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(1)

Reflects 867 gross and (809 net) identified potential vertical drilling locations on 40-acre spacing, and 862 gross (663 net) identified potential horizontal drilling locations ranging in length from 4,500 feet to 9,500 feet in various horizons from the Clearfork to the Cline based on our evaluation of applicable geologic and engineering data. Some of these horizontal drilling locations require pooling acreage with other operators. We have an additional 1,128 gross (1,031 net) identified potential vertical drilling locations based on 20-acre downspacing. The drilling locations on which we actually drill wells will ultimately depend on the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results and other factors.

(2)	Does not give effect to our pending acquisitions of approximately 11,150 additional net acres. See “—Recent Developments—Pending Acquisitions.”

(3)	Includes 38 gross (33 net) operated vertical wells, 33 gross (30 net) operated horizontal wells, two gross (one net) non-operated vertical wells and one gross (one net) non-operated horizontal well.

(4)	During June 2013.

•	$267.6 million for the drilling and completion of operated wells, of which approximately 65% is allocated to horizontal wells;

•	$9.0 million for our participation in the drilling and completion of non-operated wells; and

•	$25.0 million for the construction of infrastructure to support production, including investments in water disposal infrastructure and gathering line projects.

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Grow production and reserves by developing our oil-rich resource base. We intend to actively drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital. As of June 30, 2013, we had 867 identified potential vertical drilling locations and 862 identified potential horizontal drilling locations on our acreage in the Permian Basin based on 40-acre spacing and an additional 1,128 vertical locations based on 20-acre downspacing. We were operating a one vertical rig drilling program as of June 30, 2013, as we increase our focus on horizontal wells.

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Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We believe there are opportunities to target various intervals in the Wolfberry play with horizontal wells. Our initial horizontal focus has been on the Wolfcamp B interval in Midland and Upton Counties. Our first two horizontal wells were completed in 2012 and had lateral lengths of less than 4,000 feet. Subsequently, we have drilled or are currently drilling 17 horizontal wells as operator and have participated in one additional horizontal well as a non-operator, 19 of which are Wolfcamp B wells and one of which is a Clearfork well. These wells have had lateral lengths ranging from approximately 4,300 feet to 10,300 feet. In the future, we expect that our optimal average lateral lengths will be in the range of 7,500 feet to 8,000 feet, although the actual length will vary depending on the layout of our acreage and other factors. We expect that longer lateral lengths will result in higher per well recoveries and lower development costs per BOE. During the first six months of 2013, we were able to drill our horizontal wells with approximately 7,500 foot lateral lengths to total depth in an average of 21 days and we recently drilled a 10,353 foot lateral well in 19 days. Our future horizontal drilling program is designed to further capture the upside potential that may exist on our properties. We also believe our horizontal drilling program may significantly increase our recoveries per section as compared to drilling vertical wells alone. Horizontal drilling may also be economical in areas where vertical drilling is currently not economical or logistically viable. In addition, we believe increased well density opportunities may exist across our acreage base. We closely monitor industry trends with respect to higher well density, which could increase the recovery factor per section and enhance returns since infrastructure is typically in place. We were using three horizontal drilling rigs as of June 30, 2013, and currently intend to add a fourth horizontal rig in the fourth quarter of 2013, and are currently contemplating adding one or two additional horizontal drilling rigs in 2014.

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Leverage our experience operating in the Permian Basin. Our executive team, which has an average of approximately 24 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. The time to reach total depth, or TD, for our vertical Wolfberry wells decreased from an average of 18 days during the second quarter of 2011 to an average of 14 days during the period from April 2012 through August 2012 to an average of 11 days during the fourth quarter of 2012 to an average of eight days during the second quarter of 2013, with three of our recent vertical wells reaching TD in less than seven days. Our focus on efficient drilling and completion techniques, and the reduction in time to reach TD, is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. We believe that the experience of our executive team in deviated and horizontal drilling and completions should help reduce the execution risk normally associated with these complex well paths. In addition, our completion techniques are continually evolving as we evaluate hydraulic fracturing practices that may potentially increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.

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Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. In the current commodity price environment, our oil and liquids rich asset base provides attractive returns. 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 99% of our acreage. This operational control allows us to more efficiently manage 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 88% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies.

•	Pursue strategic acquisitions with exceptional resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential and can achieve attractive returns on invested capital. Our executive team, with its extensive experience in the Permian Basin, has

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Maintain financial flexibility. We seek to maintain a conservative financial position. Upon completion of our initial public offering in October 2012, we used a portion of the net proceeds from the offering to repay the entire balance outstanding under our revolving credit facility. On December 28, 2012, the borrowing base under our revolving credit facility was redetermined, resulting in an increase in our availability to $135.0 million, and it was redetermined again on May 6, 2013, resulting in an increase in availability to $180.0 million. We used a portion of the net proceeds of our May 2013 common stock offering to repay all borrowings outstanding under our revolving credit facility and, as of the date of this prospectus, we have the full $180.0 million of borrowing base availability.

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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 Wolfberry play. We believe that our historical vertical development success will be complemented with horizontal drilling locations that could ultimately translate into an increased recovery factor on a per section basis. Our production for the six months ended June 30, 2013 was approximately 73% oil, 15% natural gas liquids and 12% natural gas. As of December 31, 2012, our estimated net proved reserves were comprised of approximately 65% oil and 21% natural gas liquids, which allows us to benefit from the currently more favorable pricing of oil and natural gas liquids as compared to natural gas.

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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. As of June 30, 2013, we had 867 identified potential vertical drilling locations based on 40-acre spacing and an additional 1,128 identified potential vertical drilling locations based on 20-acre downspacing. We also believe that there are a significant number of horizontal locations that could be drilled on our acreage. Based on our initial results and those of other operators in the area to date, combined with our interpretation of various geologic and engineering data, we have identified 862 potential horizontal locations on our acreage. These locations exist across most of our acreage blocks and in multiple horizons. Of the 862 locations, 376 are in the Wolfcamp A horizon or the Wolfcamp B horizon, with the remaining locations in either the Clearfork, Spraberry, Wolfcamp C or Cline horizons. We have assigned horizontal locations to the Lower Spraberry, but have not assigned locations to other intervals within the Spraberry, which we believe may have development potential. Our current horizontal location count is based on 880 foot spacing between wells in the Wolfcamp B horizon in Midland and Upton Counties, and 1,320 foot spacing between wells in all other counties and horizons. The ultimate inter-well spacing may be less than these amounts, which would result in a higher location count. Based on horizontal wells drilled to date, we currently estimate that EURs for our Wolfcamp B horizontal wells will be approximately 550 to 650 MBOE for lateral lengths averaging 7,500 feet. In addition, we have approximately 182 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 horizontal drilling opportunities and strategic leasehold acquisitions.

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Experienced, incentivized and proven management team. Our executive team has an average of approximately 24 years of industry experience per person, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with both drilling and completing horizontal wells as well as horizontal well reservoir and geologic expertise, which will be of strategic importance as we expand our horizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.

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Favorable and stable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With approximately 380,000 wells drilled in the Permian Basin since the 1940s, we believe that the geological and regulatory environment is more stable and predictable, and that we are faced with less operational risks, in the Permian Basin as compared to emerging hydrocarbon basins.

•	High degree of operational control. We are the operator of approximately 99% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and

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Financial flexibility to fund expansion. We have a conservative balance sheet. We will seek to maintain financial flexibility to allow us to actively develop our drilling, exploitation and exploration activities in the Wolfberry play and maximize the present value of our oil-weighted resource potential. As of the date of this prospectus, we had no borrowings outstanding under our revolving credit facility and available borrowing capacity of $180.0 million. We expect that our borrowing base will be further increased as we increase our reserves.

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•	Our business is difficult to evaluate because of our limited operating history.

•	Difficulties managing the growth of our business may adversely affect our financial condition and results of operations.

•	Failure to develop our undeveloped acreage could adversely affect our future cash flow and income.

•	Our exploration and development operations require substantial capital that we may be unable to obtain, which could lead to a loss of properties and a decline in our reserves.

•	Our future success depends on our ability to find, develop or acquire additional oil and natural gas reserves.

•	The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

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

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

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

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

•	Any failure by us to comply with applicable environmental laws and regulations, including those relating to hydraulic fracturing, could result in governmental authorities taking actions that adversely affect our operations and financial condition.

•	Our operations are subject to operational hazards for which we may not be adequately insured.

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

•	Our two largest stockholders control a significant percentage of our common stock and their interests may conflict with yours.

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•	assumes the underwriters do not exercise their option to purchase additional shares of our common stock; and

•	excludes 2,500,000 shares of common stock reserved for issuance under our equity incentive plan, including:

•	245,716 restricted stock units issued to certain employees under the terms of their employment agreements;

•	33,330 restricted stock units issued to our non-employee directors as part of their director compensation; and

•	options to purchase 913,000 shares of our common stock granted to certain of our employees.

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(1)	The years ended December 31, 2011 and 2010 and the six months ended June 30, 2012 reflect the combined historical financial data of Windsor Permian LLC and Windsor UT LLC due to the transfer of a business between entities under common control. See Note 1 to our combined consolidated financial statements incorporated by reference into this prospectus.

(2)

The year ended December 31, 2012 reflects (a) the combined historical financial data of Windsor Permian LLC and Windsor UT LLC 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. See Note 1 and Note 2 to our combined consolidated financial statements incorporated by reference into this prospectus.

(3)

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 C-Corp 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. For 2011 and 2010 comparative purposes, we have included pro forma financial data to give effect to income taxes assuming the earnings of the Company and the Predecessors had been subject to federal income tax as a subchapter C corporation since inception. If the earnings of the Company and the Predecessors had been subject to federal income tax as a subchapter C corporation since inception, we would have incurred net operating losses for income tax purposes in each period. We would have been in a net deferred tax asset, or DTA, position as a result of such tax losses and would have recorded a valuation allowance to reduce each period’s DTA balance to zero. A valuation allowance to reduce each period’s DTA would have resulted in an equal and offsetting credit for the respective expenses or an equal and offsetting debit for the respective benefits for income taxes, with the resulting tax expenses for each 2011 and 2010 of zero. 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 1 to our combined consolidated financial statements incorporated by reference into this prospectus.

(4)

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. See Note 1 to our combined consolidated financial statements incorporated by reference into this prospectus.

(5)

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 and as if the common shares issued to Gulfport upon the closing of the Gulfport transaction 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. See Note 1 to our combined consolidated financial statements for the year ended December 31, 2012 incorporated by reference into this prospectus.

(6)	Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss), see “Selected Historical Combined Consolidated Financial Data” and “Unaudited Pro Forma Condensed Consolidated Financial Statement” beginning on pages 41 and 46, respectively, of this prospectus.

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(1)

Estimates of reserves as of December 31, 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2012, 2011 and 2010, respectively, in accordance with revised SEC guidelines applicable to reserve estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

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•	our proved reserves;

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

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

•	our ability to acquire, locate and produce new reserves.

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

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

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

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

•	the price of foreign imports;

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

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

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

•	the level of consumer product demand;

•	weather conditions and other natural disasters;

•	risks associated with operating drilling rigs;

•	technological advances affecting energy consumption;

•	domestic and foreign governmental regulations and taxes;

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

•	the proximity and capacity of oil and natural gas pipelines and other transportation facilities;

•	the price and availability of alternative fuels; and

•	overall domestic and global economic conditions.

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•	unusual or unexpected geological formations;

•	loss of drilling fluid circulation;

•	title problems;

•	facility or equipment malfunctions;

•	unexpected operational events;

•	shortages or delivery delays of equipment and services;

•	compliance with environmental and other governmental requirements; and

•	adverse weather conditions.

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•	a significant portion of our cash flows could be used to service our indebtedness;

•	a high level of debt could increase our vulnerability to general adverse economic and industry conditions;

•	the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

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

•	our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

•	a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

•	a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

•	incur additional indebtedness;

•	create additional liens;

•	sell assets;

•	merge or consolidate with another entity;

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•	pay dividends or make other distributions;

•	engage in transactions with affiliates; and

•	enter into certain swap agreements.

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

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

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

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•	our quarterly or annual operating results;

•	changes in our earnings estimates;

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

•	additions or departures of key personnel;

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

•	our failure to achieve operating results consistent with securities analysts’ projections;

•	changes in industry, general market or economic conditions; and

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•	announcements of legislative or regulatory changes.

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

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

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

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

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

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

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•	business strategy;

•	exploration and development drilling prospects, inventories, projects and programs;

•	expectations regarding the consummation of the pending acquisitions described under "Summary—Recent Developments—Pending Acquisitions";

•	oil and natural gas reserves;

•	identified drilling locations;

•	ability to obtain permits and governmental approvals;

•	technology;

•	financial strategy;

•	realized oil and natural gas prices;

•	production;

•	lease operating expenses, general and administrative costs and finding and development costs;

•	future operating results; and

•	plans, objectives, expectations and intentions.

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•	on an actual basis; and

•	as adjusted to give effect to the sale of 4,000,000 shares of our common stock in this offering, our receipt of an estimated $ million of net proceeds from this offering, after deducting underwriting discounts and commissions and estimated offering expenses, and the use of the net proceeds to fund the pending acquisitions as described under the caption “Use of Proceeds” on page 38.

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(1)	Represents the period from October 12, 2012, the date on which our common stock began trading on the NASDAQ Global Select Market, through December 31, 2012.

(2)	Through August 6, 2013.

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(1)	The years ended December 31, 2011 and 2010 and the six months ended June 30, 2012 reflect the combined historical

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(2)

The year ended December 31, 2012 reflects (a) the combined historical financial data of Windsor Permian LLC and Windsor UT LLC 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. See Note 1 and Note 2 to our combined consolidated financial statements incorporated by reference into this prospectus.

(3)

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 C-Corp 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. For 2011, 2010, 2009 and 2008 comparative purposes, we have included pro forma financial data to give effect to income taxes assuming the earnings of the Company and the Predecessors had been subject to federal income tax as a subchapter C corporation since inception. If the earnings of the Company and the Predecessors had been subject to federal income tax as a subchapter C corporation since inception, we would have incurred net operating losses for income tax purposes in each period. We would have been in a net deferred tax asset, or DTA, position as a result of such tax losses and would have recorded a valuation allowance to reduce each period’s DTA balance to zero. A valuation allowance to reduce each period’s DTA would have resulted in an equal and offsetting credit for the respective expenses or an equal and offsetting debit for the respective benefits for income taxes, with the resulting tax expenses for each 2011 and 2010 of zero. 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 1 to our combined consolidated financial statements incorporated by reference into this prospectus.

(4)

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. See Note 1 to our combined consolidated financial statements incorporated by reference into this prospectus.

(5)

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

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(a)	To record the operating results of the certain property interests of Gulfport Energy Corporation from the nine months ended September 30, 2012 to the closing date of the Gulfport transaction on October 11, 2012.

(b)	To record incremental accretion of discount of asset retirement obligations associated with the Gulfport transaction.

(c)	To record incremental depletion, depreciation, and amortization of oil and natural gas properties associated with the Gulfport transaction, amortized on a unit-of-production basis over the remaining life of total proved reserves.

(d)	To record the effects of the distribution of minority equity interests in Bison and Muskie to Windsor Permian’s sole member which occurred on June 15, 2012.

(e)

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 in connection with the Gulfport transaction (7,914,036 shares) and to DB Holdings in connection with the merger of Diamondback Energy LLC with and into Diamondback Energy, Inc. (14,697,496 shares) 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.

(a)

The pro forma financial data adjusts the Diamondback Energy, Inc. historical column to give effect to income taxes assuming the earnings of the Company had been subject to federal income tax as a subchapter C corporation since December 31, 2011, thus excluding the $54,142,000 charge relating to the change in tax status as of October 11, 2012. 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.

(b)	The pro forma financial data adjusts the pro forma column to give effect to income taxes assuming the earnings of the Company had been subject to federal income tax as a subchapter C corporation since December 31, 2011, thus excluding the $54,142,000 charge relating to the change in tax status as of October 11, 2012. The pro forma tax provision has been

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Grow production and reserves by developing our oil-rich resource base. We intend to actively drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital. As of June 30, 2013, we had 867 identified potential vertical drilling locations and 862 identified potential horizontal drilling locations on our acreage in the Permian Basin based on 40-acre spacing and an additional 1,128 vertical locations based on 20-acre downspacing. We were operating a one vertical rig drilling program as of June 30, 2013, as we increase our focus on horizontal wells.

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Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We believe there are opportunities to target various intervals in the Wolfberry play with horizontal wells. Our initial horizontal focus has been on the Wolfcamp B interval in Midland and Upton Counties. Our first two horizontal wells were completed in 2012 and had lateral lengths of less than 4,000 feet. Subsequently, we have drilled or are currently drilling 17 horizontal wells as operator and have participated in one additional horizontal well as a non-operator, 19 of which are Wolfcamp B wells and one of which is a Clearfork well. These wells have had lateral lengths ranging from approximately 4,300 feet to 10,300 feet. In the future, we expect that our optimal average lateral lengths will be in the range of 7,500 feet to 8,000 feet, although the actual length will vary depending on the layout of our acreage and other factors. We expect that longer lateral lengths will result in higher per well recoveries and lower development costs per BOE. During the first six months of 2013, we were able to drill our horizontal wells with approximately 7,500 foot lateral lengths to total depth in an average of 21 days and we recently drilled a 10,353 foot lateral well in 19 days. Our future horizontal drilling program is designed to further capture the upside potential that may exist on our properties. We also believe our horizontal drilling program may significantly increase our recoveries per section as compared to drilling vertical wells alone. Horizontal drilling may also be economical in areas where vertical drilling is currently not economical or logistically viable. In addition, we believe increased well density opportunities may exist across our acreage base. We closely monitor industry trends with respect to higher well density, which could increase the recovery factor per section and enhance returns since infrastructure is typically in place. We were using three horizontal drilling rigs as of June 30, 2013, and currently intend to add a fourth horizontal rig in the fourth quarter of 2013, and are currently contemplating adding one or two horizontal drilling rigs in 2014.

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Leverage our experience operating in the Permian Basin. Our executive team, which has an average of approximately 24 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. The time to reach total depth, or TD, for our vertical Wolfberry wells decreased from an average of 18 days during the second quarter of 2011 to an average of 14 days during the period from April 2012 through August 2012 to an average of 11 days during the fourth quarter of 2012 to an average of eight days during the second quarter of 2013, with three of our recent vertical wells reaching TD in less than seven days. Our focus on efficient drilling and completion techniques, and the reduction in time to reach TD, is an important part of the continuous

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Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. In the current commodity price environment, our oil and liquids rich asset base provides attractive returns. 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 99% of our acreage. This operational control allows us to more efficiently manage 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 88% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies.

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Pursue strategic acquisitions with exceptional resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential and can achieve attractive returns on invested capital. 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. As discussed in more detail under “—Recent Developments—Pending Acquisitions,” we have entered into agreements to acquire approximately 11,150 additional net acres in the Permian Basin.

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Maintain financial flexibility. We seek to maintain a conservative financial position. Upon completion of our initial public offering in October 2012, we used a portion of the net proceeds from the offering to repay the entire balance outstanding under our revolving credit facility. On December 28, 2012, the borrowing base under our revolving credit facility was redetermined, resulting in an increase in our availability to $135.0 million, and it was redetermined again on May 6, 2013, resulting in an increase in availability to $180.0 million. We used a portion of the net proceeds of our May 2013 common stock offering to repay all borrowings outstanding under our revolving credit facility and, as of the date of this prospectus, we have $180.0 million of borrowing base availability.

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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 Wolfberry play. We believe that our historical vertical development success will be complemented with horizontal drilling locations that could ultimately translate into an increased recovery factor on a per section basis. Our production for the six months ended June 30, 2013 was approximately 73% oil, 15% natural gas liquids and 12% natural gas. As of December 31, 2012, our estimated net proved reserves were comprised of approximately 65% oil and 21% natural gas liquids, which allows us to benefit from the currently more favorable pricing of oil and natural gas liquids as compared to natural gas.

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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. As of June 30, 2013, we had 867 identified potential vertical drilling locations based on 40-acre spacing and an additional 1,128 identified potential vertical drilling locations based on 20-acre downspacing. We also believe that there are a significant number of horizontal locations that could be drilled on our acreage. Based on our initial results and those of other operators in the area to date, combined with our interpretation of various geologic and engineering data, we have identified 862 potential horizontal locations on our acreage. These locations exist across most of our acreage blocks and in multiple horizons. Of the 862 locations, 376 are in the Wolfcamp A horizon or the Wolfcamp B horizon, with the remaining locations in either the Clearfork, Spraberry, Wolfcamp C or Cline horizons. We have assigned horizontal locations to the Lower Spraberry, but have not assigned locations to other intervals within the Spraberry, which we believe may have development potential. Our current horizontal location count is based on 880 foot spacing between wells in the Wolfcamp B horizon in Midland and Upton Counties, and 1,320 foot spacing between wells in all other counties and horizons. The ultimate inter-well spacing may be less than these amounts, which would result in a higher location count. Based on horizontal wells drilled to date, we currently estimate that EURs for our Wolfcamp B

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Experienced, incentivized and proven management team. Our executive team has an average of approximately 24 years of industry experience per person, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with both drilling and completing horizontal wells as well as horizontal well reservoir and geologic expertise, which will be of strategic importance as we expand our horizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.

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Favorable and stable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With approximately 380,000 wells drilled in the Permian Basin since the 1940s, we believe that the geological and regulatory environment is more stable and predictable, and that we are faced with less operational risks, in the Permian Basin as compared to emerging hydrocarbon basins.

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High degree of operational control. We are the operator of approximately 99% 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 adjust 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.

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Financial flexibility to fund expansion. We have a conservative balance sheet. We will seek to maintain financial flexibility to allow us to actively develop our drilling, exploitation and exploration activities in the Wolfberry play and maximize the present value of our oil-weighted resource potential. As of the date of this prospectus, we had no borrowings outstanding under our revolving credit facility and available borrowing capacity of $180.0 million. We expect that our borrowing base will be further increased as we increase our reserves.

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•	Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis.

•	Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

•	Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

•	Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

•	Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

•	We adopted the rules effective December 31, 2009, as required by the SEC.

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•	review and verification of historical production data, which data is based on actual production as reported by us;

•	preparation of reserve estimates by our Vice President—Reservoir Engineering or under his direct supervision;

•	review by our Vice President—Reservoir Engineering of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

•	direct reporting responsibilities by our Vice President—Reservoir Engineering to our Chief Executive Officer;

•	verification of property ownership by our land department; and

•	no employee’s compensation is tied to the amount of reserves booked.

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(1)

Estimates of reserves as of December 31, 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2012, 2011 and 2010, respectively, in accordance with revised SEC guidelines applicable to reserve estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

•	additions of 3,167 MBOE attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position;

•	the conversion of approximately 3,224 MBOE attributable to PUDs into proved developed reserves;

•	negative revisions of approximately 625 MBOE in PUDs due to a combination of lower product prices causing wells to reach economic limit earlier, adjustments in working interest and performance revisions; and

•	purchases of reserves in place of 8,077 MBOE.

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(1)

After giving effect to our hedging arrangements, the average prices per Bbl of oil and per BOE were $85.38 and $69.77, respectively, during the six months ended June 30, 2013, $80.34 and $67.00, respectively, during the six months ended June 30, 2012, $79.68 and $64.47, respectively, during the year ended December 31, 2012, and $92.15 and $79.05, respectively, during the year ended December 31, 2011. Average prices for our hydrocarbons were not impacted by hedging arrangements during 2010.

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(1)	Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease.

(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

(3)	A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

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•	the location of wells;

•	the method of drilling and casing wells;

•	the timing of construction or drilling activities, including seasonal wildlife closures;

•	the rates of production or “allowables”;

•	the surface use and restoration of properties upon which wells are drilled;

•	the plugging and abandoning of wells; and

•	notice to, and consultation with, surface owners and other third parties.

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•	a transaction involving compensation of directors;

•	a transaction involving compensation of an executive officer or involving an employment agreement, severance arrangement, change in control provision or agreement or special supplemental benefit of an executive officer;

•	a transaction with a related party involving less than $120,000;

•	a transaction in which the interest of the related party arises solely from the ownership of a class of our equity securities and all holders of that class receive the same benefit on a pro rata basis;

•	a transaction involving indemnification payments and payments under directors and officers indemnification insurance policies made pursuant to our certificate of incorporation or bylaws or pursuant to any policy, agreement or instrument of the Company or to which the Company is bound; and

•	a transaction in which the interest of the related party arises solely from indebtedness of a 5% shareholder or an “immediate family member” of a 5% shareholder.

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•	each stockholder known by us to be the beneficial owner of more than five percent of the outstanding shares of our common stock;

•	each of our directors;

•	each of our named executive officers; and

•	all of our directors and executive officers as a group.

*	Less than 1%.

(1)

Percentage of beneficial ownership is based upon 42,161,532 shares of common stock outstanding as of August 1, 2013. For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any shares which such person has the right to acquire within 60 days. For purposes of computing the percentage of outstanding shares held by each person or group of persons named above, any security which such person or group of persons has the right to acquire within 60 days is deemed to be outstanding for the purpose of computing the percentage ownership for such person or persons, but is not deemed to be outstanding for the purpose of computing the percentage ownership of any other person. As a result, the denominator used in calculating the beneficial ownership among our stockholders may differ.

(2)

Based solely on Schedule 13D/A filed with the SEC on July 2, 2013 by DB Energy Holdings LLC (“DB Holdings”), Wexford Spectrum Fund, L.P. (“WSF”), Wexford Catalyst Fund, L.P. (“WCF”), Spectrum Intermediate Fund Limited (“SIF”), Catalyst Intermediate Fund Limited (“CIF” and, together with DB Holdings, WSF, WCF and SIF, the “Funds”), Wexford Capital LP (“Wexford Capital”), Wexford GP LLC (“Wexford GP”), Charles E. Davidson (“Mr. Davidson”), and Joseph M. Jacobs (“Mr. Jacobs”), the Form 4 filed with the SEC on July 9, 2013 by DB Holdings and the Form 4 filed with the SEC on July 9, 2013 by Wexford Capital, Wexford GP, Mr. Davidson and Mr. Jacobs. DB Holdings is a holding

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(3)	Based solely on the Form 4 filed with the SEC on July 9, 2013 by Gulfport Energy Corporation. Gulfport Energy Corporation’s address is 14313 North May Avenue, Suite 100, Oklahoma City, Oklahoma 73134.

(4)

Based solely on Schedule 13G/A filed with the SEC on March 11, 2013 by Wellington Management Company, LLP. These shares are owned of record by clients of Wellington Management. Those clients have the right to receive, or the power to direct the receipt of, dividends from, or the proceeds from the sale of, such securities. No such client is known to have such right or power with respect to more than five percent of this class of securities. Wellington Management has shared voting power over 3,468,678 shares and shared dispositive power over 3,747,150 shares. Wellington Management Company, LLP’s address is 280 Congress Street, Boston, Massachusetts 02210.

(5)

Includes options to purchase 150,000 shares of our common stock and 28,572 restricted stock units. These 28,572 restricted stock units will not be settled until the first business day coincident with or next following the date of the first open trading window to occur after April 5, 2013, but no later than December 31, 2013. Excludes (i) options to purchase 150,000 shares of our common stock and (ii) 28,571 restricted stock units, which will vest, in each case, in two remaining approximately equal annual installments beginning on April 18, 2014.

(6)

Includes options to purchase 25,000 shares of our common stock and 8,571 restricted stock units, which restricted stock units will not be settled until the first business day coincident with or next following the date of the first open trading window to occur after April 5, 2013 (which has not yet occurred), but no later than December 31, 2013. Excludes (i) options to purchase 25,000 shares of our common stock and (ii) 8,532 restricted stock units, which will vest, in each case, in two remaining approximately equal annual installments beginning on September 1, 2014.

(7)

Includes options to purchase 50,000 shares of our common stock and 17,143 restricted stock units, which restricted stock units will not be settled until the first business day coincident with or next following the date of the first open trading window to occur after April 5, 2013 (which has not yet occurred), but no later than December 31, 2013. Excludes (i) options to purchase 50,000 shares of our common stock and (ii) 17,144 restricted stock units, which will vest, in each case, in two remaining approximately equal annual installments beginning on September 30, 2014.

(8)

Includes options to purchase 50,000 shares of our common stock and 16,906 restricted stock units, which restricted stock units will not be settled until the first business day coincident with or next following the date of the first open trading window to occur after April 5, 2013 (which has not yet occurred), but no later than December 31, 2013. Excludes (i) options to purchase 50,000 shares of our common stock and (ii) 16,666 restricted stock units, which will vest, in each case, in two remaining approximately equal annual installments beginning on August 15, 2014.

(9)

Includes options to purchase 50,000 shares of our common stock and 16,906 restricted stock units, which restricted stock units will not be settled until the first business day coincident with or next following the date of the first open trading window to occur after April 5, 2013 (which has not yet occurred), but no later than December 31, 2013. Excludes (i) options to purchase 50,000 shares of our common stock and (ii) 16,666 restricted stock units, which will vest, in each case, in two remaining approximately equal annual installments beginning on August 15, 2014.

(10)

Includes options to purchase 50,000 shares of our common stock and 16,906 restricted stock units, which restricted stock units will not be settled until the first business day coincident with or next following the date of the first open trading window to occur after April 5, 2013 (which has not yet occurred), but no later than December 31, 2013. Excludes (i) options to purchase 50,000 shares of our common stock and (ii) 16,666 restricted stock units, which will vest, in each case, in two remaining approximately equal annual installments beginning on September 12, 2014.

(11)

Includes options to purchase 25,000 shares of our common stock and 8,452 restricted stock units, which restricted stock units will not be settled until the first business day coincident with or next following the date of the first open trading window to occur after April 5, 2013 (which has not yet occurred), but no later than December 31, 2013. Excludes (i) options to purchase 25,000 shares of our common stock and (ii) 8,334 restricted stock units, which will vest, in each case, in two remaining approximately equal annual installments beginning on August 8, 2014.

(12)	Includes options to purchase 12,500 shares of our common stock and 4,286 restricted stock units, which restricted stock

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(13)	Includes restricted stock units that will not be settled until the first business day coincident with or next following the date of the first open trading window to occur after April 5, 2013 (which has not yet occurred), but no later than December 31, 2013. Excludes 4,444 restricted stock units, which will vest in two remaining equal annual installments beginning on October 11, 2013.

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•	the distinctive serial designation and number of shares of the series;

•	the voting powers and the right, if any, to elect a director or directors;

•	the terms of office of any directors the holders of preferred shares are entitled to elect;

•	the dividend rights, if any;

•	the terms of redemption, and the amount of and provisions regarding any sinking fund for the purchase or redemption thereof;

•	the liquidation preferences and the amounts payable on dissolution or liquidation;

•	the terms and conditions under which shares of the series may or shall be converted into any other series or class of stock or debt of the corporation; and

•	any other terms or provisions which the board of directors is legally authorized to fix or alter.

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

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

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

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•	1% of the number of shares of our common stock then outstanding, which will equal approximately 461,615 shares immediately after this offering; or

•	the average weekly trading volume of our common stock on the NASDAQ Global Select Market during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale.

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•	an individual who is a citizen or resident of the United States;

•	a corporation (including any entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

•	an estate whose income is subject to U.S. federal income taxation regardless of its source; or

•	trust, if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have authority to control all substantial decisions of the trust, or if it has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a U.S. person.

•	certain former U.S. citizens or residents;

•	shareholders that hold our common stock as part of a straddle, constructive sale transaction, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction;

•	shareholders that acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

•	shareholders that are partnerships or entities treated as partnerships for U.S. federal income tax purposes or other pass-through entities or owners thereof;

•	shareholders that own, or are deemed to own, more than five percent (5%) of our outstanding common stock (except to the extent specifically set forth below);

•	shareholders subject to the alternative minimum tax;

•	financial institutions, banks and thrifts;

•	insurance companies;

•	tax-exempt entities;

•	real estate investment trusts;

•	“controlled foreign corporations,” “passive foreign investment companies” or corporations that accumulate earnings to avoid U.S. federal income tax;

•	broker-dealers or dealers in securities or foreign currencies; and

•	traders in securities that use a mark-to-market method of accounting for U.S. federal income tax purposes.

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the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty applies, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States, in which case, the gain will be taxed on a net income basis at the U.S. federal income tax rates and in the manner applicable to U.S. persons, and if the non-U.S. holder is a foreign corporation, the branch profits tax described above may also apply;

•

the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and meets other requirements, in which case, the non-U.S. holder will be subject to a flat 30% tax on the gain derived from the disposition (or such lower rate specified by an applicable income tax treaty), which may be offset by U.S. source capital losses, provided the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses; or

•	we are or have been a “United States real property holding corporation,” or USRPHC, for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held our common stock.

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•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•

Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing shares in the open market.

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Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

•	Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

•	In passive market making, market makers in the common stock who are underwriters or prospective underwriters may, subject to limitations, make bids for or purchases of our common stock until the time, if any, at which a stabilizing bid is made.

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•	our Current Report on Form 8-K, filed with the SEC on February 1, 2013;

•	our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on March 1, 2013;

•	our Amendment No. 1 to our Annual Report on Form 10-K/A for the year ended December 31, 2012, filed with the SEC on April 11, 2013;

•	our Current Report on Form 8-K, filed with the SEC on April 11, 2013;

•	our Definitive Proxy Statement on Schedule 14A, filed with the SEC on April 30, 2013;

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•	our Quarterly Report on Form 10-Q for the three months ended March 31, 2013, filed with the SEC on May 9, 2013;

•	our Current Report on Form 8-K, filed with the SEC on May 20, 2013;

•	our Current Report on Form 8-K, filed with the SEC on June 6, 2013;

•	our Current Report on Form 8-K, filed with the SEC on June 24, 2013; and

•	our Quarterly Report on Form 10-Q for the three months ended June 30, 2013, filed with the SEC on August 8, 2013.

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(i)	Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

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*	Incorporated by reference from Diamondback Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission on March 1, 2013.

**	Incorporated by reference from Diamondback Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 filed with the Securities and Exchange Commission on August 8, 2013.

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*	To be completed by amendment.

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*	Filed herewith.

**	To be filed by amendment.

+	Management contract, compensatory plan or arrangement.

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*	Filed herewith.

**	To be filed by amendment.

+	Management contract, compensatory plan or arrangement.