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•	business strategy;

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

•	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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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 December 31, 2014, we had 2,185 gross (1,646 net) identified potential horizontal drilling locations, and 786 gross (746 net) identified potential vertical drilling locations on our acreage in the Permian Basin based on 40-acre spacing and an

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Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We have targeted various intervals in the Wolfberry play through horizontal drilling and believe that there are opportunities to target additional intervals in the Wolfberry play with horizontal wells. Our initial horizontal focus has been on the Wolfcamp B interval, but we have begun to derisk additional intervals such as the Lower Spraberry. Our first two horizontal wells were completed in 2012 and had lateral lengths of less than 4,000 feet. As of December 31, 2014, we had drilled 124 horizontal wells as operator and had participated in nine additional horizontal wells as a non-operator, including two in which we own only a minor wellbore interest. Of these 133 total horizontal wells, 100 had been completed and were on production. Of the 100 horizontal wells on production, 78 are in the Wolfcamp B interval, three are in the Clearfork zone, 16 are in the Spraberry zone, and three are in the Cline zone. These wells have lateral lengths ranging from approximately 4,000 feet to 10,300 feet. In the future, we expect that our optimal average lateral lengths will be in the range of 6,000 feet to 7,500 feet, although the actual length will vary depending on the layout of our acreage and other factors. We expect that longer lateral lengths will continue to result in higher per well recoveries and lower development costs per BOE. During the year ended December 31, 2014, we were able to drill our horizontal wells with approximately 7,500 foot lateral lengths to total depth, or TD, in an average of 16 days and we drilled an approximately 10,000 foot lateral well in 17 days. Our horizontal drilling program is designed to further capture the upside potential that may exist on our properties. We also believe our horizontal drilling program has significantly increased 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.

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Leverage our experience operating in the Permian Basin. Our executive team, which has an average of over 25 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. Our focus on efficient drilling and completion techniques is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. We believe that the experience of our executive team in deviated and horizontal drilling and completions 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. 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 95% 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 80% 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. During the year ended December 31, 2014, we acquired approximately 28,654 gross (20,216) net leasehold acres primarily in Glasscock, Martin and Midland counties. We intend to continue to pursue acquisitions that meet our strategic and financial targets.

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Maintain financial flexibility. We seek to maintain a conservative financial position. On November 13, 2014, we entered into a second amendment to our amended and restated credit agreement, resulting in an increase to the borrowing base under our revolving credit facility to $750.0 million. We elected a commitment amount of $500.0 million, of which $276.5 million was available for borrowing as of December 31, 2014. As of December 31, 2014, Viper had no outstanding borrowings, and $110.0 million available for borrowing, under its revolving credit facility.

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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 horizontal drilling has resulted in an increased recovery factor on a per section basis as compared to our historical vertical development. Our production for the year ended December 31, 2014 was approximately 76% oil, 14% natural gas liquids and 10% natural gas. As of December 31, 2014, our estimated net proved reserves were comprised of approximately 67% oil and 16% 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 December 31, 2014, we had 2,185 gross (1,646 net) identified potential horizontal drilling locations on our acreage based on our results and those of other operators in the area and our interpretation of various geologic and engineering data. The 2,185 gross identified potential horizontal locations have an average lateral length of approximately 6,600 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 2,185 locations, 923 are in the Wolfcamp B horizon or the Lower Spraberry horizon, with the remaining locations in either the Wolfcamp A, Clearfork, Wolfcamp C or Cline horizons. Our current horizontal location count is based on 660 foot spacing between wells in the Wolfcamp B and Lower Spraberry horizons in Midland County, Glasscock County, and Southwest Martin County and Viper's mineral interests, and 880 foot spacing in other counties. In the Middle Spraberry, well counts are based on 880 foot spacing in Midland County and Southwest Martin County and 1,320 foot spacing in other counties. For all other zones and counties, our well counts are based on 1,320 foot spacing, with the exception of the Wolfcamp A in Glasscock County which is based on 660 foot spacing. The ultimate inter-well spacing may be closer than these distances, which would result in a higher 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, 2014, range from 378 MBOE per well, consisting of 276 MBbls of oil and 612 MMcf of natural gas, to 1,191 MBOE per well, consisting of 935 MBbls of oil and 1,539 MMcf of natural gas, for wells ranging in lateral length from approximately 5,000 feet to approximately 10,000 feet, in intervals including the Clearfork, Middle Spraberry, Lower Spraberry, and Wolfcamp B. Ryder Scott has estimated gross EURs of 638 MBOE for our Wolfcamp B wells in Midland County and 993 MBOE for our Lower Spraberry wells in Midland County, which constitute 51% of our remaining PUD horizontal wells, in each case based on 7,500 foot lateral lengths. We also had 786 gross (746 net) identified potential vertical drilling locations based on 40-acre spacing and an additional 1,086 gross (996 net) identified potential vertical drilling locations based on 20-acre downspacing. The gross EURs from our future PUD vertical wells on 40-acre spacing, as estimated by Ryder Scott as of December 31, 2014, range from 101 MBOE per well, consisting of 77 MBbls of oil and 142 MMcf of natural gas, to 145 MBOE per well, consisting of 111 MBbls of oil and 206 MMcf of natural gas, with an average EUR per well of 120 MBOE, consisting of 89 MBbls of oil and 186 MMcf of natural gas. In addition, we have approximately 628 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.

•	Experienced, incentivized and proven management team. Our executive team has an average of over 25 years of industry experience per person, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig development drilling programs and extensive

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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. We believe that the geological and regulatory environment of the Permian Basin is more stable and predictable, and that we are faced with less operational risks, in the Permian Basin as compared to emerging hydrocarbon basins.

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High degree of operational control. We are the operator of approximately 95% 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 December 31, 2014, we had $223.5 million of borrowings outstanding under our revolving credit facility and $276.5 million of available borrowing capacity. As of December 31, 2014, Viper had no outstanding borrowings, and $110.0 million available for borrowing, under its revolving credit facility.

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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.

•	The ability to book proven undeveloped reserves, subject to certain exceptions, only if they relate to wells scheduled to be drilled within five years of the date of booking, as well as the requirement to write down proved undeveloped reserves if the associated wells are not drilled within the required five-year timeframe.

•	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.

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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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•	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”;

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•	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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•	our proved reserves;

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

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

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

•	our ability to borrow under our credit facility.

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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 and quantity of foreign imports;

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

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

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

•	the level of consumer product demand;

•	weather conditions and other natural disasters;

•	risks associated with operating drilling rigs;

•	technological advances affecting energy consumption;

•	the price and availability of alternative fuels;

•	domestic and foreign governmental regulations and taxes;

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

•	the proximity, cost, availability 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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•	our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to the senior notes, including any repurchase obligations that may arise thereunder;

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

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

•	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;

•	a high level of debt could limit our ability to access the capital markets to raise capital on favorable terms;

•	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; and

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

•	incur or guarantee additional indebtedness;

•	make certain investments;

•	create additional liens;

•	sell or transfer assets;

•	issue preferred stock;

•	merge or consolidate with another entity;

•	pay dividends or make other distributions;

•	designate certain of our subsidiaries as unrestricted subsidiaries;

•	create unrestricted subsidiaries;

•	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;

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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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•	our quarterly or annual operating results;

•	changes in our earnings estimates;

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

•	additions or departures of key personnel;

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

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

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

•	announcements of legislative or regulatory changes.

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

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

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

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

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

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

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•	$285.0 million to $315.0 million will be spent on drilling and completing 50 to 60 gross (43 to 52 net) operated horizontal wells focused in Midland, Andrews, Upton, Martin and Dawson Counties;

•	$20.0 million to $30.0 million will be spent on infrastructure;

•	$20.0 million to $30.0 million will be spent on non-operated activity and other expenditures; and

•	an estimated $75.0 million for expenditures related to 2014 activity (net of expenditures from 2015 expected to be carried into 2016).

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By:	/s/ John Stohlmann

1.	I have reviewed this Annual Report on Form 10-K of Diamondback Energy, Inc.

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

1.	I have reviewed this Annual Report on Form 10-K of Diamondback Energy, Inc.

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

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(1)	completion intervals which are open at the time of the estimate, but which have not started producing;

(2)	wells which were shut-in for market conditions or pipeline connections; or

(3)	wells not capable of production for mechanical reasons.

(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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(1)	completion intervals which are open at the time of the estimate, but which have not started producing;

(2)	wells which were shut-in for market conditions or pipeline connections; or

(3)	wells not capable of production for mechanical reasons.

(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.