,012 gross (206,660 net) acres, which consisted of approximately 117,586 gross (101,941 net) acres in the Northern Midland Basin and approximately 128,426 gross (104,719 net) acres in the Southern Delaware Basin.

On February 28, 2017, we completed an acquisition of oil and natural gas properties, midstream assets and other related assets in the Delaware Basin for an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of our common stock, of which approximately 1.15 million shares were placed in an indemnity escrow.

This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million.

New Senior Notes

We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes.

We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.

In this offering, we purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of our Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters.

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

We are currently operating six rigs on the acreage and expect to average approximately six to eight operated rigs in 2018.

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

Additionally, we have successfully completed additional wells targeting such zones as the Wolfcamp B and 2nd Bone Spring, and expect to test these zones further in 2018.

We are currently operating four rigs in the Delaware Basin and plan to average approximately four to five rigs in 2018.

| Oil (MBbls) | 233,181 | | | 139,174 | | | 105,979 | |

| Natural gas (MMcf) | 285,369 | | | 174,896 | | | 149,503 | |

| Total (MBOE) | 335,352 | | | 205,458 | | | 156,899 | |

| | 2017 | | | | 2016 | | | | 2015 | | |

| | 2017 | | | 2016 | | | 2015 | |

Midstream services expense.

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

| | 2017 | | | | 2016 | | | | 2015 | | |

| Lease bonus | 11,764 | | | | — | | | | — | | |

| Midstream services | 7,072 | | | | — | | | | — | | |

| Total revenues | 1,205,111 | | | | 527,107 | | | | 446,733 | | |

| Midstream services | 10,409 | | | | — | | | | — | | |

| | 2017 | | | | 2016 | | | | 2015 | | |

| Oil (MBbls) | 21,418 | | | | 11,562 | | | | 9,081 | | |

| Natural gas (MMcf) | 20,660 | | | | 10,728 | | | | 7,931 | | |

| Natural gas liquids (MBbls) | 4,056 | | | | 2,399 | | | | 1,678 | | |

| Combined volumes (MBOE) | 28,917 | | | | 15,749 | | | | 12,081 | | |

| Natural gas, hedged ($ per MMbtu)(1) | 2.65 | | | | 2.06 | | | | 2.47 | | |

| Oil | $ | 8.05 | | | 21,418 | | | | $ | 172,403 | |

| Natural gas liquids | $ | 8.00 | | | 4,056 | | | | $ | 32,446 | |

| Natural gas | $ | 0.43 | | | 20,660 | | | | $ | 8,884 | |

| Oil | 9,856 | | | | $ | 40.70 | | | $ | 401,080 | |

| Natural gas liquids | 1,656 | | | | $ | 14.20 | | | $ | 23,521 | |

| Natural gas | 9,931 | | | | $ | 2.10 | | | $ | 20,834 | |

Lease Bonus Revenue.

Lease bonus revenue was $11.8 million for the year ended December 31, 2017, $2.8 million of which was attributable to lease bonus payments to extend the term of seven leases, reflecting an average bonus of $3,442 per acre and the remaining $9.1 million was attributable to lease bonus payments on three new leases, reflecting an average bonus of $14,320 per acre.

We had no lease bonus revenue for the year ended December 31, 2016.

On December 31, 2016, our net acreage position in the Permian Basin was approximately 105,894 net acres.

In July 2016, we completed an underwritten public offering of 6,325,000 shares of common stock, which included 825,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters.

The stock was sold to the underwriters at $87.24 per share and we received proceeds of approximately $551.8 million from the sale of these shares of common stock, net of estimated offering expenses and underwriting discounts and commissions, which we used to fund a portion of the purchase price for the acquisition of certain leasehold interests and related assets in the Southern Delaware Basin.

In December 2016, we completed an underwritten public offering of 12,075,000 shares of common stock, which included 1,575,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters.

The stock was sold to the underwriters at $95.3025 per share and we received proceeds of approximately $1,150.8 million from the sale of these shares of common stock, net of estimated offering expenses and underwriting discounts and commissions.

Viper’s Equity Offerings

In August 2016, Viper completed an underwritten public offering of 8,050,000 common units, which included 1,050,000 common units issued pursuant to an option to purchase additional common units granted to the underwriter.

In this offering, we purchased 2,000,000 common units from the underwriter at $15.60 per unit, which is the price per common unit paid by the underwriter to Viper.

Following the January 2017 public offering, we had an approximate 74% limited partner interest in Viper.

Viper received net proceeds from this offering of approximately $147.6 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which Viper used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and intends to use the remaining net proceeds for general partnership purposes, which may include additional acquisitions.

Senior Note Transactions

On October 28, 2016, we completed an offering of $500.0 million in aggregate principal amount of our 4.75% senior notes due 2024, which we refer to as the 2024 senior notes.

We received approximately $496.0 million in net proceeds from the offering of the 2024 senior notes, which were used primarily to repurchase all of our outstanding 7.625% senior notes due 2021, which we refer to as the 2021 senior notes, accepted for purchase in a related tender offer, to pay fees and expenses thereof and to redeem the 2021 senior notes that remained outstanding after completion of the tender offer discussed below.

We intend to use the remaining net proceeds from the offering of the 2024 senior notes for general corporate purposes, which may include the funding of a portion of the our capital development plans.

On October 21, 2016, we commenced a cash tender offer to purchase any and all of our 2021 senior notes, which tender offer expired on October 27, 2016 and settled on October 28, 2016.

An aggregate of $330.1 million principal amount of the 2021 senior notes was validly tendered in the tender offer.

The remaining 2021 senior notes that were not tendered in the tender offer were redeemed by us, and the indenture governing the 2021 senior notes was fully satisfied and discharged.

The cash tender offer for the 2021 senior notes and redemption of the remaining 2021 senior notes were funded with a portion of the net proceeds from the offering of the 2024 senior notes.

We received approximately $495.8 million in net proceeds from the offering of the 2025 senior notes, which we intend to use, together with the net proceeds from our December 2016 underwritten public offering of common stock, cash on hand and other financing sources, to fund the cash consideration for the Pending Acquisition.

On September 1, 2016, we acquired from an unrelated third party leasehold interests and related assets in the Southern Delaware Basin for an aggregate purchase price of $558.5 million.

This transaction included approximately 26,797 gross (19,262 net) acres primarily in Reeves and Ward counties, 19 gross producing vertical wells, 11 gross producing horizontal wells, saltwater disposal and gathering infrastructure and other related assets.

We estimate that there are 290 net potential horizontal drilling locations across four zones with an average lateral length of approximately 9,500 feet on this acreage.

We financed this acquisition with the net proceeds of the July 2016 equity offering discussed above and cash on hand.

Our Pending Acquisition

On December 13, 2016, we entered into a definitive purchase and sale agreement with Brigham to acquire certain assets of Brigham, for aggregate consideration consisting of a purchase price of $1.62 billion in cash and the issuance of 7.69 million shares of our common stock to Brigham, subject to certain adjustments.

See Item 1.

“Business and Properties-Our Pending Acquisition” for additional information regarding this transaction.

Recent Acquisitions by Viper

During 2016, Viper acquired mineral interests underlying 61,679 gross (2,142 net royalty) acres in 63 transactions for an aggregate of approximately $205.7 million.

Viper funded these acquisitions primarily with borrowings under its revolving credit facility and a portion of the net proceeds from its August 2016 offering of common units.

In the Midland Basin, we have drilled and completed multiple pads in Glasscock County with significant positive results and we anticipate continuing active development on this acreage with one rig in 2017, assuming commodity prices remain steady or increase further.

We have also drilled and completed three three-well pads in Howard County targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B formations with positive results, and plan to continue to operate one rig in this area.

The remainder of our rigs in the Midland Basin will focus on our core development area in Midland County as well as our acreage in Southwest Martin County and Northeast Andrews County targeting the Spraberry and Wolfcamp formations.

In the Delaware Basin, we are currently drilling our first operated well in Ward County, and plan to operate one rig consistently on this acreage through 2017 targeting the Wolfcamp and Bone Spring formations.

After the closing of our Pending Acquisition, which is expected to occur in February 2017, we plan to operate between one and three rigs on that asset targeting the Wolfcamp and Bone Spring formations as well.

| Oil (Bbls)/d | 31,590 | | 24,880 | | 14,744 |

| Oil (Bbls) | 139,174,000 | | | 105,978,711 | | | 75,689,589 | |

| Natural gas (Mcf) | 174,896,000 | | | 149,502,744 | | | 111,605,260 | |

| Total (BOE) | 205,457,333 | | | 156,899,979 | | | 112,832,398 | |

Where available, we benefit

We use price swap derivatives, including basis [removed: swaps,] [added: swaps and costless collars,] to reduce price volatility associated with certain of our oil and natural gas sales.

Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX [removed: WTI.][added: WTI and Crude Oil Brent and with natural gas derivative settlements based on NYMEX Henry Hub.]

At December 31, [added: 2017 and] 2016, we had a net liability derivative position of [removed: $22.6] [added: $106.7] million [removed: related to our price swap] and [removed: price basis swap derivatives, as compared to a net asset derivative position of $4.6 million as of December 31, 2015] [added: $22.6 million, respectively,] related to our price swap and price basis swap derivatives.

Utilizing actual derivative contractual volumes under our fixed price swaps and fixed price basis swaps as of December 31, [removed: 2016,] [added: 2017,] a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to [removed: $40.7] [added: $180.2] million, an increase of [removed: $18.0] [added: $74.1] million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position to [removed: $4.6] [added: $32.1] million, a decrease of [removed: $18.0] [added: $74.1] million.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately [removed: $49.5] [added: $73.0] million at December 31, [removed: 2016)] [added: 2017)] and receivables from the sale of our oil and natural gas production (approximately [removed: $70.6] [added: $158.6] million at December 31, [removed: 2016).][added: 2017).]

For the year ended December 31, [removed: 2014, two] [added: 2017, three] purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company [removed: (64%);] [added: (31%); Koch Supply & Trading LP (19%);] and Enterprise Crude Oil LLC [removed: (16%).][added: (11%).]

At December 31, 2016, we had three [removed: customers] [added: customer] that represented approximately 75% of our total joint operations receivables.

At December 31, [removed: 2015,] [added: 2017,] we had [removed: five customer] [added: three customers] that represented approximately [removed: 73%] [added: 74%] of our total joint operations receivables.

[removed: The applicable margin ranges from 0.50% to 1.50% in the case of the] alternative base rate and from [removed: 1.50%] [added: 1.25%] to [removed: 2.50%] [added: 2.25%] in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base.

As of December 31, [removed: 2016,] [added: 2017,] we had [removed: no] [added: $397.0 million] borrowings outstanding under our revolving credit facility.

Our weighted average interest rate on borrowings under our revolving credit facility was [removed: 1.92% on January 19, 2016, the last day] [added: 2.97%] on [removed: which borrowings were outstanding under such facility.][added: December 31, 2017.]

[added: An] increase [added: or decrease of 1%] in [added: the interest rate would have a corresponding decrease or increase in] our interest expense of approximately [removed: $0.1] [added: $4.0] million based on the [removed: $11.0] [added: $397.0] million outstanding in the aggregate under our revolving credit facility as of such date.

The applicable margin ranges from 0.25% to 1.25% in the case of the

An increase or decrease of 1% in the interest rate would have a corresponding decrease or

At December 31, [removed: 2016,] [added: 2017,] our total [removed: net] acreage position in the Permian Basin was approximately [removed: 105,894 net] [added: 246,012 gross (206,660 net)] acres.

In addition, we, through our subsidiary Viper Energy Partners LP, or Viper, own mineral interests underlying approximately [removed: 107,568] [added: 247,602] gross [removed: (6,404] [added: acres, 43,843] net [removed: royalty)] acres [added: and 9,570 net royalty acres] primarily in Midland County, Texas in the Permian Basin.

Approximately [removed: 41%] [added: 36%] of these net [added: royalty] acres are operated by us.

We own Viper Energy Partners GP LLC, the general partner of Viper, which we refer to as the general partner, and we own approximately [removed: 74%] [added: 64%] of the limited partner interest in Viper.

As of December 31, [removed: 2016,] [added: 2017,] our estimated proved oil and natural gas reserves were [removed: 205,457] [added: 335,352] MBOE (which includes estimated reserves of [removed: 31,435] [added: 38,246] MBOE attributable to the mineral interests owned by Viper), based on reserve reports prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers.

Of these reserves, approximately [removed: 57.9%] [added: 62.2%] are classified as proved developed producing.

Proved undeveloped, or PUD, reserves included in this estimate are from [removed: 120] [added: 168] gross [removed: (102] [added: (142] net) horizontal well locations in which we have a working interest, and [removed: 14] [added: nine] horizontal wells in which we own only a mineral interest through our subsidiary, Viper.

As of December 31, [removed: 2016,] [added: 2017,] our estimated proved reserves were approximately [removed: 68%] [added: 70%] oil, [removed: 18%] [added: 14%] natural gas liquids and [removed: 14%] [added: 16%] natural gas.

Based on our evaluation of applicable geologic and engineering data, we currently have approximately [removed: 2,722] [added: 3,800] gross [removed: (1,802] [added: (2,750] net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately [removed: $50.00] [added: $60.00] per Bbl WTI.

The challenging commodity price environment that we experienced in [removed: 2015] [added: 2016] continued in [removed: 2016, with the posted price of WTI reaching a 12-year low of $26.19 per barrel on February 11, 2016.][added: 2017.]

Commodity prices improved during [removed: 2016,] [added: 2017,] but continued to be volatile.

During [removed: 2016,] [added: 2017,] we again demonstrated our operational focus on achieving best-in-class execution, low-cost operations and a conservative balance sheet as we continued to reduce drilling days, well costs and operating expenses while maintaining what we believe to be a peer leading leverage ratio.

We intend to continue our operational focus in [removed: 2017,] [added: 2018,] emphasizing full cycle economics and financial discipline.

We are operating [removed: six] [added: ten] rigs now and currently intend to operate between [removed: six and] ten [added: and twelve] rigs in [removed: 2017] [added: 2018,] depending on market conditions.

We have the option to release up to [removed: three] [added: eight] of our current [removed: six] [added: ten] rigs in [removed: 2017] [added: 2018] should commodity prices deteriorate.

| • | Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We have targeted various intervals in the Midland Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. Our initial horizontal focus had been on the Wolfcamp B interval, but our recent focus has included the Lower Spraberry, Middle Spraberry and Wolfcamp A intervals. Our first two horizontal wells were completed in 2012 and had lateral lengths of less than 4,000 feet. As of December 31, [removed: 2016,] [added: 2017,] we had drilled [removed: 261] [added: 412] horizontal wells as operator and had participated in [removed: 44] [added: 61] additional horizontal wells as a non-operator, including two in which we own only a minor wellbore interest. We also acquired interest in [removed: 23] [added: 76] horizontal wells on properties we purchased. Of these [removed: 328] [added: 549] total horizontal wells, [removed: 277] [added: 466] had been completed and were on production. Of the [removed: 277] [added: 466] horizontal wells on production, [removed: 130] [added: 152] are in the Wolfcamp B interval, [removed: 31] [added: 122] are in the Wolfcamp A interval, [removed: 101] [added: 163] are in the Lower Spraberry interval, [removed: seven] [added: nine] are in the Middle Spraberry interval, three are in the Cline interval, three are in the Clearfork [added: interval, seven are in the Bone Spring] interval and [removed: two] [added: seven] are in [removed: the Devonian interval.] [added: various other intervals.] These wells have lateral lengths ranging from approximately [removed: 2,312] [added: 2,100] feet to [removed: 12,903] [added: 13,000] feet. In [removed: 2017,] [added: 2018,] we expect that our average lateral length will be about [removed: 8,000] [added: 9,300] feet, although the actual length will vary depending on the layout of our acreage and other factors. As technology continues to improve, we expect that our average lateral length will increase, resulting in higher per well recoveries and lower development costs per BOE. During the year ended December 31, [removed: 2016,] [added: 2017,] we were able to drill our horizontal wells [added: in the Midland Basin] with approximately 7,500 foot lateral lengths to total depth, or TD, in an average of [removed: 12.3] [added: 12.2] days and we drilled [removed: an] approximately 10,000 foot lateral [removed: well] [added: wells] in [removed: 14.3] [added: 14.5] days. Further advances in drilling and completion technology may result in economic development of zones that are not currently viable. |

We are the operator of approximately [removed: 98%] [added: 84%] of [removed: our] [added: this Permian Basin] acreage.

| • | Pursue strategic acquisitions with substantial resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential. Our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We regularly review acquisition opportunities and intend to pursue acquisitions that meet our strategic and financial targets. During the year ended December 31, [removed: 2016,] [added: 2017,] we acquired approximately [removed: 27,182] [added: 99,830] gross [removed: (19,943] [added: (84,468] net) leasehold acres primarily in [removed: Reeves, Ward and] Pecos [added: and Reeves] counties in the Southern Delaware Basin. [removed: We have also entered into a definitive purchase and sale agreement with Brigham for a transaction that we expect to complete by the end of February 2017. See “–Our Pending Acquisition” above.] |

| • | Maintain financial flexibility. We seek to maintain a conservative financial position. In connection with our fall [removed: 2016] [added: 2017 borrowing base] redetermination, the agent lender under our revolving credit agreement recommended a borrowing base of [removed: $1.0] [added: $1.8] billion. We elected a commitment amount of [removed: $500.0 million,] [added: $1.0 billion,] of which [removed: $500.0] [added: $603.0] million was available for borrowing as of December 31, [removed: 2016.] [added: 2017.] As of December 31, [removed: 2016,] [added: 2017,] Viper had [removed: $120.5] [added: $93.5] million in outstanding borrowings, and [removed: $154.5] [added: $306.5] million available for borrowing, under its revolving credit facility. [removed: In January 2017, Viper repaid its outstanding borrowings in full with a portion of the net proceeds from its public offering of common units.] |

| • | Oil rich resource base in one of North America’s leading resource plays. All of our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the Permian Basin. Our production for the year ended December 31, [removed: 2016] [added: 2017] was approximately [removed: 73%] [added: 74%] oil, [removed: 16%] [added: 14%] natural gas liquids and [removed: 11%] [added: 12%] natural gas. As of December 31, [removed: 2016,] [added: 2017,] our estimated net proved reserves were comprised of approximately [removed: 68%] [added: 70%] oil, [removed: 18%] [added: 14%] natural gas liquids and [removed: 14%] [added: 16%] natural gas. |

[removed: | • | Multi-year drilling inventory in one of North America’s leading oil resource plays. We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed price of approximately $50.00 per Bbl WTI, we currently have approximately 2,722 gross (1,802 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data. These gross identified economic potential horizontal locations have an average lateral length of approximately 8,600 feet, with the actual length depending on lease geometry and other considerations. These locations exist across most of our acreage blocks and in multiple horizons. Of these 2,722 locations, 2,223 are in the Midland Basin and 499 are in the Delaware Basin. The Delaware Basin locations do not include locations attributable to the Pending Acquisition. In the Midland Basin, 1,018 are in the Lower Spraberry or Wolfcamp B horizons where we have drilled a large number of wells, 805 are in the Wolfcamp A or Middle Spraberry horizons where we have drilled a limited number of wells and 355 are in the Clearfork or Cline horizons where we have drilled very few wells. Our current location count for the Lower Spraberry horizon is based on 500 foot spacing in the Spanish Trail property in Midland County and 660 foot spacing in other areas of Midland, Martin, northeast Andrews, Howard and Glasscock counties, and 880 foot spacing in all other counties. For the Wolfcamp B horizon, the horizontal location count is based on 660 foot spacing between wells in Midland, Martin, northeast Andrews, Howard, and Glasscock counties, and 880 foot spacing in all other counties. In the Wolfcamp A horizon, the horizontal location count in based on 660 foot spacing in Howard and Glasscock counties, 880 foot spacing in Reeves, Ward and Pecos counties, 880 foot spacing in Midland and southwest Martin counties and 1,320 foot spacing in other counties. The horizontal location count for the Middle Spraberry is based on 880 foot spacing in Midland, Martin and northeast Andrews counties and 1,320 foot spacing in other counties. In the Cline and Clearfork horizons, the horizontal location count is based on 1,320 foot spacing except for the Clearfork in central Andrews County which is based on 660 foot spacing. In the Delaware Basin, 303 locations are in the Wolfcamp A or Wolfcamp B horizons, and 196 locations are in the 2nd Bone Spring or 3rd Bone Spring horizon. The horizontal location counts are based on 880 foot spacing in the Wolfcamp A and Wolfcamp B horizons, and 1,320 foot spacing in the Bone Spring horizons. The ultimate inter- |][added: | • | Multi-year drilling inventory in one of North America’s leading oil resource plays. We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 3,800 gross (2,750 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data. These gross identified economic potential horizontal locations have an average lateral length of approximately 8,400 feet, with the actual length depending on lease geometry and other considerations. These locations exist across most of our acreage blocks and in multiple horizons. Of these 3,800 locations, 2,100 are in the Midland Basin and 1,700 are in the Delaware Basin. In the Midland Basin, 860 are in the Lower Spraberry or Wolfcamp B horizons where we have drilled a large number of wells, 825 are in the Wolfcamp A or Middle Spraberry horizons where we have drilled a limited number of wells and 415 are in the Clearfork or Cline horizons where we have drilled very few wells. Our current location count for the Lower Spraberry horizon is based on 660 foot spacing in f Midland, southwest Martin, northeast Andrews, Howard and Glasscock counties, and 880 foot spacing in all other counties. For the Wolfcamp B horizon, the horizontal location count is based on 660 foot spacing between wells in Midland, Martin, northeast Andrews, Howard, and Glasscock counties, and 880 foot spacing in all other counties. In the Wolfcamp A horizon, the horizontal location count in based on 660 foot spacing in Midland, Howard and Glasscock counties, 880 foot spacing in southwest Martin county and 1,320 foot spacing in other counties. The horizontal location count for the Middle Spraberry is based on 880 foot spacing in Midland, Martin and northeast Andrews counties and 1,320 foot spacing in other counties. In the Cline and Clearfork horizons, the horizontal location count is based on 1,320 foot spacing except for the Clearfork in central Andrews County which is based on 660 foot spacing. In the Delaware Basin, 1,240 locations are in the Wolfcamp A or Wolfcamp B horizons, and 460 locations are in the 2nd Bone Spring or 3rd Bone Spring horizon. The horizontal location counts are based on 880 foot spacing in the Wolfcamp A and Wolfcamp B horizons, and 1,320 foot spacing in the Bone Spring horizons. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count. The two-stream gross estimated ultimate recoveries, or EURs, from our future PUD horizontal wells, as estimated by Ryder Scott as of December 31, 2017, range from 528 MBOE per well, consisting of 413 MBbls of oil and 687 MMcf of natural gas, to 1,665 MBOE per well, consisting of 1,307 MBbls of oil and 2,150 MMcf of natural gas, for wells ranging in lateral length from approximately 5,000 feet to approximately 12,500 feet, in intervals including the Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B. Ryder Scott has estimated gross EURs of 910 MBOE for our Lower Spraberry wells in Midland County and 1,071 MBOE for our Wolfcamp A wells in Pecos County, which constitute 36% of our remaining PUD horizontal wells, in each case based on 7,500 foot lateral lengths. In addition, we have approximately 1,837 square miles of proprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including additional horizontal drilling opportunities and strategic leasehold acquisitions. |]

| • | High degree of operational control. We are the operator of approximately [removed: 98%] [added: 84%] of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of our acreage, we retain the ability to increase or decrease our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects. |

Our total [removed: net] acreage position in the Permian Basin was approximately [removed: 105,894 net] [added: 246,012 gross (206,660 net)] acres at December 31, [removed: 2016.][added: 2017.]

In addition, we, through our subsidiary Viper, own mineral interests underlying approximately [removed: 107,568] [added: 247,602] gross [removed: (6,404] [added: acres, 43,843] net [removed: royalty)] acres [added: and 9,570 net royalty acres] primarily in [removed: Midland County, Texas in] the Permian Basin.

Since our initial acquisition in the Permian Basin through December 31, [removed: 2016,] [added: 2017,] we drilled or participated in the drilling of [removed: 585] [added: 753] gross [removed: (474] [added: (608] net) wells on our leasehold acreage in this area, primarily targeting the Wolfberry play.

Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, [added: Bone Spring,] Wolfcamp, Cline, Strawn and Atoka formations.

As of December 31, [removed: 2016,] [added: 2017,] we held working interests in [removed: 998] [added: 1,166] gross [removed: (792) net] [added: (937 net)] producing [added: wells and royalty interests in 64 additional] wells.

The Permian Basin formed as an area of rapid [removed: Mississippian-Pennsylvanian] [added: Pennsylvanian-Permian] subsidence in [removed: the foreland of the Ouachita fold belt.][added: response to dynamic structural influence.]

It is one of the largest sedimentary basins in the U.S., [removed: and has] [added: with established] oil and gas production from several reservoirs from Permian through Ordovician in age.

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

The Spraberry/Bone Spring was deposited as [added: siliciclastic] turbidites in a deep water submarine fan environment, while the Wolfcamp reservoirs consist of debris-flow and grain-flow sediments, which were also deposited in a submarine fan setting.

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

Our extensive geophysical database currently includes approximately [removed: 871] [added: 1,837] square miles of 3-D data.

During the year ended December 31, [removed: 2016,] [added: 2017,] net production from our Permian Basin acreage was [removed: 15,749,436 BOE,] [added: 28,917 MBOE,] or an average of [removed: 43,031] [added: 79,224] BOE/d, of which approximately [removed: 73%] [added: 74%] was oil, [removed: 16%] [added: 14%] was natural gas liquids and [removed: 11%] [added: 12%] was natural gas.

[added: Recent and] Future Activity

During [removed: 2017,] [added: 2018,] we expect to [removed: drill] [added: complete] an estimated [removed: 130] [added: 170] to [removed: 165] [added: 190] gross [removed: (110] [added: (146] to [removed: 140] [added: 163] net) horizontal wells on our acreage.

We currently estimate that our capital expenditures in [removed: 2017] [added: 2018] for drilling and infrastructure will be between [removed: $800.0 million] [added: $1.3 billion] and [removed: $1.0] [added: $1.5] billion, consisting of [removed: $650.0 million] [added: $1.175 billion] to [removed: $825.0 million] [added: $1.325 billion] for horizontal drilling and completions including non-operated activity and [removed: $150.0] [added: $125.0] million to $175.0 million for infrastructure and other expenditures, but excluding the cost of any leasehold and mineral rights acquisitions.

During the year ended December 31, [removed: 2016,] [added: 2017,] we drilled [removed: 73] [added: 150] gross [removed: (61] [added: (130] net) and completed [removed: 62] [added: 123] gross [removed: (54] [added: (105] net) horizontal [removed: wells.][added: wells, including five drilled but uncompleted wells we acquired.]

We [removed: drilled and completed two gross (one net) vertical wells and] participated in the drilling of [removed: 19] [added: 16] gross [added: (two net) non-operated horizontal wells in the Permian Basin.]

During the year ended December 31, [removed: 2016,] [added: 2017,] our capital expenditures for drilling, completing and equipping wells were [removed: $310.0] [added: $719.3] million.

| • | Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. Our acreage position in the Wolfberry play is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately 84% of our acreage. This operational control allows us to manage more efficiently the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development. Our average 84% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies. |

Approximately 36% of these net royalty acres are operated by us.

the Permian Spraberry, Dean and Wolfcamp formations.

The shales exhibit low permeabilities which necessitate the need for hydraulic fracture stimulation to unlock the vast storage of hydrocarbons in these targets.

This data will continue to be utilized in the development of our horizontal drilling program and identification of additional resource to be exploited.

We are operating ten rigs now and currently intend to operate between ten and twelve rigs in 2018, depending on market conditions.

We have the option to release up to eight of our current ten rigs in 2018 should commodity prices deteriorate.

| | | | | | | | | |

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

| | | | | | | | | |

| Oil (MBbls) | 141,246 | | | 79,457 | | | 60,569 | |

| Natural gas (MMcf) | 190,740 | | | 105,399 | | | 96,871 | |

| Total (MBOE) | 208,447 | | | 119,104 | | | 92,132 | |

| Oil (MBbls) | 91,935 | | | 59,717 | | | 45,409 | |

| Natural gas (MMcf) | 94,629 | | | 69,497 | | | 52,632 | |

| Natural gas liquids (MBbls) | 19,198 | | | 15,054 | | | 10,586 | |

| Total (MBOE) | 126,905 | | | 86,354 | | | 64,767 | |

| Oil (MBbls) | 233,181 | | | 139,174 | | | 105,979 | |

| Natural gas (MMcf) | 285,369 | | | 174,896 | | | 149,503 | |

| Total (MBOE)(1) | 335,352 | | | 205,458 | | | 156,899 | |

| Revisions | (4,710 | ) |

| Net purchases | 6,246 | |

Of the 87 gross wells, 26 were in the Delaware Basin.

We own a working interest in 23 of the 27 gross Viper wells.

Net purchases of 6,246 MBOE were primarily from our purchase in Pecos and Reeves counties.

Downward revisions of 4,710 MBOE resulted from reclassification of seven locations and technical revisions.

| Oil (MBbls) | 21,418 | | | | 11,562 | | | | 9,081 | | |

| Natural gas (MMcf) | 20,660 | | | | 10,728 | | | | 7,931 | | |

| Natural gas liquids (MBbls) | 4,056 | | | | 2,399 | | | | 1,678 | | |

| Combined volumes (MBOE) | 28,917 | | | | 15,749 | | | | 12,081 | | |

| Natural gas, hedged ($ per MMbtu)(1) | 2.65 | | | | 2.06 | | | | 2.47 | | |

| Delaware | 58,444 | | | 49,919 | | | 69,982 | | | 54,800 | | | 128,426 | | | 104,719 | |

| Midland | 84,325 | | | 69,641 | | | 33,261 | | | 32,300 | | | 117,586 | | | 101,941 | |

| Total | 142,769 | | | 119,560 | | | 103,243 | | | 87,100 | | | 246,012 | | | 206,660 | |

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

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

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

| Delaware | 28,572 | | | 22,198 | | | 31,091 | | | 19,415 | | | 13,097 | | | 1,286 | | | 3,639 | | | 719 | | | — | | | — | |

| Midland | 897 | | | 715 | | | 908 | | | 255 | | | 19,678 | | | 18,933 | | | — | | | — | | | — | | | — | |

| Total | 29,469 | | | 22,913 | | | 31,999 | | | 19,670 | | | 32,775 | | | 20,219 | | | 3,639 | | | 719 | | | — | | | — | |

Our Pending Acquisition

On December 13, 2016, we entered into a definitive purchase and sale agreement with Brigham Resources Operating, LLC and Brigham Resources Midstream, LLC, or together, Brigham, to acquire certain assets of Brigham, for aggregate consideration consisting of $1.62 billion in cash and the issuance of 7.69 million shares of our common stock to Brigham, subject to certain adjustments.

We refer to this transaction as the Pending Acquisition.

The assets, located in Pecos and Reeves counties

in Texas include over 93,761 gross (76,319 net) acres, approximately 9,500 BOE/d (77% oil) of average net production for November 2016, based on production, completion and flowback data provided by Brigham that has not been verified by us, from 48 gross producing horizontal wells and 16 gross producing vertical wells.

The assets are also estimated to include six drilled but uncompleted wells as of January 1, 2017.

Based on our internal estimates and the data provided by Brigham, we believe the assets include approximately 1,149 net royalty acres.

Additionally, based on publicly available data with respect to recent horizontal wells on and surrounding the properties, we believe the assets are prospective for four primary targets: Wolfcamp A, Wolfcamp B, the 3rd Bone Spring and the 2nd Bone Spring.

We believe that development potential within the footprint of the Pending Acquisition includes 1,213 net identified economic potential horizontal locations, based on 880\-foot spacing (six wells per section) in the Wolfcamp A and Wolfcamp B and 1,320\-foot inter-lateral spacing (four wells per section) in the 3rd Bone Spring and 2nd Bone Spring.

Additional development and downspacing potential may exist throughout the Wolfcamp and Bone Spring intervals.

We believe that the identified potential horizontal locations are conducive to more capital efficient longer laterals with an average of approximately 8,500 feet.

Assuming all of the acreage in the Pending Acquisition is acquired, our total leasehold interest as of December 31, 2016 would have been approximately 182,000 net acres.

The foregoing data and estimates are based primarily on information provided to us by Brigham.

We have not yet verified these results and estimates and cannot assure you that actual results will not differ.

See Item 1A “Risk Factors-Risks Related to the Pending Acquisition” for a discussion of these risks.

| • | Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. Our acreage position in the Wolfberry play is |

generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities.

This operational control allows us to manage more efficiently the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development.

Our average 79% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies.

well spacing may vary from these distances due to different factors, which would result in a higher or lower location count.

The two-stream gross estimated ultimate recoveries, or EURs, from our future PUD horizontal wells, as estimated by Ryder Scott as of December 31, 2016, range from 494 MBOE per well, consisting of 366 MBbls of oil and 769 MMcf of natural gas, to 1,273 MBOE per well, consisting of 995 MBbls of oil and 1,667 MMcf of natural gas, for wells ranging in lateral length from approximately 7,500 feet to approximately 10,000 feet, in intervals including the Clearfork, Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B.

Ryder Scott has estimated gross EURs of 620 MBOE for our Wolfcamp B wells in Midland County and 998 MBOE for our Lower Spraberry wells in Midland County, which constitute 47% of our remaining PUD horizontal wells, in each case based on 7,500 foot lateral lengths.

In addition, we have approximately 871 square miles of proprietary 3-D seismic data covering our acreage.

This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including additional horizontal drilling opportunities and strategic leasehold acquisitions.

We are the operator of approximately 98% of this Permian Basin acreage.

We refer to the Clearfork, Spraberry, Wolfcamp, Strawn and Atoka formations collectively as the Wolfberry play.

The Wolfberry play of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp play.

The shales exhibit micro-darcy permeabilities which result in relatively small drainage areas and recovery factors, so relatively small inter-well spacing is necessary.

This data will continue to be utilized in the development of our horizontal drilling activities and to identify and avoid potential geohazards (e.g., faults and lithologies that are difficult to drill).

(five net) non-operated horizontal wells in the Permian Basin.

We spent an additional $817.0 million for leasehold and mineral rights acquisitions.

staff has an average of approximately 24 years of industry experience per person.

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

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

| Oil (Bbls) | | | | 79,457,000 | | | 60,569,398 | | | 43,885,835 | |

| Natural gas (Mcf) | | | | 105,399,000 | | | 96,871,109 | | | 68,264,113 | |

| Total (BOE) | | | | 119,103,500 | | | 92,132,936 | | | 66,484,615 | |

| Oil (Bbls) | | | | 59,717,000 | | | 45,409,313 | | | 31,803,754 | |

| Natural gas (Mcf) | | | | 69,497,000 | | | 52,631,635 | | | 43,341,147 | |

| Natural gas liquids (Bbls) | | | | 15,054,000 | | | 10,585,791 | | | 7,320,504 | |

10-K 1 [removed: diamondback201610-k.htm] [added: diamondback201710-k.htm] DIAMONDBACK 10-K

For the fiscal year ended December 31, [removed: 2016][added: 2017]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, [removed: or] a smaller reporting [added: company, or an emerging growth] company.

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, [removed: 2016] [added: 2017] was approximately [removed: $4,475,534,237.][added: $7,801,460,276.]

As of February [removed: 13, 2017, 90,143,934] [added: 7, 2018, 98,167,289] shares of the registrant’s common stock were outstanding.

Portions of Diamondback Energy, Inc.’s Proxy Statement for the [removed: 2017] [added: 2018] Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K

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

FOR THE YEAR ENDED DECEMBER 31, [removed: 2016][added: 2017]

| [Glossary of Oil and Natural Gas [removed: Terms](#s6CB86D279CDC5943B4C9B6A6420A4348)] [added: Terms](#sFC261EDB341153FFAAB194EDDB89BA93)] | [removed: [ii](#s6CB86D279CDC5943B4C9B6A6420A4348)] [added: [ii](#sFC261EDB341153FFAAB194EDDB89BA93)] |

| [Glossary of Certain Other [removed: Terms](#s5372D9CC2C355C07B63C07A8AE4A4CB6)] [added: Terms](#sFC00CAD20140550D9F3A129268A31C26)] | [removed: [v](#s5372D9CC2C355C07B63C07A8AE4A4CB6)] [added: [v](#sFC00CAD20140550D9F3A129268A31C26)] |

| [Cautionary Statement Regarding Forward-Looking [removed: Statements](#s839EC7B4C9C25A37B656F2A051642181)] [added: Statements](#sF8A74953C3585FB983D697046683B30B)] | [removed: [vi](#s839EC7B4C9C25A37B656F2A051642181)] [added: [vi](#sF8A74953C3585FB983D697046683B30B)] |

| [Items 1 and 2. Business and [removed: Properties](#s3955C188A7E3511698E393B8632AD0D5)] [added: Properties](#s1DB6A2CF161C578DA65DE52F54DBF8B3)] | [removed: [1](#s3955C188A7E3511698E393B8632AD0D5)] [added: [1](#s1DB6A2CF161C578DA65DE52F54DBF8B3)] |

| [Item 1A. Risk [removed: Factors](#s4761C5246AC95C66ACF6A6FCF7CECC75)] [added: Factors](#s7BE1F9F2028E5EE39DC1D7A225121E1A)] | [removed: [20](#s4761C5246AC95C66ACF6A6FCF7CECC75)] [added: [21](#s7BE1F9F2028E5EE39DC1D7A225121E1A)] |

| [Item 1B. Unresolved Staff [removed: Comments](#s1024A98C1A9C5D50A9056BF24F188D81)] [added: Comments](#s84A06DF571B65E13BA60590BA959EE66)] | [removed: [46](#s1024A98C1A9C5D50A9056BF24F188D81)] [added: [45](#s84A06DF571B65E13BA60590BA959EE66)] |

| [Item 3. Legal [removed: Proceedings](#s685B7BFECCF45F48A029906928870F9A)] [added: Proceedings](#s86A40CD43C765F3E941262D8FDC98782)] | [removed: [46](#s685B7BFECCF45F48A029906928870F9A)] [added: [45](#s86A40CD43C765F3E941262D8FDC98782)] |

| [Item 4. Mine Safety [removed: Disclosures](#sC1B3483C6FC353DD9DE6BA958725A76D)] [added: Disclosures](#s0BB46837F9EB53B9B1700CAC4F19FB62)] | [removed: [46](#sC1B3483C6FC353DD9DE6BA958725A76D)] [added: [45](#s0BB46837F9EB53B9B1700CAC4F19FB62)] |

| [Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity [removed: Securities](#s283729EC353E570EBA4B07ED8E5C10B4)] [added: Securities](#s90781501D156551893CEA681956A868F)] | [removed: [47](#s283729EC353E570EBA4B07ED8E5C10B4)] [added: [46](#s90781501D156551893CEA681956A868F)] |

| [Item 6. Selected Financial [removed: Data](#sB379095B36255C7A9D0F656CD8585534)] [added: Data](#sBE138A1BAC045F4DA2B09DF61FEDEA84)] | [removed: [48](#sB379095B36255C7A9D0F656CD8585534)] [added: [47](#sBE138A1BAC045F4DA2B09DF61FEDEA84)] |

| [Item 7. Management's Discussion and Analysis of Financial Condition and Results of [removed: Operations](#sCB678B66074053828A2FD23E748786E5)] [added: Operations](#sCD76B6E3558853B39B2387525D55C57F)] | [removed: [51](#sCB678B66074053828A2FD23E748786E5)] [added: [49](#sCD76B6E3558853B39B2387525D55C57F)] |

| [Item 7A. Quantitative and Qualitative Disclosures about Market [removed: Risk](#s557F5DA2A6F6555E8B40D493CC8DB0CC)] [added: Risk](#s4457E30CF3685723B126E82D7862C5AF)] | [removed: [72](#s557F5DA2A6F6555E8B40D493CC8DB0CC)] [added: [70](#s4457E30CF3685723B126E82D7862C5AF)] |

| [Item 8. Financial Statements and Supplementary [removed: Data](#sCC4CE2E9DC5B59F0863D8BF84D066069)] [added: Data](#s453116CB11F352A3BEB3B5E29FF82919)] | [removed: [73](#sCC4CE2E9DC5B59F0863D8BF84D066069)] [added: [71](#s453116CB11F352A3BEB3B5E29FF82919)] |

| [Item 9. Changes in and Disagreements with Accountants on Accounting and Financial [removed: Disclosure](#sCEFD47209EE45F428E409454D447420A)] [added: Disclosure](#sE50DAC2960405482877D61B33DC74FEF)] | [removed: [73](#sCEFD47209EE45F428E409454D447420A)] [added: [71](#sE50DAC2960405482877D61B33DC74FEF)] |

| [Item 9A. Controls and [removed: Procedures](#s05F17184E6FE51178D4FD88BEF650FFB)] [added: Procedures](#s606796D27457578C9BDBD9EEDB577E62)] | [removed: [73](#s05F17184E6FE51178D4FD88BEF650FFB)] [added: [71](#s606796D27457578C9BDBD9EEDB577E62)] |

| [Item 9B. Other [removed: Information](#s2E314D81C6A95BC499C9ED039DB00D1A)] [added: Information](#s9E8035A0A6175A3EA8624A2FD3D14C95)] | [removed: [76](#s2E314D81C6A95BC499C9ED039DB00D1A)] [added: [74](#s9E8035A0A6175A3EA8624A2FD3D14C95)] |

| [Item 10. Directors, Executive Officers and Corporate [removed: Governance](#sC14B1B1A8ED551DD93B5AC3C6670C891)] [added: Governance](#s4AF35A532E1B58AEAB3FCA97D2CED79A)] | [removed: [76](#sC14B1B1A8ED551DD93B5AC3C6670C891)] [added: [74](#s4AF35A532E1B58AEAB3FCA97D2CED79A)] |

| [Item 11. Executive [removed: Compensation](#s1BA388207A045F888DCD340637D3ED24)] [added: Compensation](#s1D65F9831FE55069B013C6FE82E81BD6)] | [removed: [76](#s1BA388207A045F888DCD340637D3ED24)] [added: [74](#s1D65F9831FE55069B013C6FE82E81BD6)] |

| [Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder [removed: Matters](#s3A945F89E3E75325A100F29FA62BCF9E)] [added: Matters](#s7F2275B3124253AFBD7DDB1A48AAB04D)] | [removed: [76](#s3A945F89E3E75325A100F29FA62BCF9E)] [added: [74](#s7F2275B3124253AFBD7DDB1A48AAB04D)] |

| [Item 13. Certain Relationships and Related Transactions, and Director [removed: Independence](#sBB547B88BFD852E892DF32B189B9EC46)] [added: Independence](#sB29FB793F2DD5B01B19433BCAF98F71C)] | [removed: [76](#sBB547B88BFD852E892DF32B189B9EC46)] [added: [74](#sB29FB793F2DD5B01B19433BCAF98F71C)] |

| [Item 14. Principal Accountant Fees and [removed: Services](#s073B6FF5F7885D8FBFAE013859D2FC75)] [added: Services](#s4CBF25B9CD285473804E2045A6CD6037)] | [removed: [76](#s073B6FF5F7885D8FBFAE013859D2FC75)] [added: [74](#s4CBF25B9CD285473804E2045A6CD6037)] |

| [Item 15. Exhibits and Financial Statement [removed: Schedules](#s6A71459B2971544CB634565024A986AA)] [added: Schedules](#s7A12F5F0649F5D11842ABE7FA72B0A68)] | [removed: [77](#s6A71459B2971544CB634565024A986AA)] [added: [74](#s7A12F5F0649F5D11842ABE7FA72B0A68)] |

| | | | | Emerging Growth Company | | o |

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

| [Item 16. Form 10-K Summary](#s852aec8ee38d4648a3d469cf03190719) | [80](#s852aec8ee38d4648a3d469cf03190719) |

| [Signatures](#sC4833FBCD5B65609845C3E9F4B57E645) | [S-1](#sC4833FBCD5B65609845C3E9F4B57E645) |

| Net royalty acres | Gross acreage multiplied by the average royalty interest. |

| | | | | | | |

| [Signatures](#sDA553B085BA95ACCBFC890231B782F4F) | [S-1](#sDA553B085BA95ACCBFC890231B782F4F) |

| Index to Consolidated Financial Statements | |

| [Exhibit Index](#s60FF430D88AA56489106BF63A8389A12) | [E-1](#s60FF430D88AA56489106BF63A8389A12) |

| 2021 Indenture | The indenture relating to the 2021 Senior Notes, dated as of September 18, 2013, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented. |

| Muskie | Muskie Proppant LLC. |

| 2021 Senior Notes | The Company’s 7.625% senior unsecured notes due 2021 in the aggregate principal amount of $450 million. |

There were [removed: six] [added: nine] holders of record of our common stock on February [removed: 13, 2017.][added: 9, 2018.]

| 2017 | | | | | | | |

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

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

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

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

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

On February 13, 2018, we announced that we are initiating an annual cash dividend in the amount of $0.50 per share of our common stock payable quarterly beginning with the first quarter of 2018.

The decision to pay this first dividend or any future dividends, however, is solely within the discretion of, and subject to approval by, our board of directors.

Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.

| 2015 | | | | | | | |

| 1st Quarter | $ | 78.75 | | | $ | 55.53 | |

| 2nd Quarter | $ | 85.82 | | | $ | 73.36 | |

| 3rd Quarter | $ | 77.36 | | | $ | 60.28 | |

| 4th Quarter | $ | 82.19 | | | $ | 61.51 | |

“Management’s Discussion and Analysis of Financial Condition and Results of Operations–Liquidity and Capital Resources–Credit Facility.” We currently intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.

The historical financial data for the years ended December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014] [added: 2015] and the balance sheet data as of December 31, [removed: 2016] [added: 2017] and [removed: 2015] [added: 2016] are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

The historical financial data for the year ended December 31, [removed: 2013] [added: 2014] and [removed: 2012] [added: 2013] and the balance sheet data as of December 31, [removed: 2014, 2013] [added: 2015, 2014] and [removed: 2012] [added: 2013] are derived from our audited financial statements not included in this Annual Report on Form 10-K.

| (In thousands, except per share amounts) | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | | | [removed: 2013] [added: 2014] | | | | [removed: 2012(1)] [added: 2013] | | |

| Total revenues | $ | [removed: 527,107] [added: 1,205,111] | | | $ | [removed: 446,733] [added: 527,107] | | | $ | [removed: 495,718] [added: 446,733] | | | $ | [removed: 208,002] [added: 495,718] | | | $ | [removed: 74,962] [added: 208,002] | |

| Total costs and expenses | [removed: 595,724] [added: 600,091] | | | | [removed: 1,187,002] [added: 595,724] | | | | [removed: 283,048] [added: 1,187,002] | | | | [removed: 112,808] [added: 283,048] | | | | [removed: 57,655] [added: 112,808] | | |

| Income (loss) from operations | [added: 605,020 | | | |] (68,617 | | ) | | (740,269 | | ) | | 212,670 | | | | 95,194 | | | [removed: | 17,307 | | |]

| Other income (expense) | [added: (107,831 | | ) | |] (96,099 | | ) | | (8,831 | | ) | | 92,286 | | | | (8,853 | | ) | [removed: | 1,075 | | |]

| Income (loss) before income taxes | [added: 497,189 | | | |] (164,716 | | ) | | (749,100 | | ) | | 304,956 | | | | 86,341 | | | [removed: | 18,382 | | |]

| Provision for (benefit from) income taxes | [added: (19,568 | | ) | |] 192 | | | | (201,310 | | ) | | 108,985 | | | | 31,754 | | | [removed: | 54,903 | | |]

| Net income (loss) | [added: 516,757 | | | |] (164,908 | | ) | | (547,790 | | ) | | 195,971 | | | | 54,587 | | | [removed: | (36,521 | | ) |]

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

| Net income (loss) attributable to Diamondback Energy, Inc. | $ | [removed: (165,034] [added: 482,261] | [removed: )] | | $ | [removed: (550,628] [added: (165,034] | ) | | $ | [removed: 193,755] [added: (550,628] | [added: )] | | $ | [removed: 54,587] [added: 193,755] | | | $ | [removed: (36,521] [added: 54,587] | [removed: )] |

| Basic | $ | [added: 4.95 | | | $ |] (2.20 | ) | | $ | (8.74 | ) | | $ | 3.67 | | | $ | 1.30 | | [removed: | | | |]

| Diluted | $ | [added: 4.94 | | | $ |] (2.20 | ) | | $ | (8.74 | ) | | $ | 3.64 | | | $ | 1.29 | | [removed: | | | |]

| Basic | [removed: 75,077] [added: 97,458] | | | | [removed: 63,019] [added: 75,077] | | | | [removed: 52,826] [added: 63,019] | | | | [removed: 42,015] [added: 52,826] | | | | [added: 42,015] | | |

| Diluted | [removed: 75,077] [added: 97,688] | | | | [removed: 63,019] [added: 75,077] | | | | [removed: 53,297] [added: 63,019] | | | | [removed: 42,255] [added: 53,297] | | | | [added: 42,255] | | |

| (In thousands) | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | | | [removed: 2013] [added: 2014] | | | | [removed: 2012(1)] [added: 2013] | | |

| Cash and cash equivalents | $ | [removed: 1,666,574] [added: 112,446] | | | $ | [removed: 20,115] [added: 1,666,574] | | | $ | [removed: 30,183] [added: 20,115] | | | $ | [removed: 15,555] [added: 30,183] | | | $ | [removed: 26,358] [added: 15,555] | |

| Net property and equipment | [removed: 3,390,857] [added: 7,343,617] | | | | [removed: 2,597,625] [added: 3,390,857] | | | | [removed: 2,791,807] [added: 2,597,625] | | | | [removed: 1,446,337] [added: 2,791,807] | | | | [removed: 554,242] [added: 1,446,337] | | |

| Total assets | [removed: 5,349,680] [added: 7,770,985] | | | | [removed: 2,750,719] [added: 5,349,680] | | | | [removed: 3,095,481] [added: 2,750,719] | | | | [removed: 1,521,614] [added: 3,095,481] | | | | [removed: 606,701] [added: 1,521,614] | | |

| Current liabilities | [removed: 209,342] [added: 577,428] | | | | [removed: 141,421] [added: 209,342] | | | | [removed: 266,729] [added: 141,421] | | | | [removed: 121,320] [added: 266,729] | | | | [removed: 79,232] [added: 121,320] | | |

| Long-term debt | [removed: 1,105,912] [added: 1,477,347] | | | | [removed: 487,807] [added: 1,105,912] | | | | [removed: 673,500] [added: 487,807] | | | | [removed: 460,000] [added: 673,500] | | | | [removed: 193] [added: 460,000] | | |

| Total [removed: Stockholders’/ Members’ equity(4)] [added: stockholders’/ members’ equity(1)] | [removed: 3,697,462] [added: 5,254,860] | | | | [removed: 1,875,972] [added: 3,697,462] | | | | [removed: 1,751,011] [added: 1,875,972] | | | | [removed: 845,541] [added: 1,751,011] | | | | [removed: 462,068] [added: 845,541] | | |

| Total equity | [removed: 4,018,292] [added: 5,581,737] | | | | [removed: 2,108,973] [added: 4,018,292] | | | | [removed: 1,985,213] [added: 2,108,973] | | | | [removed: —] [added: 1,985,213] | | | | — | | |

| Net cash provided by operating activities | $ | [removed: 332,080] [added: 888,625] | | | $ | [removed: 416,501] [added: 332,080] | | | $ | [removed: 356,389] [added: 416,501] | | | $ | [removed: 155,777] [added: 356,389] | | | $ | [removed: 49,692] [added: 155,777] | |

| Net cash used in investing activities | [removed: (1,310,242] [added: (3,132,282] | | ) | | [removed: (895,050] [added: (1,310,242] | | ) | | [removed: (1,481,997] [added: (895,050] | | ) | | [removed: (940,140] [added: (1,481,997] | | ) | | [removed: (183,078] [added: (940,140] | | ) |

| Net cash provided by financing activities | [removed: 2,624,621] [added: 689,529] | | | | [removed: 468,481] [added: 2,624,621] | | | | [removed: 1,140,236] [added: 468,481] | | | | [removed: 773,560] [added: 1,140,236] | | | | [removed: 152,785] [added: 773,560] | | |

| Consolidated Adjusted [removed: EBITDA(5)] [added: EBITDA(2)] | $ | [removed: 387,535] [added: 928,039] | | | $ | [removed: 449,245] [added: 387,535] | | | $ | [removed: 398,334] [added: 449,245] | | | $ | [removed: 157,604] [added: 398,334] | | | $ | [removed: 42,783] [added: 157,604] | |

| [removed: (4)] [added: (1)] | For the years ended December 31, [added: 2017,] 2016, 2015 and 2014, total stockholders’ equity excludes [added: $326.9 million,] $320.8 million, $233.0 million and $234.2 million, respectively, of non-controlling interest related to Viper Energy Partners LP. There was no equity related to non-controlling interest for the [removed: years] [added: year] ended December 31, [removed: 2013 and 2012.] [added: 2013.] |

| [removed: (5)] [added: (2)] | Consolidated Adjusted EBITDA is a supplemental non-GAAP financial measure. For our definition of Consolidated Adjusted EBITDA and a reconciliation of Consolidated Adjusted EBITDA to net income (loss) see “–Non-GAAP financial measure and reconciliation” below. |

We define Consolidated Adjusted EBITDA as net income (loss) plus [added: net] non-cash [added: (gain)] loss on derivative instruments, [removed: net,] [added: net] interest expense, depreciation, depletion and amortization expense, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, [added: loss on extinguishment of debt,] income tax (benefit) provision and non-controlling [removed: interest.][added: interest in net (income) loss.]

| (In thousands) | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | | | [removed: 2013] [added: 2014] | | | | [removed: 2012] [added: 2013] | | |

| Net income (loss) | $ | [removed: (164,908] [added: 516,757] | [removed: )] | | $ | [removed: (547,790] [added: (164,908] | ) | | $ | [removed: 195,971] [added: (547,790] | [added: )] | | $ | [removed: 54,587] [added: 195,971] | | | $ | [removed: (36,521] [added: 54,587] | [removed: )] |

| Non-cash (gain) loss on derivative instruments, net | [removed: 26,522] [added: 84,240] | | | | [removed: 112,918] [added: 26,522] | | | | [removed: (117,109] [added: 112,918] | | [removed: )] | | [removed: (5,346] [added: (117,109] | | ) | | [removed: (8,057] [added: (5,346] | | ) |

| Interest [removed: expense] [added: expense, net] | [removed: 40,684] [added: 40,554] | | | | [removed: 41,510] [added: 40,684] | | | | [removed: 34,515] [added: 41,510] | | | | [removed: 8,059] [added: 34,515] | | | | [removed: 3,610] [added: 8,059] | | |

| Depreciation, depletion and amortization | [removed: 178,015] [added: 326,759] | | | | [removed: 217,697] [added: 178,015] | | | | [removed: 170,005] [added: 217,697] | | | | [removed: 66,597] [added: 170,005] | | | | [removed: 26,273] [added: 66,597] | | |

| Impairment of oil and natural gas properties | [removed: 245,536] [added: —] | | | | [removed: 814,798] [added: 245,536] | | | | [removed: —] [added: 814,798] | | | | — | | | | — | | |

| Non-cash equity-based compensation expense | [removed: 33,532] [added: 34,178] | | | | [removed: 24,572] [added: 33,532] | | | | [removed: 14,253] [added: 24,572] | | | | [removed: 2,724] [added: 14,253] | | | | [removed: 3,482] [added: 2,724] | | |

| Capitalized equity-based compensation expense | [removed: (7,079] [added: (8,641] | | ) | | [removed: (6,043] [added: (7,079] | | ) | | [removed: (4,437] [added: (6,043] | | ) | | [removed: (972] [added: (4,437] | | ) | | [removed: (1,005] [added: (972] | | ) |

| Asset retirement obligation accretion expense | [removed: 1,064] [added: 1,391] | | | | [removed: 833] [added: 1,064] | | | | [removed: 467] [added: 833] | | | | [removed: 201] [added: 467] | | | | [removed: 98] [added: 201] | | |

| (In thousands) | 2017 | | | | 2016 | | | | 2015 | | | | 2014 | | | | 2013 | | |

| (In thousands) | 2017 | | | | 2016 | | | | 2015 | | | | 2014 | | | | 2013 | | |

| Pro forma information(2) | | | | | | | | | | | | | | | | | | | |

| Income before income taxes, as reported | | | | | | | | | | | | | | | | | $ | 18,382 | |

| Pro forma provision for income taxes | | | | | | | | | | | | | | | | | 6,553 | | |

| Pro forma net income | | | | | | | | | | | | | | | | | $ | 11,829 | |

| Pro forma earnings per common share(3) | | | | | | | | | | | | | | | | | | | |

| Basic | | | | | | | | | | | | | | | | | $ | 0.60 | |

| Diluted | | | | | | | | | | | | | | | | | $ | 0.60 | |

| | |

| --- | --- |

| (1) | The year ended December 31, 2012 reflects (a) the combined historical financial data of Windsor Permian LLC and Windsor UT LLC, which we sometimes refer to as the Predecessors, due to the transfer of a business between entities under common control and (b) the results of operations attributable to the acquisition of properties from Gulfport Energy Corporation beginning October 11, 2012, the closing date of the property acquisition. |

| (2) | Diamondback was formed as a holding company on December 30, 2011, and did not conduct any material business operations until October 11, 2012 when Diamondback merged with its parent entity, Diamondback Energy LLC, with Diamondback continuing as the surviving entity. Diamondback is a subchapter C corporation under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision for 2012 as if the Company and the Predecessors were subject to income taxes since December 31, 2011. The unaudited pro forma data is presented for informational purposes only, and does not purport to project our results of operations for any future period or our financial position as of any future date. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K. |

| (3) | The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued upon the merger of Diamondback Energy LLC into Diamondback were outstanding for the entire year. Diluted earnings per share reflects the potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock awards and units were fully vested. During periods in which the Company realizes a net loss, options and restricted stock awards would not be dilutive to net loss per share and conversion into common stock is assumed not to occur. |

As of December 31, [removed: 2016,] [added: 2017,] 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: 2016,] [added: 2017,] our disclosure controls and procedures are effective.

There have not been any changes in our internal control over financial reporting that occurred during the year ended December 31, [removed: 2016] [added: 2017] 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: 2016.][added: 2017.]

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: 2016.][added: 2017.]

The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, [removed: 2016,] [added: 2017,] 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: 2016,] [added: 2017,] based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial [added: reporting and for its assessment of the effectiveness of internal control over financial] reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting.

We conducted our audit in accordance with the standards of the [removed: Public Company Accounting Oversight Board (United States).][added: PCAOB.]

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, [removed: 2016,] [added: 2017,] based on [added: 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 [removed: States),] [added: States) (“PCAOB”),] the consolidated financial statements of the Company as of and for the year ended December 31, [removed: 2016,] [added: 2017,] and our report dated February [removed: 15, 2017] [added: 14, 2018] expressed an unqualified opinion on those financial statements.

Opinion on internal control over financial reporting

Basis for opinion

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Definition and limitations of internal control over financial reporting

February 14, 2018

February 15, 2017

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: 2016.][added: 2017.]

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: 2016.][added: 2017.]

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: 2016.][added: 2017.]

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: 2016.][added: 2017.]

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: 2016.][added: 2017.]

| | [Report of Independent Registered Public Accounting [removed: Firm](#s5EA600683F4C5A8EA2D6C1CDA3405EDD)] [added: Firm](#s822D57E140F554C7BEFF93D453B1AE90)] | [removed: [F-1](#s5EA600683F4C5A8EA2D6C1CDA3405EDD)] [added: [F-1](#s822D57E140F554C7BEFF93D453B1AE90)] |

| | [Consolidated Balance [removed: Sheets](#s6BEBAB95F7FC5C97B0AFDB3C989C57F4)] [added: Sheets](#s606E0FA6BC07594F84C6E482D4D64774)] | [removed: [F-2](#s6BEBAB95F7FC5C97B0AFDB3C989C57F4)] [added: [F-2](#s606E0FA6BC07594F84C6E482D4D64774)] |

| | [Consolidated Statements of [removed: Operations](#sC54F4F0B6C805022825379485F272A1E)] [added: Operations](#s277C69C474905CA7A5222BCFCD9F4BFA)] | [removed: [F-3](#sC54F4F0B6C805022825379485F272A1E)] [added: [F-3](#s277C69C474905CA7A5222BCFCD9F4BFA)] |

| | [Consolidated Statement of Stockholders' [removed: Equity](#s9C8417B535B652F096CF411751F31A62)] [added: Equity](#s995ABA84E5D4568C95549536355D36FB)] | [removed: [F-4](#s9C8417B535B652F096CF411751F31A62)] [added: [F-4](#s995ABA84E5D4568C95549536355D36FB)] |

| | [Consolidated Statements of Cash [removed: Flows](#s979D5ABB96BE57F6B485FC536B7ED5B6)] [added: Flows](#sB37BCEB203515A378B7E26879EBE54B6)] | [removed: [F-5](#s979D5ABB96BE57F6B485FC536B7ED5B6)] [added: [F-5](#sB37BCEB203515A378B7E26879EBE54B6)] |

| | [Notes to Consolidated Financial [removed: Statements](#sDD02E49A04FE56D1A5753FDC279B2DD1)] [added: Statements](#s463165B51A23527A86B0A9BE2E778E83)] | [removed: [F-7](#sDD02E49A04FE56D1A5753FDC279B2DD1)] [added: [F-7](#s463165B51A23527A86B0A9BE2E778E83)] |

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

| 2.1# | | [removed: Purchase] [added: [Purchase] and Sale Agreement dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, and FC Permian Properties, Inc., as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, [removed: 2014).] [added: 2014).](http://www.sec.gov/Archives/edgar/data/1539838/000119312514056306/d679610dex21.htm)] |

| 2.2# | | [removed: Purchase] [added: [Purchase] and Sale Agreement, dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, FC Permian Properties, Inc., Blake Braun, Richard D. Campbell, and Thomas J. Woodside, as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, [removed: 2014).] [added: 2014).](http://www.sec.gov/Archives/edgar/data/1539838/000119312514056306/d679610dex22.htm)] |

| 2.3# | | [removed: Purchase] [added: [Purchase] and Sale Agreement by and among Rio Oil and Gas, LLC, Rio Oil and Gas (Permian) LLC, Rio Oil and Gas (OPCO), LLC, Bluestem Energy, LP, Bluestem Energy Partners, LP, Bluestem Energy Holdings, LLC, Bluestem Energy Assets, LLC, Bluestem Acquisitions, LLC, BC Operating, Inc., Crown Oil Partners V, LP and Crump Energy Partners II, LLC, as sellers, and Diamondback E&P LLC, as buyer, dated July 18, 2014 (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on July 21, [removed: 2014).] [added: 2014).](http://www.sec.gov/Archives/edgar/data/1539838/000153983814000070/ex2_1purchaseandsaleagreem.htm)] |

| 2.4# | | [removed: Purchase] [added: [Purchase] and Sale Agreement, dated as of December 13, 2016, by and among Brigham Resources Operating, LLC and Brigham Resources Midstream, LLC, as sellers, and Diamondback E&P LLC and Diamondback Energy, Inc., as buyers (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 14, [removed: 2016).] [added: 2016).](http://www.sec.gov/Archives/edgar/data/1539838/000119312516793063/d265514dex21.htm)] |