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•	business strategy;

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

•	oil and natural gas reserves;

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

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

•	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 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.

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Focus on increasing hydrocarbon recovery through horizontal development of stacked horizons. We have been developing multiple pay intervals in the Permian Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. Our initial horizontal wells were completed in 2012, and since then we have been an active horizontal driller in the basin. As of December 31, 2018, we are the operator of 1,193 producing horizontal wells and have a non-operated working interest in 253 additional wells. Of these 1,446 total horizontal wells, 952 wells are in the Midland Basin, 493 wells are in the Delaware Basin and one well is in the Central Basin platform. We believe that our significant experience drilling, completing and operating horizontal wells will allow us to efficiently develop our remaining inventory and ultimately target other horizons that have limited development to date. During the year ended December 31, 2018, we were able to drill our horizontal wells in the Midland Basin with approximately 7,500 foot lateral lengths to total depth, or TD, in an average of 13 days, we drilled approximately 10,000 foot lateral wells in 15 days and we drilled approximately 13,000 foot wells in 23 days. During the year ended December 31, 2018, we were able to drill our horizontal wells in the Delaware Basin with approximately 7,500 foot lateral lengths to total depth in an average of 24 days and we drilled approximately 10,000 foot lateral wells in 31 days. Further advances in drilling and completion technology may result in economic development of zones that are not currently viable.

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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 has helped reduce the execution risk normally associated with these complex well paths. In addition, our completion techniques are continually evolving as we evaluate and implement hydraulic fracturing practices that have and are expected to continue to increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.

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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 89% 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 76% 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 substantial resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential. Our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We regularly review acquisition opportunities and intend to pursue acquisitions that meet our strategic and financial targets. During the year ended December 31, 2018, we completed multiple acquisitions in the Midland Basin through our acquisitions of Ajax, ExL and EnergyQuest, as well as Energen. As a result, our Midland Basin acreage footprint increased from approximately 101,941 net acres to approximately 194,661 net acres as of December 31, 2018, with our Delaware Basin acreage increasing from approximately 104,719 net acres to approximately 170,205 net acres over the same period.

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Maintain financial flexibility. We seek to maintain a conservative financial position. In connection with our fall 2018 borrowing base redetermination, our borrowing base was set at $2.65 billion, and we elected a commitment amount of $2.0 billion, of which $0.5 billion was available for borrowing as of December 31, 2018. As of December 31, 2018, Viper had $411.0 million in outstanding borrowings, and $144.0 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 Permian Basin. Our production for the year ended December 31, 2018 was approximately 72% oil, 16% natural gas liquids and 12% natural gas. As of December 31, 2018, our estimated net proved reserves were comprised of approximately 63% oil, 18% natural gas liquids and 19% 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. At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 11,868 gross (7,633 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data. These gross identified economic potential horizontal locations have an average lateral length of approximately 7,200 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 11,868 locations, 6,479 are in the Midland Basin and 5,389 are in the Delaware Basin. In the Midland Basin, 2,465 are in the Lower Spraberry or Wolfcamp B horizons where we have drilled a large number of wells, 2,200 are in the Wolfcamp A or Middle Spraberry horizons where we have drilled a limited number of wells and 1,814 are in the Clearfork, Jo Mill or Cline horizons where we have drilled very few wells. Our current location count for the Lower Spraberry horizon is based on 660 foot to 880 foot spacing in Midland, Martin, northeast Andrews, Howard and Glasscock counties, depending on the prospect area and 880 foot spacing in all other counties. For the Wolfcamp B horizon, the horizontal location count is based on 660 foot to 880 foot spacing between wells in Midland, Martin, northeast Andrews, Howard, and Glasscock counties, and 880 foot spacing in all other counties. In the Wolfcamp A horizon, the horizontal location count in based on 660 foot to 880 foot spacing in Midland, Howard and Glasscock counties, 880 foot spacing in southwest Martin county and 1,320 foot spacing in other counties. The horizontal location count for the Middle Spraberry is based on 880 foot spacing in Midland, Martin and northeast Andrews counties and 1,320 foot spacing in other counties. In the Cline and Clearfork and Jo Mill horizons, the horizontal location count is based on 880 foot to 1,320 foot spacing. In the Delaware Basin, 2,219 locations are in the Wolfcamp A or Wolfcamp B horizons, and 1,789 locations are in the 2nd Bone Spring or 3rd Bone Spring horizon and 1,381 locations are in other horizons including the Brushy Canyon, Avalon, 1st Bone Spring and Wolfcamp C. The horizontal location counts are based on 880 foot spacing in the Wolfcamp A and Wolfcamp B horizons, and 1,320 foot spacing in the Bone Spring horizons. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count. In addition, we have approximately 2,617 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.

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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 experience in the Permian Basin. In addition, our executive team has significant experience with both drilling and completing horizontal

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

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High degree of operational control. We are the operator of approximately 89% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of our acreage, we retain the ability to increase or decrease our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.

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

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

•	review by our Executive 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 Executive 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.

(1)

Estimates of reserves as of December 31, 2018, 2017 and 2016 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, 2018, 2017 and 2016, respectively, in accordance with SEC guidelines applicable to reserves 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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(1)	Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.

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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. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells.

(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)	Does not include Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests.

(4)	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.

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

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

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

•	not realizing anticipated operating synergies;

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

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

•	integrating relationships with customers, vendors and business partners;

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

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

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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; and

•	overall domestic and global economic conditions.

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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 economically new reserves; and

•	our ability to borrow under our credit facility.

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•	recoverable reserves;

•	future oil and natural gas prices and their applicable differentials;

•	operating costs; and

•	potential environmental and other liabilities.

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•	crude oil swap contracts priced at a weighted average price of $61.07 WTI Cushing for 10,638,000 aggregate Bbls;

•	crude oil swap contracts priced at a weighted average price of $72.39 WTI Magellan East Houston for 1,270,000 aggregate Bbls;

•	crude oil swap contracts priced at a weighted average price of $68.02 Brent for 2,005,000 aggregate Bbls;

•	crude oil basis swap contracts priced at a weighted average price of $(5.56) for 17,012,000 aggregate Bbls for the spread between the WTI Midland price and the WTI Cushing price;

•	natural gas swap contracts priced at a weighted average price of $3.06 Henry Hub for 25,550,000 aggregate MMBtu;

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•	natural gas basis swap contracts priced at a weighted average price of $(1.60) Waha Hub for 18,250,000 aggregate MMBtu;

•	natural gas liquid swaps priced at a weighted average price of $27.30 Mont Belvieu for 2,760,000 aggregate Bbls;

•	crude oil three-way collars contracts with a WTI Cushing short put price of $38.10, floor price of $48.10 and a ceiling price of $63.70 for 7,570,000 aggregate Bbls;

•	crude oil three-way collars contracts with a WTI Magellan East Houston short put price of $56.82, floor price of $66.82 and a ceiling price of $77.60 for 994,000 aggregate Bbls; and

•	crude oil three-way collars contracts with a Brent short put price of $55.00, floor price of $65.00 and a ceiling price of $82.47 for 2,000,000 aggregate Bbls.

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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;

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•	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;

•	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.

•	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

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

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

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(1)	For the years ended December 31, 2018, 2017, 2016, 2015 and 2014, total stockholders’ equity excludes $467.0 million, $326.9 million, $320.8 million $233.0 million and $234.2 million, respectively, of non-controlling interest related to Viper Energy Partners LP.

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

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(1)	Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.

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(1)	Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

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(1)	Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

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•	$2.3 billion to $2.55 billion will be spent on drilling and completing 290 to 320 gross (255 to 280 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 9,400 feet;

•	$400.0 million to $450.0 million will be spent on midstream infrastructure; and

•	$175.0 million to $200.0 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

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(1)	Includes the outstanding principal amount under the revolving credit facilities, the table does not include interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.

(2)	Interest represents the scheduled cash payments on the senior notes and Energen Notes.

(3)	Includes only the minimum amount of interest and commitment fees due which, as of December 31, 2018, includes a commitment fee equal to 0.375% per year of the unused portion of the borrowing base of Viper’s credit agreement.

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(4)

Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 7—Asset Retirement Obligations of the Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.

(5)	Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2018.

(6)	Operating lease obligations represent future commitments for building, equipment and vehicle leases.

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(1)	Includes $7,070,120 Common stock issued for business combination, $14,088 for stock options assumed and $51,829 for restricted stock units assumed.

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(1)	At the effective time of the Merger, Energen became a wholly owned subsidiary of the Company and remained the issuer of these notes (the “Energen Notes”).

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(1)	Includes 107,472 replacement awards granted in connection with the closing of the Energen merger on November 29, 2018.

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(1)	A maximum of 392,406 units could be awarded based upon the Company’s final TSR ranking.

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(1)	The federal statutory rates for the years ended December 31, 2018, 2017 and 2016 were 21%, 35% and 35%, respectively.

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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 that are open at the time of the estimate but which have not yet 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 that are open at the time of the estimate but which have not yet 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.