Edgar Filing: Diamondback Energy, Inc.

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

Name of Each Exchange on Which Registered

Common Stock, par value $0.01 per share

The NASDAQ Stock Market LLC

Securities registered pursuant to Section 12(g) of the Act: None

12.31.13 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



ý	ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013



¨	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-35700

Diamondback Energy, Inc.

(Exact Name of Registrant As Specified in Its Charter)



Delaware			45-4502447
(State or Other Jurisdiction of Incorporation or Organization)			(IRS Employer Identification Number)

500 West Texas, Suite 1200 Midland, Texas			79701
(Address of Principal Executive Offices)			(Zip Code)

(Registrant Telephone Number, Including Area Code): (432) 221-7400

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2013 was approximately $800,108,000.

As of February 3, 2014, 47,106,216 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2014 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.

DIAMONDBACK ENERGY, INC. TABLE OF CONTENTS

		Page
PART I
ITEMS 1 and 2.	BUSINESS AND PROPERTIES	1
ITEM 1A.	RISK FACTORS	21
ITEM 1B.	UNRESOLVED STAFF COMMENTS	46
ITEM 3.	LEGAL PROCEEDINGS	46
ITEM 4.	MINE SAFETY DISCLOSURES	46
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	46
ITEM 6.	SELECTED FINANCIAL DATA	48
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	51
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	68
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	69
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	69
ITEM 9A.	CONTROLS AND PROCEDURES	70
ITEM 9B.	OTHER INFORMATION	72
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	72
ITEM 11.	EXECUTIVE COMPENSATION	72
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	72
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	72
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	72
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	73

Signatures		S-1

Index to Combined Consolidated Financial Statements		73

Exhibit Index		E-1

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used throughout this report:

3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

Bbls/d. Bbls per day.

BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

BOE/d. BOE per day.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

MBOE. One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mcf. Thousand cubic feet of natural gas.

Mcf/d. Mcf per day.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

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Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

PDP. Proved developed producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

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

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this Annual Report on Form 10–K could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about our:


•	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.

All forward-looking statements speak only as of the date of this report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

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PART I

Diamondback Energy, Inc., or Diamondback, was incorporated in Delaware 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. Prior to the merger, Diamondback Energy LLC was a holding company and did not conduct any material business operations other than its ownership of Diamondback’s common stock and the membership interests in Windsor Permian LLC, or Windsor Permian. As a result of the merger, Windsor Permian became a wholly-owned subsidiary of Diamondback. Also on October 11, 2012, Wexford Capital LP, or Wexford, our equity sponsor, caused all of the outstanding equity interests in Windsor UT LLC, or Windsor UT, to be contributed to Windsor Permian prior to the merger in a transaction we refer to as the “Windsor UT Contribution.” In this Annual Report on Form 10-K, the combined consolidated historical financial information, operational data and reserve information for Diamondback present the assets and liabilities of Diamondback and its subsidiaries, including Windsor UT, as if they were combined for all periods presented. Although the financial and other information is reported on a combined consolidated basis, such presentation is not necessarily indicative of the results that would have been obtained if Diamondback had owned and operated Windsor UT from its inception. In this Annual Report on Form 10-K, we refer to Diamondback, together with its consolidated subsidiaries, as “we,” “us,” “our,” or “the Company”. This report includes certain terms commonly used in the oil and gas industry, which are defined above in the “Glossary of Oil and Natural Gas Terms.”

ITEM 1. BUSINESS

Overview

We are an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators.

We began operations in December 2007 with our acquisition of 4,174 net acres with production at the time of acquisition of approximately 800 BOE/d from 34 gross (16.8 net) wells in the Permian Basin. Subsequently, we acquired approximately 61,764 additional net acres, which brought our total net acreage position in the Permian Basin to 65,938 net acres at December 31, 2013. We are the operator of approximately 99% of this acreage. In addition, we own mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas, and we are the operator of approximately 50% of the acreage associated with these mineral interests. As of December 31, 2013, we had drilled 270 gross (243 net) wells, and participated in an additional 22 gross (nine net) non-operated wells, in the Permian Basin. Of these 292 gross (252 net) wells, 277 were completed as producing wells and 15 were in various stages of completion. In 2013, we acquired working interests in 49 gross (40 net) producing wells. In the aggregate, as of December 31, 2013, we held interests in 351 gross (306 net) producing wells in the Permian Basin. Nine gross (eight net) wells have been plugged and abandoned or converted to service wells. We also hold royalty interests in 81 wells in which we have no working interest. As discussed in more detail below under “–Pending Acquisition,” we recently entered into agreements to acquire approximately 6,450 gross (2,825 net) leasehold acres in Martin County, Texas.

Our activities are primarily focused on the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations, which we refer to collectively as the Wolfberry play. The Wolfberry play is characterized by high oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates. The Wolfberry play is a modification and extension of the Spraberry play, the majority of which is designated in the Spraberry Trend area field. According to the U.S. Energy Information Administration, the Spraberry trend area ranked as the second largest oilfield in the United States, based on 2009 reserves.

As of December 31, 2013, our estimated proved oil and natural gas reserves were 63,586 MBOE based on a reserve report prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers. Of these reserves, approximately 45% are classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate are from 206 vertical gross (151 net) well locations on 40-acre spacing and 43 gross (31 net) horizontal well locations. As of December 31, 2013, these proved reserves were approximately 67% oil, 17% natural gas liquids and 16% natural gas.

Based on our evaluation of applicable geologic and engineering data as of December 31, 2013, we had 848 identified potential vertical drilling locations on 40-acre spacing, an additional 1,128 identified potential vertical drilling locations based on 20-acre downspacing and we had also identified 1,430 potential horizontal drilling

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locations in multiple horizons on our acreage. We intend to continue to grow our reserves and production through development drilling, exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through additional acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. The gross estimated ultimate recoveries, or EURs, from our future PUD vertical wells on 40-acre spacing, as estimated by Ryder Scott as of December 31, 2013, range from 109 MBOE per well, consisting of 83 MBbls of oil and 156 MMcf of natural gas to 150 MBOE per well, consisting of 114 MBbls of oil and 214 MMcf of natural gas, with an average EUR per well of 128 MBOE, consisting of 94 MBbls of oil and 204 MMcf of natural gas. We also intend to continue to refine our drilling pattern and completion techniques in an effort to increase our average EUR per well from vertical wells drilled on 40-acre spacing. We currently anticipate a reduction of approximately 20% in our EURs from vertical wells drilled on 20-acre spacing.

Horizontal Wells. In 2012, we began testing the horizontal well potential of our acreage. Our first horizontal well was the Janey 16H in Upton County and was drilled in the Wolfcamp B interval. We are the operator of this well with a 100% working interest. Our second horizontal well was the Kemmer 4209H well in Midland County also drilled in the Wolfcamp B interval. It is a non-operated well in which we own a 47% working interest. Since the initial two wells, through December 31, 2013, we have drilled 41 horizontal wells as operator and participated in six wells as non-operator, including two in which we own only a minor wellbore interest. Of these 49 total horizontal wells (including our two initial wells), 44 are in the Wolfcamp B interval, two are in the Clearfork zone, two are in the Spraberry zone and one is in the Cline zone. Thirty-seven of the 49 wells were completed and producing as of December 31, 2013 and the other 12 are in various stages of completion. The table below presents certain data regarding our producing horizontal wells (excluding the two non-operated wells in which we hold only a minor wellbore interest).



	Number
	of		Peak	30-Day
	Producing	Lateral	24-HR IP	IP Rate
County/Zone	Wells	Length	(BOE/d)	(BOE/d)	% Oil
Midland County Wolfcamp B^(a)	16	5,591’	899	650	88%
Upton County Wolfcamp B^(b)	15	6,453’	880	566	83%
Andrews County Wolfcamp B	1	4,051’	613	440	83%
Midland County Spraberry	2	5,042’	905	732	84%
Andrews County Clearfork	1	7,540’	611	390	82%




(a)	The 30-day initial production, or IP, rate and percentage of oil for Midland County Wolfcamp B is based on 13 wells for which there is sufficient production history.
(b)	The 30-day IP rate and percentage of oil for Upton County Wolfcamp B is based on 13 wells for which there is sufficient production history.

The production results from the wells in Midland and Upton Counties, along with geoscience and engineering data that we have gathered and analyzed, and published results by other operators, give us confidence that our acreage in Midland and Upton Counties is prospective in the Wolfcamp B interval. Additionally, we believe the results of our operated wells in Andrews County in the Wolfcamp B and the Clearfork intervals significantly reduces the hydrocarbon risks of our acreage in the vicinity of those wells.

Pending Acquisition

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locations in the Middle Spraberry, Wolfcamp A, Cline and Clearfork intervals, based on 240 acre spacing per well (or four across a section). Under the terms of the existing joint operating agreement, we have made offers to the owners of the remaining 56.2% of the working interests to acquire their interests in the acreage. If all such owners were to sell their interests to us, the aggregate purchase price would be approximately $397.2 million. We intend to finance the acquisition, subject to market conditions and other factors, with a combination of borrowings under our revolving credit facility and the issuance of new debt and equity securities. We will become the operator of this acreage if and when two or more working interest holders with more than 50% of the working interest appoint us as the successor operator. The acquisition is scheduled to close by the end of February 2014, however the transaction remains subject to completion of due diligence and satisfaction of other customary closing conditions, and there can be no assurance that the transaction will be completed.

Our Business Strategy

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

•

Grow production and reserves by developing our oil-rich resource base. We intend to 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, 2013, we had 1,430 identified potential horizontal drilling locations, and 848 identified potential vertical 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 December 31, 2013, as we increase our focus on horizontal wells.

•

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 41 horizontal wells as operator and have participated in six additional horizontal wells as a non-operator, including two in which we own only a minor wellbore interest. Of these 49 total horizontal wells (including our two initial wells), 44 are in the Wolfcamp B interval, two are in the Clearfork zone, two are in the Spraberry zone, and one is 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 result in higher per well recoveries and lower development costs per BOE. During the year ended December 31, 2013, we were able to drill our horizontal wells with approximately 7,500 foot lateral lengths to total depth, or TD, in an average of 18 days and we drilled an approximately 10,000 foot lateral well in 17 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 four horizontal drilling rigs as of December 31, 2013, and currently intend to add a fifth horizontal rig in the second quarter of 2014.

•

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.

•

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

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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 86% 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 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, 2013, we acquired mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas and acquired approximately 13,900 additional gross (11,150 net) leasehold acres in Martin County, Texas and Dawson County, Texas. We have entered into agreements dated February 14, 2014 to acquire 6,450 gross (2,825 net) acres in Martin County, Texas. See “–Pending Acquisition” above for more information regarding the acquisition. We intend to continue to pursue acquisitions that meet our strategic and financial targets.

•

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 November 1, 2013, our credit agreement was amended and restated, resulting in an increase to the borrowing base under our revolving credit facility to $225.0 million, of which $215.0 million was available for borrowing as of December 31, 2013.

Our Strengths

We believe that the following strengths will help us achieve our business goals:

•

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 year ended December 31, 2013 was approximately 76% oil, 13% natural gas liquids and 11% natural gas. As of December 31, 2013, our estimated net proved reserves were comprised of approximately 67% oil and 17% 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.

•

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, 2013, we had 848 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 1,430 potential horizontal locations on our existing acreage with an average lateral length of approximately 6,270 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 the 1,430 existing locations, 604 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 horizon in Midland County where we operate and own mineral interests, and 880 foot spacing elsewhere in the Wolfcamp B horizon in Midland County and other counties. In the Lower and Middle Spraberry, well counts are based on 880 foot spacing in Midland 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. The ultimate inter-well spacing may be closer than these distances, which would result in a higher location count. The gross two-stream estimated EURs from our future PUD horizontal wells, as estimated by Ryder Scott as of December 31, 2013, range from 374 MBOE per well, consisting of 274 MBbls of oil and 604 MMcf of natural gas, to 847 MBOE per well, consisting of 623 MBbls of oil and 1,342 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,

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and Wolfcamp B. Ryder Scott has estimated gross EURs of 638 MBOE for our Wolfcamp B wells in Andrews and Midland Counties, which constitute 51% of our remaining PUD horizontal wells, and 604 MBOE for our eastern Upton County Wolfcamp B wells, which constitute 19% of our remaining PUD horizontal wells, in each case based on 7,500 foot lateral lengths. 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.

•

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 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.

•

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 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.

•

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, 2013, we had $10.0 million of borrowings outstanding under our revolving credit facility and $215.0 million of available borrowing capacity.

Our Properties

Location and Land

We acquired approximately 4,174 net acres in West Texas (near Midland) in the Permian Basin on December 20, 2007, with an effective date of November 1, 2007, from ExL Petroleum, LP, Ambrose Energy I, Ltd. and certain other sellers. Subsequently, we acquired approximately 61,764 additional net acres, which brought our total net acreage position in the Permian Basin to approximately 65,938 net acres at December 31, 2013. We are the operator of approximately 99% of this Permian Basin acreage. In addition, we own mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas, and we are the operator of approximately 50% of the acreage associated with these mineral interests. Since our initial acquisition in the Permian Basin through December 31, 2013, we drilled or participated in the drilling of 291 gross (251 net) wells on our leasehold acreage in this area, primarily targeting the Wolfberry play. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States.

Area History

Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations. The Spraberry play was initiated with production from several new field discoveries in the late 1940s and early 1950s. It was eventually recognized that a regional productive trend was present, as fields were extended and coalesced over a broad area in the central Midland Basin. Development in the Spraberry play was sporadic over the next several decades due to typically low productive rate wells, with economics being dependent on oil prices and drilling costs.

The Wolfcamp formation is a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or debris flows with good reservoir properties.

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Exploration using 2-D seismic data located additional fields, but it was not until the use of 3-D seismic data in the 1990s that the greater extent of the Wolfcamp formation was revealed. The additional potential of the shales within this formation as reservoir rather than just source rocks was not recognized until very recently.

During the late 1990s, Atlantic Richfield Company, or Arco, began a drilling program targeting the base of the Spraberry formation at 10,000 feet, with an additional 200 to 300 feet drilled to produce from the upper portion of the Wolfcamp formation. Henry Petroleum, a private firm, owned interests in the Pegasus field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracturing treatments across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they monetized a portion of their acreage position, which led to the acquisition that enabled us to begin our participation in this play. Recent advancements in enhanced recovery techniques and horizontal drilling continue to make this play attractive to the oil and gas industry. By mid-2010, approximately half of the rigs active in the Permian Basin were drilling wells in the Wolfberry play. As of December 31, 2013, we held interests in 351 gross (306 net) producing wells.

Geology

The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita fold belt. It is one of the largest sedimentary basins in the U.S., and has oil and gas production from several reservoirs from Permian through Ordovician in age. The term “Wolfberry” was coined initially to indicate commingled production from the Permian Spraberry, Dean and Wolfcamp formations. In this report, we refer to the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations collectively as the Wolfberry play. The Wolfberry play of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp play. The Spraberry was deposited as turbidites in a deep water submarine fan environment, while the Wolfcamp reservoirs consist of debris-flow and grain-flow sediments, which were also deposited in a submarine fan setting. The best carbonate reservoirs within the Wolfcamp are generally found in proximity to the Central Basin Platform, while the shale reservoirs within the Wolfcamp thicken basinward away from the Central Basin Platform. Both the Spraberry and Wolfcamp contain organic-rich mudstones and shales which, when buried to sufficient depth for maturation, became the source of the hydrocarbons found in the reservoirs.

The Wolfberry play can be generally characterized as a combination of low-permeability clastic, carbonate and shale reservoirs which are hydrocarbon-charged and are economic due to the overall thickness of the section (more than 3,000 feet) and application of enhanced stimulation (fracking) techniques. The Wolfberry is an unconventional “basin-centered oil” resource play, in the sense that there is no regional downdip oil/water contact.

Several shale intervals within the Wolfcamp formation are currently being evaluated for horizontal development potential, and initial drilling to explore these intervals commenced in 2012. The shales exhibit micro-darcy permeabilities which result in relatively small drainage areas and recovery factors. Because of this, we believe the horizontal exploitation of these reservoirs will supplement, and not replace, our vertical development program.

There are also productive carbonate and shale intervals within the shallower Permian Clearfork formation. Two shale intervals within the Clearfork formation are currently being evaluated for potential horizontal development. Below the Wolfcamp formation lie the Pennsylvanian Strawn and Atoka formations. Although difficult to predict, there are conventional pay intervals that develop locally within these formations which, when present, can add significant reserves.

Debris flows within the Spraberry and Wolfcamp carbonates have been observed on 3-D seismic surveys. Initial tests have confirmed the presence of enhanced reservoir. Additionally, structural closures have been mapped and are being evaluated for drilling to test deeper targets. Our extensive geophysical database, which includes approximately 182 square miles of proprietary 3-D seismic data, will be used to enhance grading of future locations.

Production Status

During the year ended December 31, 2013, net production from our Permian Basin acreage was 2,672,244 BOE, or an average of 7,321 BOE/d, of which approximately 76% was oil, 13% was natural gas liquids and 11% was natural gas.

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Facilities

Our land oil and gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units.

Future Activity

During 2014, we expect to drill an estimated 65 to 75 gross (52 to 60 net) horizontal wells and 20 to 25 gross (16 to 20 net) vertical wells on our acreage. We currently estimate that our capital expenditures for 2014 will be between $425.0 million and $475.0 million, which includes costs for infrastructure and non-operated wells but does not include the cost of any land acquisitions, including the pending acquisition. During the year ended December 31, 2013, we drilled 38 gross (37 net) horizontal wells and 39 gross (33 net) vertical wells and participated in the drilling of four gross (two net) non-operated wells in the Permian Basin. During the year ended December 31, 2013, our aggregate capital expenditures for drilling and oil gas infrastructure were $297.7 million, and we spent an additional $640.0 million for leasehold and mineral rights acquisitions.

Oil and Natural Gas Data

Proved Reserves

SEC Rule-Making Activity

In December 2008, the Securities and Exchange Commission, or SEC, released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required, unless contractual arrangements designate the price to be used. Other significant amendments included the following:


•	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.

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2013, 2012 and 2011 were prepared by Ryder Scott, with respect to our assets in the Permian Basin.

Ryder Scott is an independent petroleum engineering firm. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2013 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second

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determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 85% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 15% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our Vice President—Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. Our Vice President—Reservoir Engineering is a petroleum engineer with over 30 years of reservoir and operations experience and our geoscience staff has an average of approximately 26 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:


•	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.

The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2013, 2012 and 2011, based on the reserve report prepared by Ryder Scott. Each reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States.

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	Year Ended December 31,
	2013		2012		2011
Estimated proved developed reserves:
Oil (Bbls)	19,789,965		7,189,367		3,949,099
Natural gas (Mcf)	31,428,756		12,864,941		5,285,945
Natural gas liquids (Bbls)	4,973,493		2,999,440		1,263,710
Total (BOE)	30,001,584		12,332,964		6,093,800
Estimated proved undeveloped reserves:
Oil (Bbls)	22,810,887		19,007,492		14,151,337
Natural gas (Mcf)	30,250,740		21,705,207		15,265,522
Natural gas liquids (Bbls)	5,732,231		5,251,989		3,785,849
Total (BOE)	33,584,908		27,877,016		20,481,440
Estimated Net Proved Reserves:
Oil (Bbls)	42,600,852		26,196,859		18,100,436
Natural gas (Mcf)	61,679,496		34,570,148		20,551,467
Natural gas liquids (Bbls)	10,705,724		8,251,429		5,049,559
Total (BOE)⁽¹⁾	63,586,492		40,209,979		26,575,240
Percent proved developed	47.2	%	30.7	%	22.9	%



(1)	Estimates of reserves as of December 31, 2013, 2012 and 2011 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, 2013, 2012 and 2011, 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.

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A.“Risk Factors.” We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2013, our proved undeveloped reserves totaled 22,811 MBbls of oil, 30,251 MMcf of natural gas and 5,732 MBbls of natural gas liquids, for a total of 33,585 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2013 were primarily due to:


•	additions of 15,928 MBOE attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position;


•	the conversion of approximately 4,733 MBOE attributable to PUDs into proved developed reserves;


•	negative revisions of approximately 9,493 MBOE in PUDs, 7.933 MBOE of which was due to downgrading 92 vertical locations that were booked as PUDs to probable in accordance with the SEC five year PUD rule; and


•	purchases of reserves in place of 4,006 MBOE.

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Costs incurred relating to the development of PUDs were approximately $76.6 million during 2013. Estimated future development costs relating to the development of PUDs are projected to be approximately $201 million in 2014, $166 million in 2015, $109 million in 2016 and $26 million in 2017. Since our current executive team assumed management control in 2011, our average drilling costs and drilling times have been reduced. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.

All of our PUD drilling locations are scheduled to be drilled prior to the end of 2018.

As of December 31, 2013, 2% of our total proved reserves were classified as proved developed non-producing.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding our net production of oil, natural gas and natural gas liquids, all of which is from the Permian Basin in West Texas, and certain price and cost information for each of the periods indicated:




	Historical
	Year Ended December 31,
	2013			2012			2011
Production Data:
Oil (Bbls)	2,022,749			756,286			449,434
Natural gas (Mcf)	1,730,497			833,516			413,640
Natural gas liquids (Bbl)	361,079			183,114			86,815
Combined volumes (BOE)	2,672,244			1,078,320			605,189
Daily combined volumes (BOE/d)	7,321			2,946			1,658
Average Prices⁽¹⁾:
Oil (per Bbl)	$	93.32		$	86.88		$	92.24
Natural gas (per Mcf)	3.61			2.85			3.98
Natural gas liquids (per Bbl)	36.00			37.57			54.98
Combined (per BOE)	77.84			69.52			79.11
Average Costs (per BOE):
Lease operating expense	$	7.92		$	14.14		$	16.41
Gathering and transportation expense	$	0.34		$	0.39		$	0.33
Production taxes	$	4.83		$	4.86		$	5.01
Production taxes as a % of sales	6.2		%	7.0		%	6.3		%
Depreciation, depletion and amortization	$	24.92		$	24.36		$	25.78
General and administrative	$	4.13		$	9.62		$	6.04

(1) After giving effect to our derivative instruments, the average prices per Bbl of oil and per BOE were $89.75 and $75.14, respectively, during the year ended December 31, 2013; $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.

Productive Wells

As of December 31, 2013, we owned an average 87% working interest in 351 gross (306 net) productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

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Acreage

The following table sets forth information as of December 31, 2013 relating to our leasehold acreage:

Developed Acreage⁽¹⁾

Undeveloped Acreage⁽²⁾

Total Acreage⁽³⁾

Basin

Gross⁽⁴⁾

Net⁽⁵⁾

Gross⁽⁴⁾

Net⁽⁵⁾

Gross⁽⁴⁾

Net⁽⁵⁾

Permian

12,960

11,036

63,395

54,902

76,355

65,938



(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)	Does not include our mineral interests but does include 8,833 gross (6,654 net) 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.

Undeveloped acreage expirations

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2013, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.



	2014		2015		2016		2017		2018
Basin	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian	2,730	1,926	23,795	19,604	12,463	11,725	2,626	1,180	—	—

Drilling Results

The following table sets forth information with respect to the number of wells completed during the periods indicated. Each of these wells was drilled in the Permian Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.



	Year Ended December 31,
	2013		2012		2011
	Gross	Net	Gross	Net	Gross	Net
Development:
Productive	55	46	44	28	39	23
Dry	—	—	—	—	—	—
Exploratory:
Productive	32	27	14	7	7	4
Dry	—	—	—	—	—	—
Total:
Productive	87	73	58	35	46	27
Dry	—	—	—	—	—	—

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As of December 31, 2013, we had 15 gross (13 net) wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that are not reflected in the above table.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Marketing and Customers

We market the majority of the oil and natural gas production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our natural gas production to purchasers at market prices. In March 2009, we entered into an agreement with Windsor Midstream LLC, or Midstream, an entity controlled by Wexford. During 2010 and 2011, Midstream purchased a significant portion of our oil volumes. Effective December 1, 2011, we ceased all sales of our production under this agreement and, effective January 1, 2012, the agreement was canceled. We sell all of our natural gas under contracts with terms of greater than twelve months and all of our oil under contracts with terms of twelve months or less, excluding a five year oil purchase agreement with Shell Trading (US) Company, or Shell Trading, described below.

We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the year ended December 31, 2013, two purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (37%) and Shell Trading (US) Company (37%). For the year ended December 31, 2012, three purchasers each accounted for more than 10% of our revenue: Plains Marketing, L.P. (53%); Occidental Energy Marketing, Inc. (16%); and Andrews Oil Buyers, Inc. (10%). For the year ended December 31, 2011, one purchaser, Midstream, accounted for approximately 79% of our revenue. No other customer accounted for more than 10% of our revenue during these periods. If a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

On May 24, 2012, we entered into an oil purchase agreement with Shell Trading, in which we agreed to sell specified quantities of oil to Shell Trading upon completion of the reversal of the Magellan Longhorn pipeline and its conversion for oil shipment, which occurred on October 1, 2013. Our agreement with Shell Trading has an initial term of five years from the completion date. The agreement may also be terminated by Shell Trading by written notice to us in the event that Shell Trading’s contract for transportation on the pipeline is terminated. Our maximum delivery obligation under this agreement is 8,000 gross barrels per day. We have a one-time right to elect to decrease the contract quantity by not more than 20% of the then-current quantity, which decreased contract quantity will be effective for the remainder of the term of the agreement. Shell Trading has agreed to pay to us the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the New York Mercantile Exchange over the one-month period, as adjusted based on adjustment formulas specified in the agreement. If we fail to deliver the required quantities of oil under the agreement during any three-month period following the service commencement date, we have agreed to pay Shell Trading a deficiency payment, which is calculated by multiplying (i) the volume of oil that we failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect for transportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiency volume is calculated.

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Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Transportation

During the initial development of our fields we consider all gathering and delivery infrastructure in the areas of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm where it is further transported by pipeline. Our natural gas is generally transported from the wellhead to the purchaser’s pipeline interconnection point through our gathering system.

During the fourth quarter of 2012, we completed construction of a gas gathering system that transports our gas stream to a sour gas pipeline, thereby eliminating the processing and treating expense. By the end of 2013, we were moving 70% of our produced water by pipeline directly into commercial salt water disposal wells, rather than by truck, thereby further reducing one of the largest components of LOE. We believe that the completion of gathering systems, the connection to salt water disposal wells and other actions will help us to reduce our lease operating expense in future periods.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 18.75% to 25.00%, resulting in a net revenue interest to us generally ranging from 81.25% to 75.00%.

Seasonal Nature of Business

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.

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Environmental Matters and Regulation

Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Waste Handling. The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

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Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane in 2013 and a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “—Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in January 2011. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the Rule in 2014. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010.

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The EPA has continued to adopt GHG regulations of other industries, such as the September 2013 proposed GHG rule that, if finalized, would set new source performance standards for new coal-fired and natural-gas fired power plants, which could have an adverse effect on our financial condition and results of operations. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration—wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress.

On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for

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reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013 that would update existing regulation for hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected in 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

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The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

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.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that

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significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Operational Hazards and Insurance

The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies for onshore property (oil lease property/production equipment) for selected locations, rig physical damage protection, control of well protection for selected wells, comprehensive general liability, commercial automobile, workers compensation,

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pollution liability (claims made coverage with a policy retroactive date), excess umbrella liability and other coverage.

Our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and cash flows. See “Item 1A. Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.”

We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Generally, we also require our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

Employees

As of December 31, 2013, we had approximately 68 full time employees. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full time employees.

Facilities

Our corporate headquarters is located in Midland, Texas. We also lease additional office space in Midland and in Oklahoma City, Oklahoma. We believe that our facilities are adequate for our current operations.

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ITEM 1A. RISK FACTORS.

The nature of our business activities subjects us to certain hazards and risks. The following is a summary of some of the material risks relating to our business activities. Other risks are described in “Item 1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” These risks are not the only risks we face. We could also face additional risks and uncertainties not currently known to the Company or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial conditional or results of operations and the trading price of our shares could decline.

Risks Related to the Oil and Natural Gas Industry and Our Business

A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2013, our total capital expenditures, including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately $937.7 million. Our 2014 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $425.0 million to $475.0 million, representing an increase of 48% over our 2013 capital budget. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and the senior notes.

We intend to finance our future capital expenditures with cash flow from operations, proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:


•	our proved reserves;


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


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


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


•	our ability to borrow under our credit facility.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2014 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the

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failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

Our success depends on finding, developing or acquiring additional reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made, and expect to make in the future, substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

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

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:

• recoverable reserves;

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

• operating costs; and

• potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. The inability to effectively manage the integration of acquisitions, including our recently completed and pending acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial

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position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our analysis of the acreage subject to the pending Martin County acquisition was based in part on information provided to us by the sellers and the limited representations, warranties and indemnifications of the sellers contained in the purchase agreements, which may prove to be incorrect, resulting in our not realizing the expected benefits of the acquisition.

Our analysis of the acreage subject to the pending Martin County acquisition, including our estimates of the associated proved reserves, is based in part on information provided to us by the sellers, including historical production data. Our independent reserve engineers have not reviewed, nor have they provided any estimates with respect to, the assets subject to the pending acquisition. As a result, the assumptions on which our internal estimates of proved reserves and horizontal drilling locations included in or incorporated by reference into this prospectus supplement have been based may prove to be incorrect in a number of material ways, resulting in our not realizing our expected benefits of the acquisition. In addition, the representations, warranties and indemnities of the sellers contained in the purchase agreements are limited and we may not have recourse against the sellers in the event that the acreage does not perform as expected.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.

Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. From inception through December 31, 2013, we drilled a total of 270 gross wells and participated in an additional 22 gross non-operated wells, of which 277 wells were completed as producing wells and 15 wells were in various stages of completion. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.

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Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of December 31, 2013, we had 848 gross (791 net) identified potential vertical drilling locations on our existing acreage based on 40-acre spacing, an additional 1,128 gross (1,027 net) identified potential vertical drilling locations based on 20-acre downspacing and we have also identified 1,430 gross (1,148 net) potential horizontal drilling locations in multiple horizons on our acreage. As of December 31, 2013, only 206 of our gross identified potential vertical drilling locations and 43 of our identified potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, we have identified 1,076 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable or whether wells drilled on 20-acre downspacing will produce at the same rates as those on 40-acre spacing. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. While through December 31, 2013 we are the operator of or have participated in a total of 49 horizontal wells on our acreage, we cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2013, we had leases representing 1,926 net acres expiring in 2014, 19,604 net acres expiring in 2015, 11,725 net acres expiring in 2016, 1,180 net acres expiring in 2017 and no net acres expiring in 2018. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases expiring in 2014 and 2015, we will need to operate at least a four-rig program. We cannot assure you that we will have the liquidity to deploy these rigs in this time frame, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.

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

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:


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


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


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

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•	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.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $34.03 per barrel, or Bbl, in February 2009 to a high of $113.39 per Bbl in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.82 per million British thermal units, or MMBtu, in April 2012 to a high of $7.51 per MMBtu in January 2010. During 2013, West Texas Intermediate prices ranged from $86.65 to $110.62 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.08 to $4.52 per MMBtu. On December 31, 2013, the West Texas Intermediate posted price for crude oil was $98.17 per Bbl and the Henry Hub spot market price of natural gas was $4.31 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.

We have entered into price swap derivatives and may in the future enter into forward sale contracts or additional price swap derivatives for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and natural gas.

We use price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on New York Mercantile Exchange West Texas Intermediate pricing, Argus Louisiana light sweet pricing or Inter-Continental Exchange, or ICE, pricing for Brent crude oil. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty.

As of December 31, 2013, we have crude oil swap contracts in place covering Argus Louisiana light sweet crude oil priced at a weighted average price of $98.78 for 944,000 aggregate Bbls for the production period of January - December 2014, and a price of $101.00 per Bbl for 31,000 aggregate Bbls for the production period of January 2015. As of December 31, 2013, we also have a crude oil swap contract in place covering ICE Brent crude oil priced at a price of $109.70 for 120,000 Bbls for the production period of January - April 2014. Our current goal is to hedge from 40% to 70% of our production. The contracts described above and any future economic hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in

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the price of oil. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Our derivative transactions expose us to counterparty credit risk.

Our derivative transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $12.2 million at December 31, 2013) and receivables from purchasers of our oil and natural gas production (approximately $24.8 million at December 31, 2013). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2013, two purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (37%); and Shell Trading (US) Company (37%). For the year ended December 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (53%); Occidental Energy Marketing, Inc. (16%); and Andrews Oil Buyers, Inc. (10%). For the year ended December 31, 2011, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 79% of our revenue. No other customer accounted for more than 10% of our revenue during these periods. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $24.63, $23.90 and $25.41 for the years ended December 31, 2013, 2012 and 2011, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, 2013, 2012 and 2011 was $65.8 million, $25.8 million and $15.4 million, respectively.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. Beginning December 31, 2009, we have used the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.

No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2013, 2012 and 2011. We may, however, experience ceiling test write downs in the future. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and

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Estimates—Method of accounting for oil and natural gas properties” for a more detailed description of our method of accounting.

Our estimated reserves and EURs 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 value of our reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves as of December 31, 2013, 2012 and 2011 are based on reports prepared by Ryder Scott, which conducted a well-by-well review of all our properties for the periods covered by its reserve reports using information provided by us. The EURs for our horizontal wells and the proved reserves attributable to our pending acquisition in Martin County are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates.

The estimates of reserves as of December 31, 2013, 2012 and 2011 included in this report were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods December 31, 2013, 2012 and 2011, respectively, in accordance with the revised SEC guidelines applicable to reserve estimates for such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.

The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil reserves.

The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

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The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Approximately 53% of our total estimated proved reserves as of December 31, 2013, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating 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.

All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition to the geographic concentration of our producing properties described above, as of December 31, 2013, all of our proved reserves were attributable to the Wolfberry play. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

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, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the year ended December 31, 2013, two purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (37%); and Shell Trading (US) Company (37%). For the year ended December 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (53%); Occidental Energy Marketing, Inc. (16%); and Andrews Oil Buyers, Inc. (10%). For the year ended December 31, 2011, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 79% of our revenue. No other customer accounted for more than 10% of our revenue during these periods. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent

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third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. In addition, although we intend to increase the number of rigs we have operating in 2014, we cannot guarantee that we will be able to do so. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. During the last two years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

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

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

Our business is difficult to evaluate because we have a limited operating history.

Diamondback Energy, Inc. was incorporated in Delaware on December 30, 2011. Prior to October 11, 2012, all of our historical oil and natural gas assets, operations and results described in this report were those of Windsor Permian and Windsor UT which, prior to our initial public offering, were entities controlled by our equity sponsor, Wexford. Immediately prior to the effectiveness of the registration statement relating to our initial public offering, Windsor Permian became our wholly-owned subsidiary and we acquired the oil and natural gas assets of Gulfport Energy Corporation, or Gulfport, located in the Permian Basin in exchange for shares of our common stock and a promissory note in a transaction we refer to as the Gulfport transaction. The oil and natural gas properties described in this report have been acquired by Windsor Permian, Gulfport and Windsor UT since December 2007. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

As a recently-formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

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We have incurred losses from operations during certain periods since our inception and may do so in the future.

We incurred a net loss of $36.5 million for the year ended December 31, 2012. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from our operating activities in the future.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system. Our purchasers then transport the oil by truck to a pipeline for transportation. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to

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curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.

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

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. See Item 1. “Business—Regulation” for a description of the laws and regulations that affect us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and natural gas commissions. The Environmental Protection Agency, or EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is conducting an administration-wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production

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equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Several states, including Texas, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Railroad Commission recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act, or OSHA, to state regulators and on a public internet website. We plan to use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volumes of oil and natural gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and

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completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010. In its rulemaking under the legislation, the Commodities Futures Trading Commission, or CFTC, has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The CFTC’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the CFTC has indicated that it intends to appeal the court’s decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.

In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other related

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rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2014 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, (iii) the repeal of the percentage depletion allowance for oil and natural gas properties, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (iv) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations and cash flows.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in January 2011. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the Rule in 2014. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010.

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future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from FERC’s jurisdiction under the NGA. However, the distinction between FERC—regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.

We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We have employment agreements with these executives which contain restrictions on competition with us in the event they cease to be employed by us. However, as a practical matter, such employment agreements may not assure the

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retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

A significant reduction by Wexford of its ownership interest in us could adversely affect us.

Prior to October 11, 2012, Wexford beneficially owned 100% of our equity interests. Upon completion of our initial public offering, Wexford beneficially owned approximately 44.4% of our common stock. As a result of the issuance of additional shares of common stock by us and sales of our common stock by affiliates of Wexford, as of December 31, 2013, Wexford beneficially owned approximately 22.6% of our common stock. Further, the Chairman of our Board of Directors is an affiliate of Wexford. We believe that Wexford’s substantial ownership interest in us provides Wexford with an economic incentive to assist us to be successful. Wexford is not subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Wexford sells all or a substantial portion of its ownership interest in us, Wexford may have less incentive to assist in our success and its affiliate(s) that serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations. We also receive certain services, including drilling services from entities controlled by Wexford. These service contracts may generally be terminated on 30-days notice. In the event Wexford ceases to own a significant ownership interest in us, such services may not be available to us on terms acceptable to us, if at all.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.

Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:


•	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.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

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Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

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Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected.

As of December 31, 2013, we are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls. During the course of our integration of our internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected.

If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

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Increased costs of capital could adversely affect our business.

Our business and operating results could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We recorded stock-based compensation expense in 2012 and 2013, and we may incur substantial additional compensation expense related to our future grants of stock compensation which may have a material negative impact on our operating results for the foreseeable future.

As a result of outstanding stock-based compensation awards, we recorded $2,983,000 and $6,294,000 of compensation expense in 2013 and 2012, respectively. In addition, our compensation expenses may increase in the future as compared to our historical expenses because of the costs associated with our existing and possible future incentive plans. These additional expenses could adversely affect our net income. The future expense will be dependent upon the number of share-based awards issued and the fair value of the options or shares of common stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Related to Our Indebtedness

Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the senior notes and our other indebtedness.

As of December 31, 2013, we had total long-term debt of $460.0 million, including $450.0 million outstanding under the senior notes, and borrowing base availability of $215.0 million under our revolving credit facility. We may in the future incur significant additional indebtedness under our revolving credit facility or otherwise in order to make acquisitions, to develop our properties or for other purposes.

Our level of indebtedness could have important consequences to you and affect our operations in several ways, including the following:


•	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.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

Restrictive covenants in our revolving credit facility, the indenture governing the senior notes and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our revolving credit facility and the indenture governing the senior notes contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things:


•	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.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants contained in our revolving credit facility and the indenture governing the senior notes. In addition, our revolving credit facility requires us to maintain certain financial ratios and tests. The

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requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

A breach of any of these restrictive covenants could result in default under our revolving credit facility. If default occurs, the lenders under our revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indenture governing the senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under our revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our revolving credit facility and the senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.

Availability under our revolving credit facility is currently subject to a borrowing base of $225.0 million. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of December 31, 2013, we had outstanding borrowings of $10.0 million which bore a weighted average interest rate of 1.67%. We intend to continue borrowing under our revolving credit facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness, including the senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our revolving credit facility and the indenture governing the senior notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.

We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our revolving credit facility and the indenture governing the senior notes restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2013, our borrowing base under our revolving credit facility was set at $225.0 million and we had outstanding borrowings of $10.0 million under this facility. In addition, the indenture governing the senior notes allows us to issue additional notes under certain circumstances which will also be guaranteed by the guarantors. The indenture governing the senior notes also allows us to incur certain other

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additional secured debt and allows us to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indenture governing the senior notes does not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

Our borrowings under our revolving credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility, which bear interest at a rate elected by us that is based on the prime rate, LIBOR or federal funds rate plus margins ranging from 0.5% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. As of December 31, 2013, we had $10.0 million in borrowings outstanding under our revolving credit facility, with a weighted average interest rate of 1.67%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

Risks Related to Our Common Stock

Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.

As of December 31, 2013, Wexford and Gulfport beneficially owned approximately 22.6% and 7.2%, respectively, of our common stock. In addition, individuals affiliated with Wexford and Gulfport serve on our Board of Directors. As a result, Wexford and Gulfport, together, are able to exercise significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it difficult for any other holder or group of holders of our common stock to be able to affect the way we are managed or the direction of our business. The interests of Wexford and Gulfport with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. This continued concentrated ownership will make it difficult for another company to acquire us and for you to receive any related takeover premium for your shares unless Wexford and Gulfport approve the acquisition.

The corporate opportunity provisions in our certificate of incorporation could enable Wexford, our equity sponsor, or other affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our certificate of incorporation, among other things:


•	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

•

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.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.

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We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. These transactions include, among others, drilling services provided to us by Bison Drilling and Field Services, LLC, or Bison, real property leased by us from Fasken Midland, LLC and Caliber Investment Croup, LLC, hydraulic fracturing sand purchased by us from Muskie Proppant LLC, or Muskie, and certain administrative services provided to us by Everest Operations Management LLC. Each of these entities is either controlled by or affiliated with Wexford, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests because Wexford may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, see “—Risks Related to our Common Stock—Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.”

We incur increased costs as a result of being a public company, which may significantly affect our financial condition.

We completed our initial public offering in October 2012. As a public company, we incur significant legal, accounting and other expenses that we did not incur as a private company. We also incur costs associated with our public company reporting requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. These rules and regulations increase our legal and financial compliance costs and make some activities more time-consuming and costly. These rules and regulations make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.

Since the market value of our common stock held by non-affiliates exceeded $700 million as of June 30, 2013, we ceased to be an “emerging growth company” as of December 31, 2013 and, as a result, expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not “emerging growth companies,” including Section 404 of the Sarbanes-Oxley Act. See “—Risks Related to the Oil and Natural Gas Industry and Our Business—We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability and results of operations and financial condition could be materially adversely affected.”

If the price of our common stock fluctuates significantly, your investment could lose value.

Although our common stock is listed on the NASDAQ Select Global Market, we cannot assure you that an active public market will continue for our common stock. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:


•	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;

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


•	announcements of legislative or regulatory changes.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of such shares, or the perception that such sales may occur, could impair our ability to raise capital through the sale of additional common or preferred stock. Except for any shares purchased by our affiliates, all of the shares of common stock sold in our initial public offering and our subsequent equity offering are freely tradable. In connection with our initial public offering, we also granted DB Energy Holdings LLC, or DB Holdings, and Gulfport and their respective affiliates certain registration rights obligating us to register with the SEC their shares of our common stock. In the event that one or more of our stockholders sells a substantial amount of our common stock in the public market, or the market perceives that such sales may occur, the price of our stock could decline.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrade our stock or if our operating results do not meet their expectations, our stock price could decline.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:


•	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.

These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

We do not intend to pay cash dividends on our common stock in the foreseeable future and, therefore, only appreciation of the price of our common stock will provide a return to our stockholders.

We have not paid dividends since our inception and we currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our board of directors. In addition, the terms of our revolving credit facility prohibit us from paying dividends and making other distributions. As a result, only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

In September 2010, Windsor Permian (now known as Diamondback O&G LLC) purchased certain property in Goodhue County, Minnesota, that was prospective for hydraulic fracturing grade sand. Prior to the purchase, the prior owners of the property had entered into a Mineral Development Agreement with the plaintiff and Windsor Permian purchased the property subject to that agreement. Windsor Permian subsequently contributed the property to Muskie. In an amended complaint filed in November 2012 by the plaintiff against the prior owners of the property, Windsor Permian and certain affiliates of Windsor Permian in the first judicial district court in Goodhue County, Minnesota, the plaintiff seeks damages from the Company and the other defendants alleging, among other things, interference with contractual relationship, interference with prospective advantage and unjust enrichment. In an order filed on May 24, 2013, the judge denied certain motions made by the defendants and set a trial date to determine liability, with a damage phase of the matter to commence on a later date if there is a determination of liability. Following a trial on the liability phase on June 21, 2013, the jury determined that the defendants intentionally interfered with plaintiff’s contract but that the interference did not cause the plaintiff to be unable to acquire mining permits prior to the enactment of the moratorium by Goodhue County. In an order filed on July 10, 2013, the judge ordered the damage phase to be set for trial following a pretrial and scheduling conference, and the parties have agreed upon a schedule for pretrial activities. Subsequently, the plaintiff disclosed a new damage theory, and the defendants filed motions with the court to dismiss plaintiff’s claims on the grounds that the damage claim is speculative and that plaintiff cannot prove damages as a matter of law. Plaintiff also filed a motion for leave to amend its complaint to assert a punitive damage claim. The motions were argued in December 2013 and we currently anticipate a ruling before the end of March 2014. We believe these claims are without merit and will continue to vigorously defend this action. While management has determined that the possibility of loss is remote, litigation is inherently uncertain and management cannot determine the amount of loss, if any, that may result.

We could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Price Range of Common Stock

Our common stock is listed on the NASDAQ Global Select Market under the symbol “FANG”.

The following table sets forth the range of high and low sales prices of our common stock for the periods presented:

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	High		Low
2013:
1st Quarter	$	27.21	$	18.60
2nd Quarter	$	35.91	$	23.83
3rd Quarter	$	47.22	$	33.42
4th Quarter	$	58.71	$	42.18
2012:
4th Quarter (1)	$	19.89	$	15.65

(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.

Holders of Record

The number of holders of record of our common stock was eleven on February 11, 2014.

Dividend Policy

We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility restrict the payment of cash dividends on our common stock. See Item 1A. “Risk Factors-Risks Related to the Oil and Natural Gas Industry and Our Business-Our revolving credit facility contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Credit Facility.” We currently intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.

Recent Sales of Unregistered Securities

None.

Repurchases of Equity Securities

None.

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ITEM 6. SELECTED FINANCIAL DATA

This section presents our selected historical combined consolidated financial data. The selected historical combined consolidated financial data presented below is not intended to replace our historical combined consolidated financial statements. You should read the following data along with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the combined consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report on Form 10-K.

Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years ended December 31, 2013, 2012 and 2011 and the balance sheet data as of December 31, 2013 and 2012 are derived from our audited combined consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The historical financial data for the year ended December 31, 2010 and 2009 and the balance sheet data as of December 31, 2011, 2010 and 2009 are derived from our audited financial statements not included in this Annual Report on Form 10-K.



	Year Ended December 31,
(In thousands, except per share amounts)	2013			2012⁽¹⁾			2011⁽²⁾			2010⁽²⁾			2009
Statements of Operations Data:
Total revenues	$	208,002		$	74,962		$	49,366		$	27,253		$	12,716
Total costs and expenses	112,808			57,655			34,219			18,072			11,378
Income from operations	95,194			17,307			15,147			9,181			1,338
Other income (expense)	(8,853		)	1,075			(15,533		)	(950		)	(4,044		)
Income (loss) before income taxes	86,341			18,382			(386		)	8,231			(2,706		)
Provision for income taxes	31,754			54,903			—			—			—
Net income (loss)	$	54,587		$	(36,521	)	$	(386	)	$	8,231		$	(2,706	)
Earnings per common share
Basic	$	1.30
Diluted	$	1.29
Weighted average common shares outstanding
Basic	42,015
Diluted	42,255
Pro forma information⁽³⁾
Income (loss) before income taxes, as reported				$	18,382		$	(386	)	$	8,231		$	(2,706	)
Pro forma provision for income taxes				6,553			—			—			—
Pro forma net income (loss)				$	11,829		$	(386	)	$	8,231		$	(2,706	)
Pro forma earnings per common share⁽⁴⁾
Basic				$	0.60
Diluted				$	0.60



	As of December 31,
(In thousands)	2013		2012⁽¹⁾		2011⁽²⁾		2010⁽²⁾		2009
Balance Sheet Data:
Cash and cash equivalents	$	15,555	$	26,358	$	6,959	$	4,119	$	2,430
Net property and equipment	1,446,337		554,242		221,149		155,611		95,296
Total assets	1,521,614		606,701		263,578		181,315		100,073
Current liabilities	121,320		79,232		42,298		19,070		13,972
Long-term debt	460,000		193		85,000		44,767		—
Stockholders’/ Members’ equity	845,541		462,068		129,037		115,362		84,202

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	Year Ended December 31,
(In thousands)	2013			2012⁽¹⁾			2011⁽²⁾			2010⁽²⁾			2009
Other Financial Data:
Net cash provided by operating activities	$	155,777		$	49,692		$	30,998		$	5,192		$	2,702
Net cash used in investing activities	(940,140		)	(183,078		)	(81,108		)	(55,236		)	(32,150		)
Net cash provided by financing activities	773,560			152,785			52,950			51,733			23,849



	Year Ended December 31,
(In thousands)	2013		2012⁽¹⁾		2011⁽²⁾		2010⁽²⁾		2009
Adjusted EBITDA⁽⁵⁾	$	164,822	$	48,223	$	31,758	$	17,398	$	4,617



(1	)	The year ended December 31, 2012 reflects (a) the combined historical financial data of Windsor Permian LLC and Windsor UT LLC, which we sometimes refer to as the Predecessors, due to the transfer of a business between entities under common control and (b) the results of operations attributable to the acquisition of properties from Gulfport Energy Corporation beginning October 11, 2012, the closing date of the property acquisition. See Note 2 and Note 3 to our combined consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
(1	)

(2	)	The years ended December 31, 2011 and 2010 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 included elsewhere in this Annual Report on Form 10-K.

(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 subchapter C corporation under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision for 2012 as if the Company and the Predecessors were subject to income taxes since December 31, 2011. For 2011, 2010 and 2009 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 respected 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 2 to our combined consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

(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 2 to our combined consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

(5	)	Adjusted EBITDA is a supplemental non-GAAP financial measure. For a definition of Adjusted EBITDA to net income (loss) see “—Non-GAAP financial measures and reconciliations” below.

Non-GAAP financial measures and reconciliations

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

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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.

The following presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).



	Year Ended December 31,
(In thousands)	2013			2012			2011			2010		2009
Net income (loss):	$	54,587		$	(36,521	)	$	(386	)	$	8,231	$	(2,706	)
Non-cash (gain) loss on derivative instruments, net	(5,346		)	(8,057		)	12,972			—		1,298
Loss on settlement of derivative instruments, net	7,218			5,440			37			148		2,770
Interest expense	8,059			3,610			2,528			836		11
Depreciation, depletion and amortization	66,597			26,273			16,104			8,145		3,216
Non-cash equity-based compensation expense	2,724			3,482			544			—		—
Capitalized equity-based compensation expense	(972		)	(1,005		)	(106		)	—		—
Asset retirement obligation accretion expense	201			98			65			38		28
Provision for income taxes	31,754			54,903			—			—		—
Adjusted EBITDA	$	164,822		$	48,223		$	31,758		$	17,398	$	4,617

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our combined consolidated financial statements and notes thereto appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Item 1A. Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements”.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Our activities are primarily directed at the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations which we refer to as the Wolfberry play. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. Our production was approximately 76% oil, 13% natural gas liquids and 11% natural gas for the year ended December 31, 2013, and was approximately 70% oil, 17% natural gas liquids and 13% natural gas for the year ended December 31, 2012. On December 31, 2013, our total net leasehold acreage position in the Permian Basin was approximately 65,938 net acres. In addition, we own mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas, and we are the operator of approximately 50% of the acreage associated with these mineral interests.

Diamondback was incorporated in Delaware 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 Energy LLC was a holding company and did not conduct any material business operations other than its ownership of our common stock and the membership interests in Windsor Permian LLC, or Windsor Permian. As a result of the merger, Windsor Permian became a wholly-owned subsidiary of Diamondback and subsequently changed its name to Diamondback O&G LLC. Also on October 11, 2012, Wexford Capital LP, or Wexford, caused all of the outstanding equity interests in Windsor UT LLC, or Windsor UT, to be contributed to Windsor Permian prior to the merger in a transaction we refer to as the “Windsor UT Contribution.” The Windsor UT Contribution was treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. We refer to the historical results of Windsor Permian and Windsor UT prior to October 11, 2012 as our “Predecessors.”

The subsidiaries of Diamondback, as of December 31, 2013, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, and Viper Energy Partners LLC, a Delaware limited liability company. The subsidiaries are all wholly owned.

Also on October 11, 2012, we acquired all of the oil and natural gas properties of Gulfport Energy Corporation, which we refer to as “Gulfport,” located in the Permian Basin in exchange for (i) 7,914,036 shares of our common stock, (ii) approximately $63.6 million in the form of a non-interest bearing promissory note that was repaid in full upon the closing of our initial public offering, and (iii) a post-closing cash adjustment of approximately $18.6 million. We are the operator of the acreage acquired by us from Gulfport.

On October 17, 2012, we completed our initial public offering of 14,375,000 shares of common stock, which included 1,875,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was priced at $17.50 per share and we received net proceeds of approximately $234.1 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

In the first quarter of 2013, Windsor UT merged with and into Windsor Permian and Windsor Permian, the surviving entity in the merger, was renamed Diamondback O&G LLC, or Diamondback O&G.

On May 21, 2013, we completed an underwritten primary public offering of 5,175,000 shares of common stock, which included 675,000 shares of common stock issued pursuant to an option to purchase additional shares

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granted to the underwriters. The stock was sold to the public at $29.25 per share and we received net proceeds of approximately $144.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

On June 24, 2013, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 6,000,000 shares of our common stock and, on July 5, 2013, the underwriters purchased an additional 869,222 shares of our common stock from these selling stockholders pursuant to an option to purchase additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering.

In August 2013, we completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold the public at $40.25 per share and we received net proceeds of approximately $177.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

In September 2013, we completed an offering of $450.0 million aggregate principal amount of our 7.625% Senior Notes due 2021, which we refer to as the senior notes. See “—Liquidity and Capital Resources—Financing Activity—Senior Notes.”

Recent Developments

Pending Acquisition

We have entered into definitive purchase agreements dated February 14, 2014 with unrelated third party sellers to acquire additional leasehold interests in Martin County, Texas, in the Permian Basin, for an aggregate purchase price of approximately $174.0 million, subject to certain adjustments. This transaction includes 6,450 gross (2,825 net) acres with a 43.8% working interest (75% net revenue interest) and net production of approximately 1,300 BOE/d (approximately 75% oil) during the first two weeks of February 2014 based on information reported by the operator, from 147 gross (63 net) producing vertical wells. Net proved reserves, based on our internal estimates as of December 31, 2013, were approximately 4,185 MBOE. Our estimate of proved reserves is based on our analysis of production data provided by the sellers, as well as available geologic and other data, and we may revise our estimates following ownership of these properties. We believe the acreage is prospective for horizontal drilling in the Wolfcamp B, Lower Spraberry, Middle Spraberry, Wolfcamp A, Cline and Clearfork horizons, and have identified 42 potential horizontal drilling locations in each of the Wolfcamp B and Lower Spraberry horizons based on 160 acre spacing per well (or six across a section) and an aggregate of 112 potential horizontal drilling locations in the Middle Spraberry, Wolfcamp A, Cline and Clearfork intervals, based on 240 acre spacing per well (or four across a section). Under the terms of the existing joint operating agreement, we have made offers to the owners of the remaining 56.2% of the working interests to acquire their interests in the acreage. If all such owners were to sell their interests to us, the aggregate purchase price would be approximately $397.2 million. We intend to finance the acquisition, subject to market conditions and other factors, with a combination of borrowings under our revolving credit facility and the issuance of new debt and equity securities. We will become the operator of this acreage if and when two or more working interest holders with more than 50% of the working interest appoint us as the successor operator. The acquisition is scheduled to close by the end of February 2014, however the transaction remains subject to completion of due diligence and satisfaction of other customary closing conditions, and there can be no assurance that the transaction will be completed.

Midland County Mineral Interest Acquisition

On September 19, 2013, we purchased mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas in the Permian Basin for $440.0 million, subject to certain adjustments. We are the operator of approximately 50% of the acreage associated with these mineral interests. The mineral interests entitle us to receive an average 19.5% royalty interest on all production from this acreage with no additional future capital or operating expense required. Included in our total proved reserves, as of December 31, 2013, are 10,270 MBOE of proved reserves attributable to these mineral interests. During January 2014, net production attributable to the acquired mineral interests was approximately 2,100 net BOE per day. The acquisition price was funded with the net proceeds from our offering of senior notes discussed above. The free cash flow attributable to these mineral interests was approximately $4.0 million in December 2013.

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Martin and Dawson County Leasehold Acquisitions

In September 2013, we completed two separate acquisitions of additional leasehold interests in the Permian Basin from unrelated third party sellers for an aggregate purchase price of $165.0 million, subject to certain adjustments. The first of these acquisitions closed on September 4, 2013 when we acquired certain assets located in northwestern Martin County, Texas, consisting of a 100% working interest (80% net revenue interest) in 4,506 gross and net acres with an estimated 1,576 MBOE of proved developed reserves as of December 31, 2013. The second of these acquisitions closed on September 26, 2013, when we acquired certain assets located primarily in southwestern Dawson County, Texas, consisting of a 71% working interest (55% net revenue interest) in 9,390 gross (6,638 net) acres with an estimated 916 MBOE of proved developed reserves as of December 31, 2013. These acquisitions were funded with a portion of the net proceeds from the August 2013 equity offering discussed above.

Basis of Presentation

Since we began operations in 2007, we have increased our drilling activity, evaluated potential acquisitions and added to our acreage portfolio. Because of our growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.

Operating Results Overview

During the year ended December 31, 2013, our average daily production was approximately 7,321 BOE/d, consisting of 5,542 Bbls/d of oil, 4,741 Mcf/d of natural gas and 989 Bbls/d of natural gas liquids, an increase of 4,375 BOE/d, or 149%, from average daily production of 2,946 BOE/d for the year ended December 31, 2012, consisting of 2,066 Bbls/d of oil, 2,277 Mcf/d of natural gas and 500 Bbls/d of natural gas liquids.

During the year ended December 31, 2013, we drilled 77 gross (70 net) wells, and participated in an additional 4 gross (2 net) non-operated wells, in the Permian Basin.

Reserves and pricing

Ryder Scott prepared estimates of our proved reserves at December 31, 2013, 2012 and 2011. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.



	2013	2012	2011
Estimated Net Proved Reserves:
Oil (Bbls)	42,600,852	26,196,859	18,100,473
Natural gas (Mcf)	61,679,496	34,570,148	20,551,465
Natural gas liquids (Bbls)	10,705,724	8,251,429	5,049,560
Total (BOE)	63,586,492	40,209,979	26,575,277

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	2013		2012		2011
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (Bbls)	$	92.59	$	88.13	$	93.09
Natural gas (Mcf)	$	4.13	$	2.86	$	3.91
Natural gas liquids (Bbls)	$	37.82	$	43.88	$	56.33

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the years ended December 31, 2013 and 2012, our revenues were derived 91% and 88%, respectively, from oil sales, 6% and 9%, respectively, from natural gas liquids sales and 3% and 3%, respectively, from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2013, West Texas Intermediate posted prices ranged from $86.65 to $110.62 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.08 to $4.52 per MMBtu. On December 31, 2013, the West Texas Intermediate posted price for crude oil was $98.17 per Bbl and the Henry Hub spot market price of natural gas was $4.31 per MMBtu.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time-to-time we enter into derivative arrangements for our crude oil and natural gas production. We utilize commodity derivatives to reduce our exposure to fluctuations in New York Mercantile Exchange West Texas Intermediate pricing, Argus Louisiana light sweet pricing and Inter–Continental Exchange, or ICE, pricing for Brent crude oil. While these derivative contracts stabilize our cash flows when market prices are below our contract prices, they also prevent us from realizing increases in our cash flow when market prices are higher than our contract prices. We will sustain cash and non-cash losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain cash and non-cash gains to the extent our derivatives contract prices are higher than market prices. Our derivatives contracts are not designated as accounting hedges and, as a result, gains or losses on derivatives contracts are recorded as other income (expense) in our statements of operations. For the year-end status of our derivatives, see Note 12—Derivatives, and for derivative contracts entered into subsequent to December 31, 2013, see Note 15—Subsequent Events in the Notes to the Combined Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Principal components of our cost structure

Lease operating and natural gas transportation and treating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.

Production and ad valorem taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

General and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.

Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.

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Impairment expense. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.

Other income (expense)

Interest income. This represents the interest received on our cash and cash equivalents.

Interest expense. We have financed a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our revolving credit facility and our net proceeds from the issuance of the senior notes. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Gain/Loss on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil. This amount represents (i) the recognition of non-cash gains and losses associated with our open derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into, and (ii) our cash gains and losses on the settlement of these commodity derivative instruments.

Loss from equity investment. This line item represents our proportionate share of the earnings and losses from our investment in the membership interests of Muskie, an equity method investment.

Income tax expense. Prior our initial public offering in October 2012, the operations of Windsor Permian and Windsor UT, as limited liability companies, were not subject to federal income taxes. At the date of the merger of Diamondback Energy LLC with and into Diamondback, a corresponding “first day” tax expense to net income from continuing operations was recorded to establish a net deferred tax liability for differences between the tax and book basis of Diamondback’s assets and liabilities. This charge was $54,142,000.

We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

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Results of Operations

The following table sets forth selected historical operating data for the periods indicated.



	Year Ended December 31,
	2013			2012			2011
	(In thousands, except per Bbl, Mcf and Boe amounts)
Operating Results:
Revenues
Oil and natural gas revenues	$	208,002		$	74,962		$	47,875
Other revenue	—			—			1,491
Operating Expenses
Lease operating expense	21,157			15,247			9,931
Production and ad valorem taxes	12,899			5,237			3,032
Gathering and transportation expense	918			424			202
Oil and natural gas services	—			—			1,733
Depreciation, depletion and amortization	66,597			26,273			15,601
General and administrative	11,036			10,376			3,655
Asset retirement obligation accretion expense	201			98			65
Total expenses	112,808			57,655			34,219
Income from operations	95,194			17,307			15,147
Net interest expense	(8,058		)	(3,607		)	(2,517		)
Other income - related party	1,077			2,132			—
Gain (loss) on derivative instruments, net	(1,872		)	2,617			(13,009		)
Loss from equity investment	—			(67		)	(7		)
Total other income (expense), net	(8,853		)	1,075			(15,533		)
Income (loss) before income taxes	86,341			18,382			(386		)
Provision for income taxes	31,754			54,903			—
Net income (loss)	$	54,587		$	(36,521	)	$	(386	)
Production Data:
Oil (Bbls)	2,022,749			756,286			449,434
Natural gas (Mcf)	1,730,497			833,516			413,640
Natural gas liquids (Bbls)	361,079			183,114			86,815
Combined volumes (Boe)	2,672,244			1,078,320			605,189
Daily combined volumes (Boe/d)	7,321			2,946			1,658
Average Prices⁽¹⁾:
Oil (per Bbl)	$	93.32		$	86.88		$	92.24
Natural gas (per Mcf)	3.61			2.85			3.98
Natural gas liquids (per Bbl)	36.00			37.57			54.98
Combined (per BOE)	77.84			69.52			79.11
Average Costs (per BOE)
Lease operating expense	$	7.92		$	14.14		$	16.41
Gathering and transportation expense	0.34			0.39			0.33
Production and ad valorem taxes	4.83			4.86			5.01
Production and ad valorem taxes as a % of sales	6.2		%	7.0		%	6.3		%
Depreciation, depletion, and amortization	24.92			24.36			25.78
General and administrative	4.13			9.62			6.04

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Comparison of the Years Ended December 31, 2013 and December 31, 2012

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $133,040,000, or 177%, to $208,002,000 for the year ended December 31, 2013 from $74,962,000 for the year ended December 31, 2012. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 4,375 BOE/d to 7,321 BOE/d during the year ended December 31, 2013 from 2,946 BOE/d during the year ended December 31, 2012. The total increase in revenue of approximately $133,040,000 was largely attributable to higher oil, natural gas liquids and natural gas production volumes for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The increases in production volumes were due to a combination of increased drilling activity and the effect for the full year in 2013 of the contribution of Gulfport’s Permian Basin assets on October 11, 2012 in connection with our initial public offering. Our production increased by 1,266,463 Bbls of oil, 177,965 Bbls of natural gas liquids and 896,981 Mcf of natural gas for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The net dollar effect of the increases in prices of approximately $13,768,000 (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $119,272,000 (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.



	Change in prices			Production volumes⁽¹⁾		Total net dollar effect of change (in thousands)
Effect of changes in price:
Oil	$	6.44		2,022,749		$	13,022
Natural gas liquids	$	(1.57	)	361,079		$	(564	)
Natural gas	$	0.76		1,730,497		$	1,310
Total revenues due to change in price						$	13,768

	Change in production volumes⁽¹⁾			Prior period Average Prices		Total net dollar effect of change (in thousands)
Effect of changes in production volumes:
Oil	1,266,463			$	86.88	$	110,027
Natural gas liquids	177,965			$	37.57	$	6,685
Natural gas	896,981			$	2.85	$	2,560
Total revenues due to change in production volumes						$	119,272
Total change in revenues						$	133,040




(1	)	Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas

Lease Operating Expense. Lease operating expense, or LOE, was $21,157,000 ($7.92 per BOE) for the year ended December 31, 2013, an increase of $5,910,000, or 39%, from $15,247,000 ($14.14 per BOE) for the year ended December 31, 2012. The increase was due to increased drilling activity and acquisitions, which resulted in 126 gross (105 net) additional producing wells at December 31, 2013 as compared to December 31, 2012. On a per BOE basis, LOE declined successively for each quarter throughout 2013 as new volumes came on line and expenses were held in line or were reduced. By the end of 2013, we were moving 70% of our produced water by pipeline directly into commercial salt water disposal wells, rather than by truck, thereby further reducing one of the largest components of LOE.

Production and Ad Valorem Tax Expense. Production and ad valorem taxes increased to $12,899,000 for the year ended December 31, 2013 from $5,237,000 for the year ended December 31, 2012. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. During 2013, our production taxes per BOE increased by 2% as compared to 2012, primarily reflecting the impact of higher

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oil and natural gas prices on production taxes. Our ad valorem taxes have increased primarily as a result of increased valuations on our properties and an increase in the number of wells included in those valuations as a result of our 2013 drilling activity.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased $40,324,000, or 153%, from $26,273,000 for the year ended December 31, 2012 to $66,597,000 for the year ended December 31, 2013. The average depletion rate was $24.92 for the year ended December 31, 2013 and $24.36 for the year ended December 31, 2012. The average depletion rate includes oil and gas depletion and other property and equipment depreciation.

The following table provides components of our DD&A expense for the periods presented:



	Year Ended December 31,
	2013		2012
Depletion of proved oil and natural gas properties	$	65,821,000	$	25,772,000
Depreciation of other property and equipment	776,000		501,000
DD&A	$	66,597,000	$	26,273,000

Oil and natural gas properties DD&A per BOE	$	24.63	$	23.90
Total DD&A per BOE	$	24.92	$	24.36

The increases in depletion of proved oil and natural gas properties of $40,049,000 and $0.73 per BOE for the year ended December 31, 2013 compared to 2012 resulted primarily from higher total production levels, increased net book value on new reserves added and an increase in capitalized interest to the full cost pool.

General and Administrative Expense. General and administrative expense increased $660,000 from $10,376,000 for the year ended December 31, 2012 to $11,036,000 for the year ended December 31, 2013. The increase was due to increases in salary, legal and compliance services, professional service and advisory service expenses. These increases were partially offset by a decrease in stock based compensation, increases in general and administrative costs related to exploration and development activity capitalized to the full cost pool and increases in COPAS overhead reimbursements due to increased drilling activity.

Net Interest Expense. Net interest expense for the year ended December 31, 2013 was $8,058,000, as compared to $3,607,000 for the year ended December 31, 2012, an increase of $4,451,000, or 123%. This increase was due primarily to the interest expense associated with the senior notes.

Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our combined consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the years ended December 31, 2013 and 2012, we had a cash loss on settlement of derivative instruments of $7,218,000 and $5,440,000, respectively. For the years ended December 31, 2013 and 2012, we had a non-cash gain on open derivative instruments of $5,346,000 and $8,057,000, respectively.

Income tax expense. Prior to our initial public offering in October 2012, the operations of Windsor Permian and Windsor UT, as limited liability companies, were not subject to federal income taxes. As of October 11, 2012, the date of the merger of Diamondback Energy LLC with and into Diamondback, a corresponding “first day” tax expense to net income from continuing operations was recorded to establish a net deferred tax liability for differences between the tax and book basis of Diamondback’s assets and liabilities. This charge was $54,142,000. For the year ended December 31, 2012, we recorded a deferred income tax expense of $54,903,000. Income tax expense of $761,000 was incurred as a result of operations from October 11, 2012 through December 31, 2012. For the year ended December 31, 2013, our provision for income taxes was $31,754,000.

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Comparison of the Years Ended December 31, 2012 and December 31, 2011

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $27,087,000, or 57%, to $74,962,000 for the year ended December 31, 2012 from $47,875,000 for the year ended December 31, 2011. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 1,288 BOE/d to 2,946 BOE/d during the year ended December 31, 2012 from 1,658 BOE/d during the year ended December 31, 2011. The total increase in revenue of approximately $27,087,000 was largely attributable to higher oil, natural gas liquids and natural gas production volumes for the year ended December 31, 2012 as compared to the year ended December 31, 2011. The increases in production volumes were due to a combination of increased drilling activity and the effect of the contribution of Gulfport’s Permian Basin assets during the period October 11, 2012 through December 31, 2012. The revenue increase attributable to the contribution of assets from Gulfport during the period October 11, 2012 through December 31, 2012 was $7,353,000. Our production increased by 306,852 Bbls of oil, 96,299 Bbls of natural gas liquids and 419,876 Mcf of natural gas for the year ended December 31, 2012 as compared to the year ended December 31, 2011. The net dollar effect of the decreases in prices of approximately $8,183,000 (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $35,270,000 (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.



	Change in prices			Production volumes⁽¹⁾		Total net dollar effect of change (in thousands)
Effect of changes in price:
Oil	$	(5.36	)	756,286		$	(4,055	)
Natural gas liquids	$	(17.41	)	183,114		$	(3,188	)
Natural gas	$	(1.13	)	833,516		$	(940	)
Total revenues due to change in price						$	(8,183	)

	Change in production volumes⁽¹⁾			Prior period Average Prices		Total net dollar effect of change (in thousands)
Effect of changes in production volumes:
Oil	306,852			$	92.24	$	28,304
Natural gas liquids	96,299			$	54.98	$	5,294
Natural gas	419,876			$	3.98	$	1,672
Total revenues due to change in production volumes						$	35,270
Total change in revenues						$	27,087




(1	)	Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas

Lease Operating Expense. We have reclassified 2012 ad valorem tax amounts from lease operating expenses to production and ad valorem taxes to conform with the current year’s presentation. Lease operating expense was $15,247,000 ($14.14 per BOE) for the year ended December 31, 2012, an increase of $5,316,000, or 54%, from $9,931,000 ($16.41 per BOE) for the year ended December 31, 2011. The increase was due to increased drilling activity, which resulted in additional producing wells for the year ended December 31, 2012 as compared to the year ended December 31, 2011. Our lease operating expense during both periods was adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on-line in 2011. During the fourth quarter of 2012, we completed construction of a gas gathering system that transports our gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense. We believe that the completion of gathering systems, the connection to salt water disposal wells and other actions will help us to further reduce our lease operating expense in future periods.

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Production and Ad Valorem Tax Expense. Production and ad valorem taxes increased to $5,237,000 for the year ended December 31, 2012 from $3,032,000 during the year ended December 31, 2011. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. During 2012, our production taxes per BOE decreased by 6% as compared to 2011, primarily reflecting the impact of lower oil and natural gas prices on production taxes. Our ad valorem taxes have increased primarily as a result of increased valuations on our properties and an increase in the number of wells included in those valuations as a result of our 2012 drilling activity.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $10,672,000, or 68%, from $15,601,000 for the year ended December 31, 2011 to $26,273,000 for the year ended December 31, 2012. The average depletion rate was $24.36 for the year ended December 31, 2012 and $25.78 for the year ended December 31, 2011. The average depletion rate includes oil and gas depletion and other property and equipment depreciation.

The following table provides components of our DD&A expense for the periods presented:



	Year Ended December 31,
	2012		2011
Depletion of proved oil and natural gas properties	$	25,772,000	$	15,377,000
Depreciation of other property and equipment	501,000		224,000
DD&A	$	26,273,000	$	15,601,000

Oil and natural gas properties DD&A per BOE	$	23.90	$	25.41
Total DD&A per BOE	$	24.36	$	25.78

The increase in depletion of proved oil and natural gas properties of $10,395,000 and decrease of $1.51 per BOE for the year ended December 31, 2012 compared to 2011 resulted primarily from higher total production levels and the decrease in depletion rate per BOE was due to an increase in proved reserves at December 31, 2012.

General and Administrative Expense. General and administrative expense increased $6,721,000 from $3,655,000 for the year ended December 31, 2011 to $10,376,000 for the year ended December 31, 2012. The increase was due to increases in salary, legal, professional service and contract labor expenses. These increases were partially offset by increases in general and administrative costs related to exploration and development activity capitalized to the full cost pool and increases in COPAS overhead reimbursements due to increased drilling activity. In connection with our initial public offering, we incurred a non-recurring charge to our fourth quarter general and administrative expense of approximately $2.7 million for executive bonuses and non-cash equity based compensation expense associated with such offering.

Net Interest Expense. Net interest expense for the year ended December 31, 2012 was $3,607,000, as compared to $2,517,000 for the year ended December 31, 2011, an increase of $1,090,000. This increase was due primarily to an increase in our weighted average outstanding borrowings under our credit agreement to $77,489,000 for the year ended December 31, 2012 from $68,420,000 for 2011.

Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our combined consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the years ended December 31, 2012 and 2011, we had a cash loss on settlement of derivative instruments of $5,440,000 and $37,000, respectively. For the years ended December 31, 2012 and 2011, we had a non-cash gain on open derivative instruments of $8,057,000 and a non-cash loss on open derivative instruments of $12,972,000 respectively.

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For the year ended December 31, 2012, we recorded a deferred income tax expense of $54,903,000. Income tax expense of $761,000 was incurred as a result of operations from October 11, 2012 through December 31, 2012.

Liquidity and Capital Resources

Our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of the senior notes, cash flows from operations and, prior to the completion of our initial public offering, capital contributions and loans from our equity sponsor. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. As we pursue reserves and production growth, we regularly consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.

Liquidity and cash flow

Our cash flows for the years ended December 31, 2013, 2012 and 2011 are presented below:



	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Net cash provided by operating activities	$	155,777		$	49,692		$	30,998
Net cash used in investing activities	(940,140		)	(183,078		)	(81,108		)
Net cash provided by financing activities	$	773,560		$	152,785		$	52,950
Net change in cash	$	(10,803	)	$	19,399		$	2,840

Operating Activities

Net cash provided by operating activities was $155,777,000 for the year ended December 31, 2013 as compared to $49,692,000 for the year ended December 31, 2012. The increase in operating cash flows is primarily a result of increases in our oil and natural gas revenues due to production growth and by lower expenses in 2013.

Net cash provided by operating activities was $49,692,000 for the year ended December 31, 2012 as compared to $30,998,000 for the year ended December 31, 2011. The increase in operating cash flows is largely due to increased production which was a result of our increased drilling activities throughout 2012.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cash for investing activities of $940,140,000, $183,078,000 and $81,108,000 during the years ended December 31, 2013, 2012 and 2011, respectively.

During the year ended December 31, 2013, we spent $297,713,000 on capital expenditures in conjunction with our infrastructure projects and drilling program, in which we drilled 77 gross (70 net) wells and participated in the drilling of an additional four gross (two net) non-operated wells. We spent an additional $444,083,000 on the acquisition of mineral rights, $177,343,000 on the acquisition of leasehold interests, $2,234,000 for the purchase of other property and equipment, $289,000, net, on the settlement of non-hedge derivative instruments and $18,550,000 for the post-closing cash adjustment associated with the Gulfport transaction. Our acquisition of mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas in the Permian Basin was completed on September 19, 2013. The mineral interests entitle us to receive an average 19.5% royalty interest on all production from this acreage with no additional future capital or operating expense required. In September 2013, we also completed two leasehold acquisitions in Martin County, Texas and Dawson County, Texas for an aggregate purchase price of $166,635,000 subject to adjustment.

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During the year ended December 31, 2012, we spent $100,090,000 on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 65 gross (44 net) wells. We spent an additional $11,707,000 on the acquisition of leasehold interests, $1,102,000 for the purchase of other property and equipment and $6,637,000, net, on the settlement of derivative transactions. On October 11, 2012, we acquired all of the oil and natural gas properties of Gulfport located in the Permian Basin in exchange for (i) 7,914,036 shares of our common stock, (ii) $63,590,000 in the form of a non-interest bearing promissory note that was repaid in full upon the closing of our initial public offering and (iii) a post-closing cash adjustment of approximately $18,550,000.

During 2011, we spent $76,470,000 on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 56 gross (32 net) wells. We spent an additional $3,704,000 on leasehold costs, $7,065,000 for the purchase of other property and equipment, $4,137,000 for the purchase of certain assets, real estate and leasehold interests which were subsequently contributed to Muskie and $2,460,000 for the purchase of drilling rigs and other equipment which were subsequently contributed to Bison. These amounts were partially offset by proceeds of $6,000,000 from a partial sale of our equity investment, $55,000 from the sale of property and equipment and $76,000 from the settlement of non-hedge derivative instruments and margin deposits.

Our investing activities for the years ended December 31, 2013, 2012 and 2011 are summarized in the following table:



	Year Ended December 31,
	2013			2012			2011
	(in thousands)
Drilling, completion and infrastructure	$	(297,713	)	$	(100,090	)	$	(76,470	)
Acquisition of leasehold interests	(177,343		)	(11,707		)	(3,704		)
Acquisition of Gulfport properties	(18,550		)	(63,590		)	—
Acquisition of mineral interests	(444,083		)	—			—
Purchase of other property and equipment	(2,234		)	(1,102		)	(7,065		)
Proceeds from sale of property and equipment	72			48			55
Settlement of non-hedge derivative instruments	(289		)	(8,963		)	(4,127		)
Receipt on derivative margins	—			2,326			4,203
Proceeds from equity investment, net	—			—			6,000
Net cash used in investing activities	$	(940,140	)	$	(183,078	)	$	(81,108	)

Financing Activities

Net cash provided by financing activities for the year ended December 31, 2013 was $773,560,000 as compared to $152,785,000 for the year ended December 31, 2012. The 2013 amount provided by financing activities was primarily attributable to (a) the net proceeds of $144.4 million from our May 2013 equity offering, $177.5 million from our August 2013 equity offering and $450.0 million from our September 2013 senior note offering and (b) net borrowings of $10.0 million under our revolving credit facility. During the year ended December 31, 2012, we borrowed $15.0 million under our revolving credit facility and $30.0 million under our subordinated note with Wexford and received capital contributions from our members of $4.0 million. In both periods, these proceeds were used primarily to acquire property and fund our drilling costs.

Net cash provided by financing activities for 2012 was $152,785,000 as compared to $52,950,000 for 2011. On October 17, 2012, our initial public offering was completed and we received net proceeds of approximately $234.1 million, after deducting the underwriting discount. During 2012 we borrowed $15.0 million under our revolving credit facility. All borrowings outstanding under our revolving credit facility were repaid with proceeds of the initial public offering. During 2012, we borrowed $30.0 million under our subordinated note with Wexford. This note was repaid with proceeds of the initial public offering and was canceled. During 2012, we received capital contributions from our members of $4.0 million. These proceeds were used primarily to fund our drilling costs and purchase property. During the year ended December 31, 2012, we paid $2.9 million for costs associated with our initial public offering.

Net cash provided by financing activities for 2011 was $52,950,000. During 2011, we borrowed $40.2 million under our revolving credit facility and received capital contributions from our members of $13.5 million. These proceeds were used primarily to fund our drilling costs and purchase property and equipment.

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Senior Notes

On September 18, 2013, we completed an offering of $450.0 million in aggregate principal amount of 7.625% senior unsecured notes due 2021, which we refer to as the senior notes. The senior notes bear interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October 1 of each year, commencing on April 1, 2014, and will mature on October 1, 2021. The senior notes are fully and unconditionally guaranteed by our subsidiaries. The net proceeds from the senior notes were used to fund the acquisition of mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas in the Permian Basin. The senior notes were issued to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act.

The senior notes were issued under, and are governed by, an indenture among us, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as the trustee, or the Indenture. We may issue additional senior notes under the Indenture, and all senior notes issued under the Indenture will constitute part of a single class of securities for all purposes of the Indenture. On November 5, 2013, we supplemented the Indenture by the first supplemental indenture thereto to add a subsidiary guarantor of the senior notes. The Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on, or redeem or repurchase, capital stock, prepay subordinated indebtedness, sell assets including capital stock of subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. If we experience certain kinds of changes of control or if we sell certain of our assets, holders of the senior notes may have the right to require us to repurchase their senior notes.

We have the option to redeem the senior notes, in whole or in part, at any time on or after October 1, 2016 at the redemption prices (expressed as percentages of principal amount) of 105.719% for the 12-month period beginning on October 1, 2016, 103.813% for the 12-month period beginning on October 1, 2017, 101.906% for the 12-month period beginning on October 1, 2018 and 100.000% beginning on October 1, 2019 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. In addition, prior to October 1, 2016, we may redeem all or a part of the senior notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium at the redemption date. Furthermore, before October 1, 2016, we may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the senior notes with the net cash proceeds of certain equity offerings at a redemption price of 107.625% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes originally issued under the Indenture remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering.

In connection with the issuance of the senior notes, we and the subsidiary guarantors entered into a registration rights agreement with the initial purchasers on September 18, 2013, pursuant to which we and the subsidiary guarantors have agreed to file a registration statement with respect to an offer to exchange the senior notes for a new issue of substantially identical debt securities registered under the Securities Act. Under the registration rights agreement, we also agreed to use our commercially reasonable efforts to cause the exchange offer registration statement to become effective within 360 days after the issue date of the senior notes and to consummate the exchange offer 30 days after effectiveness. We may be required to file a shelf registration statement to cover resales of the senior notes under certain circumstances. If we fail to satisfy certain of our obligations under the registration rights agreement, we agreed to pay additional interest to the holders of the senior notes as specified in the registration rights agreement.

Second Amended and Restated Credit Facility

On October 15, 2010, we entered into a secured revolving credit agreement with BNP Paribas, or BNP, as the administrative agent, sole book runner and lead arranger. On May 10, 2012, the revolving credit agreement was amended to provide for the resignation of BNP, and the appointment of Wells Fargo Bank, National Association, as administrative agent for the lenders. The credit agreement was amended and restated as of July 24, 2012 and again as of November 1, 2013. The credit agreement, as so amended and restated, provides for a revolving credit facility in the maximum amount of $600 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, we may request up to three additional redeterminations of the borrowing base during any 12-month period.

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As of December 31, 2013, the borrowing base was set at $225.0 million. As of December 31, 2013, we had outstanding borrowings of $10.0 million which bore a weighted average interest rate of 1.67%. Based on preliminary discussions with the administrative agent for our revolving credit agreement, we believe that after giving consideration to our reserve report dated December 31, 2013 and the completion of our pending acquisition in Martin County, Texas, our reserves will support a borrowing base in the range of $375.0 million to $400.0 million.

The outstanding borrowings under the credit agreement bear interest at a rate elected by us that is based on the prime rate or LIBOR plus margins ranging from 0.50% for prime-based loans and 1.50% for LIBOR loans to 1.50% for prime-based loans and 2.50% for LIBOR loans, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.50% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2018. The loan is secured by substantially all of our assets.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.



Financial Covenant			Required Ratio
Ratio of total debt to EBITDAX			Not greater than 4.0 to 1.0
Ratio of consolidated current assets to consolidated current liabilities, as defined in the credit agreement			Not less than 1.0 to 1.0
EBITDAX will be annualized beginning with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2014.

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $750 million in the form of senior or senior subordinated notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. As of December 31, 2013, we had $450 million of senior notes outstanding.

As of December 31, 2013 and December 31, 2012, we were in compliance with all financial covenants under our revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of our revolving credit facility generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Capital Requirements and Sources of Liquidity

We currently anticipate our 2014 capital budget for drilling and infrastructure will be approximately $425.0 million to $475.0 million, representing an increase of 48% over 2013. We estimate that, of these expenditures, approximately:


•	85% will be spent on 65 to 75 gross (52 to 60 net) operated horizontal wells focused in Midland, Andrews, Martin and Dawson Counties;


•	8% will be spent on 20 to 25 gross (16 to 20 net) operated vertical wells (with an assumed average working interest of 90%) focused in Midland County;


•	5% will be spent on infrastructure; and


•	2% will be spent on non-operated drilling.

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The amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

Based upon current oil and natural gas price expectations for 2014, we believe that our cash flow from operations and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2014. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2014 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

We monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We may also consider the formation of a master limited partnership or other yield based vehicle with respect to our mineral interests in the Permian Basin. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Contractual Obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2013:



	Payments Due by Period
	Total		2014		2015-2016		2017-2018		2019 & Beyond
	(in thousands)
Secured revolving credit facility⁽¹⁾	$	10,000	$	—	$	—	$	10,000	$	—
Senior notes	450,000		—		—		—		450,000
Interest expense⁽²⁾	276,216		34,313		68,625		68,625		104,653
Asset retirement obligations⁽³⁾	3,029		40		—		—		2,989
Drilling commitments⁽⁴⁾	4,729		4,729		—		—		—
Fracturing and well stimulation service agreements	3,600		3,600		—		—		—
Operating lease obligations	2,180		667		1,187		326		—
	$	749,754	$	43,349	$	69,812	$	78,951	$	557,642

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(1)	Includes the outstanding principal amount under our revolving credit facility, 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 our senior notes.
(3)	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 5 of the notes to our combined consolidated financial statements set forth in Part IV, Item 15 of this Form 10-K.
(4)	Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2013.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our combined consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2 of the Notes to the Combined Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Use of Estimates

Certain amounts included in or affecting our combined consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the combined consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the combined consolidated financial statements. Actual results could differ from those estimates.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, stock-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.

Method of accounting for oil and natural gas properties

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to

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drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Revenue recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. We account for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when our volumes exceed our estimated remaining recoverable reserves. No receivables are recorded for those wells where we have taken less than our ownership share of production. We did not have any gas imbalances as of December 31, 2013, 2012 and 2011. Revenues from oil and natural gas services are recognized as services are provided.

Impairment

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil and natural gas reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, prices are calculated as the average oil and gas prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period.

Asset retirement obligations

We measure the future cost to retire our tangible long-lived assets and recognize such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

Our asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public

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relations considerations. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and gas property balance.

Derivatives

From time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil. We recognize all of our derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. None of our derivatives were designated as hedging instruments during the years ended December 31, 2013, 2012 and 2011. For derivative instruments not designated as hedging instruments, changes in the fair value of these instruments are recognized in earnings during the period of change.

Accounting for Stock-Based Compensation

We grant various types of stock-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 9—Stock and Equity Based Compensation. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.

Income Taxes

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the years ended 2013, 2012 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Off-balance Sheet Arrangements

We currently have no off-balance sheet arrangements. Please read Note 14 included in Notes to the Combined Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10–K, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control.

We use price swap derivatives to reduce price volatility associated with certain of our oil sales. With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative contracts are based upon

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reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing, Argus Louisiana light sweet pricing or Inter–Continental Exchange, or ICE, pricing for Brent crude oil.

At December 31, 2013, we had a net asset derivative position with Wells Fargo Bank, N.A. of $431,000, related to our ICE Brent and Argus Louisiana Light Sweet fixed price swaps, as compared to a net liability derivative position of $5,205,000 as of December 31, 2012 related to our price swap derivatives. Utilizing actual derivative contractual volumes under our fixed price swaps with Wells Fargo Bank, N.A. as of December 31, 2013, a 10% increase in forward curves associated with the underlying commodity would have decreased the net asset derivative position of these instruments to a net liability derivative position of $10,471,000, a decrease of $10,902,000, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset derivative position of these instruments by $10,902,000. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $12,226,000 at December 31, 2013) and receivables from the sale of our oil and natural gas production (approximately $24,836,000 at December 31, 2013).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2013, two purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (37%); and Shell Trading (US) Company (37%). For the year ended December 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (53%); Occidental Energy Marketing, Inc. (16%); and Andrews Oil Buyers Inc. (10%). For the year ended December 31, 2011, one purchaser, Midstream, accounted for approximately 79% of our revenue. No other customer accounted for more than 10% of our revenue during these periods.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2013, we had one customer that represented approximately 86% of our total joint operations receivables. At December 31, 2012, we had one customer that represented approximately 97% of our total joint operations receivables.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 0.5% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. As of December 31, 2013, the weighted average interest rate on our borrowings was 1.67%. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income of approximately $100,000 based on the $10,000,000 outstanding in the aggregate under our revolving credit facility on December 31, 2013.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item appears beginning on page F-1 of this report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of December 31, 2013, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2013, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.

As of December 31, 2013, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting at December 31, 2013.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2013. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2013, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Diamondback Energy, Inc.

We have audited the internal control over financial reporting of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the combined consolidated financial statements of the Company as of and for the year ended December 31, 2013, and our report dated February 19, 2014 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

February 19, 2014

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ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accounting officer and controller and persons performing similar functions. The Code of Business Conduct and Ethics is posted on our website at http://ir.diamondbackenergy.com/governance.cfm. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.

ITEM 11. EXECUTIVE COMPENSATION

Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



(a)	Documents included in this report:
	1. Financial Statements

	Report of independent registered public accounting firm	F-1
	Consolidated Balance Sheets as of December 31, 2013 and 2012	F-2
	Combined Consolidated Statements of Operations for the Year Ended December 31, 2013, 2012 and 2011	F-3
	Combined Consolidated Statement of Stockholders’ Equity/Members’ Equity for the Year Ended December 31, 2013, 2012 and 2011	F-5
	Combined Consolidated Statements of Cash Flows for the Year Ended December 31, 2013, 2012 and 2011	F-6
	Notes to Combined Consolidated Financial Statements	F-8

	2. Financial Statement Schedules
	Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s combined consolidated financial statements and related notes.

	3. Exhibits
	The Exhibit Index beginning on page E–1 of this report is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		DIAMONDBACK ENERGY, INC.

Date:	February 19, 2014	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ Steven E. West	Chairman of the Board and Director	February 19, 2014
Steven E. West

/s/ Travis D. Stice	Chief Executive Officer and Director	February 19, 2014
Travis D. Stice

/s/ Michael P. Cross	Director	February 19, 2014
Michael P. Cross

/s/ David L. Houston	Director	February 19, 2014
David L. Houston

/s/ Mark L. Plaumann	Director	February 19, 2014
Mark L. Plaumann

/s/ Teresa L. Dick	Chief Financial Officer, Senior Vice President, and Assistant Secretary	February 19, 2014
Teresa L. Dick

S-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Diamondback Energy, Inc.

We have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related combined consolidated statements of operations, stockholders’/members’ equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined consolidated financial statements referred to above present fairly, in all material respects, the financial position of Diamondback Energy, Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 19, 2014, expressed an unqualified opinion thereon.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

February 19, 2014

F-1

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets



	December 31,
	2013			2012
Assets	(In thousands, except par values and share data)
Current assets:
Cash and cash equivalents	$	15,555		$	26,358
Accounts receivable:
Joint interest and other	14,437			5,959
Oil and natural gas sales	23,533			8,081
Related party	1,303			772
Inventories	5,631			6,195
Deferred income taxes	112			1,857
Derivative instruments	213			—
Prepaid expenses and other	1,184			1,053
Total current assets	61,968			50,275

Property and equipment
Oil and natural gas properties, based on the full cost method of accounting ($369,561 and $121,245 excluded from amortization at December 31, 2013 and December 31, 2012, respectively)	1,648,360			697,742
Pipeline and gas gathering assets	6,142			—
Other property and equipment	4,071			2,337
Accumulated depletion, depreciation, amortization and impairment	(212,236		)	(145,837		)
	1,446,337			554,242

Derivative instruments	218			—
Other assets	13,091			2,184
Total assets	$	1,521,614		$	606,701
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	2,679		$	12,141
Accounts payable-related party	17			18,813
Accrued capital expenditures	74,649			29,397
Other accrued liabilities	34,750			10,649
Revenues and royalties payable	9,225			3,270
Derivative instruments	—			4,817
Note payable-short term	—			145
Total current liabilities	121,320			79,232

Long-term debt	460,000			193
Derivative instruments	—			388
Asset retirement obligations	2,989			2,125
Deferred income taxes	91,764			62,695
Total liabilities	676,073			144,633
Commitments and contingencies (Note 14)
Stockholders’ equity:
Common stock, $0.01 par value, 100,000,000 shares authorized, 47,106,216 issued and outstanding at December 31, 2013; 36,986,532 issued and outstanding at December 31, 2012	471			370
Additional paid-in capital	842,557			513,772
Retained earnings (accumulated deficit)	2,513			(52,074		)
Total stockholders’ equity	845,541			462,068
Total liabilities and stockholders’ equity	$	1,521,614		$	606,701

See accompanying notes to combined consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Combined Consolidated Statements of Operations



	Year Ended December 31,
	2013			2012			2011
	(In thousands, except per share amounts)
Revenues:
Oil sales	$	188,753		$	65,704		$	2,582
Oil sales - related party	—			—			38,873
Natural gas sales	3,715			1,369			1,061
Natural gas sales - related party	2,534			1,010			586
Natural gas liquid sales	8,304			3,839			3,169
Natural gas liquid sales - related party	4,696			3,040			1,604
Oil and natural gas services - related party	—			—			1,491
Total revenues	208,002			74,962			49,366
Costs and expenses:
Lease operating expenses	19,991			14,231			7,804
Lease operating expenses - related party	1,166			1,016			2,127
Production and ad valorem taxes	12,399			4,950			1,240
Production and ad valorem taxes - related party	500			287			1,792
Gathering and transportation	237			124			53
Gathering and transportation - related party	681			300			149
Oil and natural gas services	—			—			1,207
Oil and natural gas services - related party	—			—			526
Depreciation, depletion and amortization	66,597			26,273			15,601
General and administrative expenses (including non-cash stock based compensation, net of capitalized amounts, of $1,752, $2,477 and $438 for the years ended December 31, 2013, 2012 and 2011, respectively)	9,870			9,178			495
General and administrative expenses - related party	1,166			1,198			3,160
Asset retirement obligation accretion expense	201			98			65
Total costs and expenses	112,808			57,655			34,219
Income from operations	95,194			17,307			15,147
Other income (expense)
Interest income	1			3			11
Interest expense	(8,059		)	(3,610		)	(2,528		)
Other income - related party	1,077			2,132			—
Gain (loss) on derivative instruments, net	(1,872		)	2,617			(13,009		)
Loss from equity investment	—			(67		)	(7		)
Total other income (expense), net	(8,853		)	1,075			(15,533		)
Income (loss) before income taxes	86,341			18,382			(386		)
Provision for income taxes
Current	191			—			—
Deferred	31,563			54,903			—
Net income (loss)	$	54,587		$	(36,521	)	$	(386	)
Earnings per common share
Basic	$	1.30
Diluted	$	1.29
Weighted average common shares outstanding
Basic	42,015
Diluted	42,255

See accompanying notes to combined consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Combined Consolidated Statements of Operations - Continued



	Year Ended December 31,
	2012
	(In thousands, except per share amounts)
Pro forma information (unaudited)
Income before income taxes, as reported	$	18,382
Pro forma provision for income taxes	6,553
Pro forma net income	$	11,829

Pro forma earnings per common share
Basic	$	0.60
Diluted	$	0.60
Pro forma weighted average common shares outstanding
Basic	19,721
Diluted	19,724

See accompanying notes to combined consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity/Members’ Equity



									Retained
							Additional		Earnings/
	Member’s			Common Stock			Paid-in		(Accumulated
	Equity			Shares	Amount		Capital		Deficit)			Total
	(In thousands)
Balance, December 31, 2010	$	115,362		—	$	—	$	—	$	—		$	115,362
Contributions	13,517			—	—		—		—			13,517
Equity based compensation	544			—	—		—		—			544
Net loss	(386		)	—	—		—		—			(386		)
Balance December 31, 2011	129,037			—	—		—		—			129,037

Contributions	4,008			—	—		—		—			4,008
Distributions of equity method investments	(10,504		)	—	—		—		—			(10,504		)
Equity based compensation	873			—	—		—		—			873
Earnings prior to merger	15,553			—	—		—		—			15,553
Common shares issued upon Merger	(138,967		)	14,697	147		138,820		—			—
Common shares issued upon acquisition of Gulfport properties	—			7,914	79		138,417		—			138,496
Common shares issued at initial public offering, net of offering costs	—			14,375	144		234,000		—			234,144
Stock based compensation	—			—	—		2,535		—			2,535
Net loss subsequent to merger	—			—	—		—		(52,074		)	(52,074		)
Balance December 31, 2012	—			36,986	370		513,772		(52,074		)	462,068

Stock based compensation	—			—	—		2,724		—			2,724
Tax benefits related to stock-based compensation	—			—	—		749		—			749
Common shares issued in public offering, net of offering costs	—			9,775	98		321,814		—			321,912
Exercise of stock options and vesting of restricted stock units	—			345	3		3,498		—			3,501
Net income	—			—	—		—		54,587			54,587
Balance December 31, 2013	$	—		47,106	$	471	$	842,557	$	2,513		$	845,541

See accompanying notes to combined consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Combined Consolidated Statements of Cash Flows



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	54,587		$	(36,521	)	$	(386	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for deferred income taxes	31,563			54,903			—
Excess tax benefit from stock-based compensation	(749		)	—			—
Asset retirement obligation accretion expense	201			98			65
Depreciation, depletion, and amortization	66,597			26,273			16,104
Amortization of debt issuance costs	1,018			494			250
Change in fair value of derivative instruments	(5,346		)	(2,617		)	13,009
Loss from equity investment	—			67			—
Equity based compensation expense	1,752			3,482			544
Gain on sale of assets	(39		)	(37		)	(23		)
Changes in operating assets and liabilities:
Accounts receivable	(19,973		)	(5,036		)	(1,547		)
Accounts receivable-related party	(532		)	6,096			(4,133		)
Inventories	554			(639		)	(872		)
Prepaid expenses and other	(271		)	(606		)	(202		)
Accounts payable and accrued liabilities	20,588			7,151			2,656
Accounts payable and accrued liabilities-related party	(128		)	(1,218		)	830
Revenues and royalties payable	5,955			105			2,666
Revenues and royalties payable-related party	—			(2,303		)	2,037
Net cash provided by operating activities	155,777			49,692			30,998
Cash flows from investing activities:
Additions to oil and natural gas properties	(278,809		)	(90,415		)	(58,160		)
Additions to oil and natural gas properties-related party	(13,777		)	(9,675		)	(22,014		)
Acquisition of Gulfport properties	(18,550		)	(63,590		)	—
Acquisition of mineral interests	(444,083		)	—			—
Acquisition of leasehold interests	(177,343		)	(11,707		)	—
Additions to pipeline and gas gathering assets	(5,127		)	—			—
Purchase of other property and equipment	(2,234		)	(1,102		)	(7,065		)
Proceeds from sale of property and equipment	72			48			55
Settlement of non-hedge derivative instruments	(289		)	(8,963		)	(4,127		)
Receipt on derivative margins	—			2,326			4,203
Deconsolidation of Bison	—			—			(10		)
Proceeds from sale of membership interest in equity investment	—			—			6,010
Net cash used in investing activities	(940,140		)	(183,078		)	(81,108		)
Cash flows from financing activities:
Proceeds from borrowings on credit facility	59,000			15,000			40,233
Repayment on credit facility	(49,000		)	(100,000		)	—
Proceeds from senior notes	450,000			—			—
Proceeds from note payable - related party	—			30,000			—
Payment of note payable - related party	—			(30,050		)	—
Debt issuance costs	(12,361		)	(450		)	(770		)
Public offering costs	(1,009		)	(2,887		)	(30		)
Proceeds from public offering	322,680			237,164			—

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Diamondback Energy, Inc. and Subsidiaries

Combined Consolidated Statements of Cash Flows - Continued



Exercise of stock options	3,501			—		—
Excess tax benefits of stock-based compensation	749			—		—
Contributions by members	—			4,008		13,517
Net cash provided by financing activities	773,560			152,785		52,950
Net increase (decrease) in cash and cash equivalents	(10,803		)	19,399		2,840
Cash and cash equivalents at beginning of period	26,358			6,959		4,119
Cash and cash equivalents at end of period	$	15,555		$	26,358	$	6,959



	Year Ended December 31,
	2013		2012		2011
	(In thousands)
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	404	$	3,017	$	2,265
Supplemental disclosure of non-cash transactions:
Asset retirement obligation incurred	$	226	$	386	$	297
Asset retirement obligation acquired	$	471	$	562	$	—
Distribution of equity method investments	$	—	$	10,504	$	—
Note payable exchanged for equipment	$	—	$	411	$	—
Common stock issued as a result of the Gulfport transaction	$	—	$	138,496	$	—
Post-closing adjustment payable as a result of the Gulfport transaction	$	—	$	18,550	$	—

See accompanying notes to combined consolidated financial statements.

F-7

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements

(Amounts in thousands, except per share, per BOE and acreage amounts)

1. ORGANIZATION

Diamondback Energy, Inc. (“Diamondback” or the “Company”) together with its subsidiaries, is an independent oil and gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware 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 (the “Merger”). Prior to the Merger, Diamondback Energy LLC was a holding company and did not conduct any material business operations other than its ownership of Diamondback’s common stock and the membership interests in Diamondback O&G LLC (formerly known as Windsor Permian LLC, or “Windsor Permian”). As a result of the Merger, Windsor Permian became a wholly-owned subsidiary of Diamondback. Also on October 11, 2012, Wexford Capital LP (“Wexford”), our equity sponsor, caused all of the outstanding equity interests in Windsor UT LLC (“Windsor UT”) to be contributed to Windsor Permian prior to the Merger in a transaction referred to as the “Windsor UT Contribution”. The Windsor UT Contribution was treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. The operations of Windsor Permian and Windsor UT, as limited liability companies, were not subject to federal income taxes. On the date of the Merger, a corresponding “first day” tax expense to net income from continuing operations was recorded to establish a net deferred tax liability for differences between the tax and book basis of Diamondback’s assets and liabilities. This charge was $54,142. The Company refers to the historical results of Windsor Permian and Windsor UT prior to October 11, 2012 as the “Predecessors”.

Immediately after the Merger on October 11, 2012, Diamondback acquired from Gulfport Energy Corporation (“Gulfport”) all of its oil and natural gas interests in the Permian Basin (the “Gulfport properties”) in exchange for shares of Diamondback common stock and a promissory note in a transaction referred to as the “Gulfport transaction”. The Gulfport transaction was treated as a business combination accounted for under the acquisition method of accounting with the identifiable assets and liabilities recognized at fair value on the date of transfer. See Note 3—Acquisitions for information regarding the acquisition.

On October 17, 2012, the Company completed its initial public offering (“IPO”) of 14,375 shares of common stock, which included 1,875 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $17.50 per share and the Company received net proceeds of approximately $234,100 from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

In the first quarter of 2013, Windsor UT merged with and into Windsor Permian and Windsor Permian, the surviving entity in the merger, was renamed Diamondback O&G LLC (“Diamondback O&G”).

On May 21, 2013, the Company completed an underwritten primary public offering of 5,175 shares of common stock, which included 675 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $29.25 per share and the Company received net proceeds of approximately $144,439 from the sale of these shares of common stock, after offering expenses and underwriting discounts and commissions.

On June 24, 2013, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 6,000 shares of the Company’s common stock and, on July 5, 2013, the underwriters purchased an additional 869 shares of the Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering.

In August 2013, the Company completed an underwritten public offering of 4,600 shares of common stock, which included 600 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold the public at $40.25 per share and the Company received net proceeds of

F-8

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

approximately $177,500 from the sale of these shares of common stock, after offering expenses and underwriting discounts and commissions.

In September 2013, the Company completed an offering of $450,000 principal amount of our 7.625% Senior Notes due 2021. See Note 7—Debt.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Transfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. As discussed above, the Windsor UT Contribution was accounted for as a transaction between entities under common control. Thus, the accompanying combined consolidated financial statements and related notes of the Company have been retrospectively adjusted to include the historical results of Windsor UT at historical carrying values and its operations prior to October 11, 2012, the effective date of the Windsor UT Contribution. The accompanying financial statements and related notes presented herein represent the combined results of operations and cash flows of the Predecessors through October 11, 2012, and the Company and its wholly-owned subsidiaries consolidated financial position, results of operations, cash flows and equity subsequent to October 11, 2012. All intercompany balances and transactions are eliminated in consolidation.

Use of Estimates

Certain amounts included in or affecting the Company’s combined consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the combined consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the combined consolidated financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, stock-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.

Reclassifications

The Company has reclassified certain prior year amounts to conform with the current year’s presentation. The Company has reclassified ad valorem taxes from lease operating expenses to production and ad valorem taxes.

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments are received within three months after the production date.

Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the

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Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2013 or December 31, 2012.

Derivative Instruments

The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments in the combined consolidated statements of operations.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivatives, notes payable and senior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The note payable is carried at cost, which approximates fair value due to the nature of the instrument and relatively short maturity. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 13—Fair Value Measurements).

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 6—Equity Method Investments). Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $24.63, $23.90 and $25.41 for the years ended December 31, 2013, 2012 and 2011, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $65,821, $25,772 and $15,377 for the years ended December 31, 2013, 2012 and 2011, respectively.

Under the full cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10%. Estimated future net cash flows exclude future cash flows associated with settling accrued asset retirement obligations. Estimated future net cash flows are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production. Any excess of the net book value of proved oil and natural gas properties, less related deferred income taxes, over the ceiling is charged to expense. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2013, 2012 or 2011.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated

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Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Other Property and Equipment

Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the combined consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. Depreciation expense was $776, $501 and $727 for the years ended December 31, 2013, 2012 and 2011, respectively.

Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

Impairment of Long-Lived Assets

Other property and equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the years ended December 31, 2013, 2012 or 2011.

Capitalized Interest

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. The Company capitalized interest of $3,951 for the year ended December 31, 2013. During the years ended December 31, 2012 and 2011, the Company did not capitalize any interest expense.

Inventories

Inventories are stated at the lower of cost or market and consist of the following:



	December 31,
	2013		2012
Tubular goods and equipment	$	5,631	$	5,725
Crude oil	—		470
	$	5,631	$	6,195

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Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

The Company’s tubular goods and equipment is primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2013, the Company estimated that all of its tubular goods and equipment will be utilized within one year.

Debt Issuance Costs

Other assets included capitalized costs of $12,458 and $1,115, net of accumulated amortization of $1,798 and $782, as of December 31, 2013 and 2012, respectively. The increase in 2013 related primarily to the $10,376 of costs incurred upon the issuance of the 7.625% Senior Notes due 2021. The costs associated with the Senior Notes are being amortized over the term of the Senior Notes using the effective interest method. The costs associated with our credit facility are being amortized over the term of the facility.

Other Accrued Liabilities

Other accrued liabilities consist of the following:



	December 31,
	2013		2012
Prepaid drilling liability	$	16,491	$	4,540
Interest payable	9,918		—
Lease operating expense payable	4,538		4,737
Current portion of asset retirement obligations	40		20
Other	3,763		1,352
	$	34,750	$	10,649

Revenue and Royalties Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds applicable to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying combined consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of December 31, 2013 or December 31, 2012. Revenues from oil and natural gas services are recognized as services are provided.

Investments

Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2013 and 2012. For additional information on the Company’s investments, see Note 6—Equity Method Investments.

Accounting for Stock-Based Compensation

F-12

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

The Company grants various types of stock-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 9—Stock and Equity Based Compensation. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2013 two purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (37%); and Shell Trading (US) Company (37%). For the year ended December 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (53%); Occidental Energy Marketing, Inc. (16%); and Andrews Oil Buyers, Inc. (10%). For the year ended December 31, 2011, Windsor Midstream LLC, a related party, accounted for 79% of the Company’s revenue. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

Diamondback uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Company and the Predecessor are subject to margin tax in the state of Texas. During the years ended December 31, 2013, 2012 and 2011, there was no margin tax expense. The Company’s 2009, 2010, 2011, 2012 and 2013 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2013 and December 31, 2012, the Company had no unrecognized tax benefits that would have a material impact on the effective rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2013, 2012 and 2011, there was no interest or penalties associated with uncertain tax positions recognized in the Company’s combined consolidated financial statements.

Unaudited Pro Forma Income Taxes

Diamondback was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback is a C-Corporation under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision as if the Company and the Predecessors were subject to income taxes since December 31, 2011. 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.

Unaudited Pro Forma Earnings per Share

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 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.

3. ACQUISITIONS

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Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

2013 Activity

In September 2013, the Company completed two separate acquisitions of additional leasehold interests in the Permian Basin from unrelated third party sellers for an aggregate purchase price of $165,000, subject to certain adjustments. The first of these acquisitions closed on September 4, 2013, when the Company acquired certain assets located in northwestern Martin County, Texas, consisting of a 100% working interest (80% net revenue interest) in 4,506 gross and net acres. The second of these acquisitions closed on September 26, 2013, when the Company acquired certain assets located primarily in southwestern Dawson County, Texas, consisting of a 71% working interest (55% net revenue interest) in 9,390 gross (6,638 net) acres. These acquisitions were funded with a portion of the net proceeds from the August 2013 equity offering discussed in Note 1—Organization.

On September 19, 2013, the Company completed the acquisition of the mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas in the Permian Basin. The mineral interests entitle the Company to receive an average 19.5% royalty interest on all production from this acreage with no additional future capital or operating expense required. The acquisition was accounted for as an acquisition of assets. The $440,000 purchase price was funded with the net proceeds of the Company’s offering of Senior Notes discussed in Note 7—Debt.

2012 Activity

On October 11, 2012, the Company completed the acquisition of Gulfport’s oil and natural gas interests in the Permian Basin. The acquisition was accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value.

The acquisition-date fair value of the consideration transferred totaled $220,636, which consisted of the following:



Common Stock (7,914 shares)	$	138,496
Promissory note paid in full from IPO proceeds	63,590
Closing adjustment payable	18,550
Total	$	220,636

The fair value of the 7,914 common shares issued was determined based on the IPO pricing of $17.50 per common share on October 11, 2012. The closing adjustment payable balance is a result of the working capital adjustment.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the acquisition date. As shown above, consideration transferred in the transaction was $220,636, resulting in no goodwill or bargain purchase gain.



Proved oil and natural gas properties	$	115,760
Unevaluated oil and natural gas properties	111,373
Asset retirement obligations	(562		)
Deferred income tax liability	(5,935		)
Total fair value of net assets	$	220,636

The Company has included in its combined consolidated statements of operations revenues of $7,353 and direct operating expenses of $2,260 for the period from October 11, 2012 to December 31, 2012 due to the acquisition. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion. The following unaudited summary pro forma combined consolidated statements of operations data of Diamondback for the years ended December 31, 2012 and 2011 have been prepared to give effect to the acquisition as if it had occurred on January 1, 2011. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisition occurred on January 1, 2011. The pro forma data also necessarily exclude various operation expenses related to the Gulfport properties and such financial statements should not be viewed as indicative of operations in future periods.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)



	Pro Forma
	(Unaudited)
	Year Ended December 31,
	2012			2011
Pro forma total revenues	$	97,455		$	72,418
Pro forma income from operations	24,064			23,189
Pro forma net income	(29,764		)	7,666		⁽¹⁾

(1) For 2011, this amount does not include a pro forma income tax provision relating to becoming subject to income taxes as a result of the Merger.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

4. PROPERTY AND EQUIPMENT

Property and equipment includes the following:



	December 31,
	2013			2012
Oil and natural gas properties:
Subject to depletion	$	1,278,799		$	576,497
Not subject to depletion-acquisition costs
Incurred in 2013	279,353			—
Incurred in 2012	87,252			117,395
Incurred in 2011	1,598			1,670
Incurred in 2010	1,358			1,647
Incurred in 2009	—			533
Total not subject to depletion	369,561			121,245

Gross oil and natural gas properties	1,648,360			697,742
Less accumulated depreciation, depletion, amortization and impairment	(210,837		)	(145,102		)
Oil and natural gas properties, net	1,437,523			552,640

Pipeline and gas gathering assets	6,142			—

Other property and equipment	4,071			2,337
Less accumulated depreciation	(1,399		)	(735		)
Other property and equipment, net	2,672			1,602

Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	1,446,337		$	554,242

Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized internal costs were approximately $5,348, $4,872 and $871 for the years ended December 31, 2013, 2012 and 2011, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years.

5. ASSET RETIREMENT OBLIGATIONS

The following table describes the changes to the Company’s asset retirement obligation liability for the following periods:



	Year Ended December 31,
	2013			2012			2011
Asset retirement obligation, beginning of period	$	2,145		$	1,104		$	742
Additional liability incurred	226			201			297
Liabilities acquired	471			562			—
Liabilities settled	(14		)	(5		)	—
Accretion expense	201			98			65
Revisions in estimated liabilities	—			185			—
Asset retirement obligation, end of period	3,029			2,145			1,104
Less current portion	40			20			—
Asset retirement obligations - long-term	$	2,989		$	2,125		$	1,104

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate

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Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

6. EQUITY METHOD INVESTMENTS

Bison Drilling and Field Services LLC

On November 15, 2010, the Company formed a wholly owned subsidiary, Bison Drilling and Field Services LLC (“Bison”), formerly known as Windsor Drilling LLC. In addition, on March 2, 2010, the Company formed a wholly owned subsidiary, West Texas Field Services LLC, which, on January 1, 2011, contributed all of its assets and liabilities to Bison and West Texas Field Services LLC was subsequently dissolved on June 12, 2012. Bison owns and operates drilling rigs and various oil and natural gas well servicing equipment.

Beginning on March 31, 2011, various related party investors contributed capital to Bison diluting the Company’s ownership interest. As of June 15, 2012, the Company distributed its remaining 22% interest in Bison to an entity which is controlled and managed by Wexford. As the transaction was between entities under common control, the Company recognized the distribution of $6,437 as an equity transaction. Bison continues to be a related party with the Company.

Muskie Holdings LLC

During 2011, the Company paid approximately $4,200 for land and various other capital items related to the land. On October 7, 2011, the Company contributed these assets to a newly formed entity, Muskie Holdings LLC (“Muskie”), a Delaware limited liability company now known as Muskie Proppant LLC, for a 48.6% equity interest. Through additional contributions to Muskie from a related party and various Wexford portfolio companies, the Company’s interest in Muskie decreased to 33% as of June 15, 2012. Muskie generated a loss during the period from January 1, 2012 through June 15, 2012 and the Company recorded its share of this loss.

As of June 15, 2012, the Company distributed its remaining interest in Muskie to an entity which is controlled and managed by Wexford. As the transaction was between entities under common control, the Company recognized the distribution of $4,067 as an equity transaction. Muskie continues to be a related party with the Company.

7. DEBT

Long-term debt consisted of the following:



	December 31,
	2013		2012
Revolving credit facility	$	10,000	$	—
7.625 % Senior Notes due 2021	450,000		—
Note Payable	—		338
Total long-term debt	460,000		338
Less current portion of long-term debt	—		(145		)
Long-term debt, net of current portion	$	460,000	$	193

Senior Notes

On September 18, 2013, the Company completed an offering of $450,000 in aggregate principal amount of 7.625% senior unsecured notes due 2021 (the “Senior Notes”). The Senior Notes bear interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October 1 of each year, commencing on April 1, 2014 and will mature on October 1, 2021. The Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. The net proceeds from the Senior Notes were used to fund the acquisition of mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas in the Permian Basin.

The Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as the trustee (the “Indenture”). The Indenture contains certain

F-17

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on, or redeem or repurchase, capital stock, prepay subordinated indebtedness, sell assets including capital stock of subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. If the Company experiences certain kinds of changes of control or if it sells certain of its assets, holders of the Senior Notes may have the right to require the Company to repurchase their Senior Notes.

The Company will have the option to redeem the Senior Notes, in whole or in part, at any time on or after October 1, 2016 at the redemption prices (expressed as percentages of principal amount) of 105.719% for the 12-month period beginning on October 1, 2016, 103.813% for the 12-month period beginning on October 1, 2017, 101.906% for the 12-month period beginning on October 1, 2018 and 100.000% beginning on October 1, 2019 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. In addition, prior to October 1, 2016, the Company may redeem all or a part of the Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium at the redemption date. Furthermore, before October 1, 2016, the Company may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.625% of the principal amount of the Senior Notes being redeemed plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Senior Notes originally issued under the Indenture remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering.

In connection with the issuance of the Senior Notes, the Company and the subsidiary guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the initial purchasers on September 18, 2013, pursuant to which the Company and the subsidiary guarantors have agreed to file a registration statement with respect to an offer to exchange the Senior Notes for a new issue of substantially identical debt securities registered under the Securities Act. Under the Registration Rights Agreement, the Company also agreed to use its commercially reasonable efforts to cause the exchange offer registration statement to become effective within 360 days after the issue date of the Senior Notes and to consummate the exchange offer 30 days after effectiveness. The Company may be required to file a shelf registration statement to cover resales of the Senior Notes under certain circumstances. If the Company fails to satisfy certain of its obligations under the Registration Rights Agreement, the Company agreed to pay additional interest to the holders of the Senior Notes as specified in the Registration Rights Agreement.

Credit Facility-Wells Fargo Bank

On October 15, 2010, the Company entered into a secured revolving credit agreement with BNP Paribas, or BNP, as the administrative agent, sole book runner and lead arranger. On May 10, 2012, the revolving credit agreement was amended to provide for the resignation of BNP, and the appointment of Wells Fargo Bank, National Association, as administrative agent for the lenders. The credit agreement was amended and restated as of July 24, 2012 and again as of November 1, 2013. The credit agreement, as so amended and restated, provides for a revolving credit facility in the maximum amount of $600,000, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, the Company may request up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2013, the borrowing base was $225,000. As of December 31, 2013, the Company had outstanding borrowings of $10,000 which bore a weighted average interest rate of 1.67%.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is based on the prime rate or LIBOR plus margins ranging from 0.50% for prime-based loans and 1.50% for LIBOR loans to 1.50% for prime-based loans and 2.50% for LIBOR loans, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some

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Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

cases subject to a cure period) and (b) at the maturity date of November 1, 2018. The loan is secured by substantially all of the assets of the Company and its subsidiaries.



Financial Covenant			Required Ratio
Ratio of total debt to EBITDAX			Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement			Not less than 1.0 to 1.0
EBITDAX will be annualized beginning with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2014.

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $750,000 in the form of senior or senior subordinated notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. As of December 31, 2013, the Company had $450,000 of senior notes outstanding.

As of December 31, 2013 and December 31, 2012, the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

Note Payable

The Company entered into an installment payment contract with EMC Corporation for the purchase of computer equipment. The contract is payable in equal installments over a period of 36 months. The Company repaid all outstanding borrowings under this note in 2013 and, as of December 31, 2013, had no amounts outstanding under this note. As of December 31, 2012, the Company had amounts outstanding under this note of $338.

Subordinated Note

Effective May 14, 2012, the Company issued a subordinated note to an affiliate of Wexford pursuant to which, as amended, the Wexford affiliate could, from time to time, advance up to an aggregate of $45,000. These advances were solely at the lender’s discretion and neither Wexford nor any of its affiliates had any commitment or obligation to provide further capital support to the Company. The note bore interest at a rate equal to LIBOR plus 0.28% or 8% per annum, whichever was lower. Interest was due quarterly in arrears beginning on July 1, 2012. Interest payments were payable in kind by adding such amounts to the principal balance of the note. The unpaid principal balance and all accrued interest on the note was due and payable in full on January 31, 2015 or the earlier completion of an initial public offering. Any indebtedness evidenced by this note was subordinate in the right of payment to any indebtedness outstanding under the Company’s revolving credit facility. Prior to the completion of the IPO, there was $30,050 in aggregate principal and interest outstanding under this note. In connection with the IPO, the Company repaid all outstanding borrowings under the subordinated note and the subordinated note was canceled.

Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2013, 2012 and 2011:

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Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)



	Year Ended December 31,
	2013			2012		2011
Cash payments for interest	$	404		$	3,017	$	2,265
Amortization of debt issuance costs	1,018			494		250
Accrued interest related to the Senior Notes	9,913			—		—
Change in accrued interest and other	675			99		13
Interest charges incurred	12,010			3,610		2,528
Less capitalized interest	(3,951		)	—		—
Total interest expense	$	8,059		$	3,610	$	2,528

8. EARNINGS PER SHARE & PRO FORMA EARNINGS PER SHARE

Earnings Per Share

The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:



	2013
				Per
	Income		Shares	Share
	(Per share amounts in actual dollars)
Basic:
Net income attributable to common stock	$	54,587	42,015	$	1.30
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	240
Diluted:
Net income attributable to common stock	$	54,587	42,255	$	1.29

Pro Forma Earnings Per Share

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 were outstanding for the entire year. A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below:



	2012
				Per
	Income		Shares	Share
	(Per share amounts in actual dollars)
Basic:
Pro forma net income attributable to common stock	$	11,829	19,721	$	0.60
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	3
Diluted:
Pro forma net income attributable to common stock	$	11,829	19,724	$	0.60

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Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

9. STOCK AND EQUITY BASED COMPENSATION

On October 10, 2012, the Board of Directors approved the Diamondback Energy, Inc. 2012 Equity Incentive Plan (the “2012 Plan”), which is intended to provide eligible employees with equity-based incentives. The 2012 Plan provides for the granting of incentive stock options, nonstatutory stock options, restricted awards (restricted stock and restricted stock units), performance awards, and stock appreciation rights, or any combination of the foregoing. A total of 2,500 shares of the Company’s common stock has been reserved for issuance pursuant to this plan. Previous to the 2012 Plan, each of the Company’s Executive Officers was provided with an option to acquire a percentage membership interest in Windsor Permian. In connection with the IPO and the 2012 Plan, these options were canceled and replaced with the right to receive a cash payment, restricted stock units and stock options. Such grant of new awards was deemed to be a modification of old awards and was accounted for as a modification of the original awards. The modification date for these awards was October 11, 2012, which was the date the Company’s IPO was priced at $17.50 per share. Eight employees were affected by this modification. As a result of the modification, incremental compensation cost of $4,588 was recognized on the modification date to recognize the portion of awards that are vested and includes cash payments of $2,813. In addition to the compensation expense recognized on the modification date, $5,866 of compensation expense will be recognized over the remaining service period and a liability of $333 was recognized ratably over one year as the Company’s chief executive officer received a cash payment on the first anniversary date of the IPO. The modification did not change the original vesting or exercise periods. As a result, options vest in four substantially equal annual installments commencing on the first anniversary of the original date of grant and are exercisable for 5 years from the original date of grant.

The following table presents the effects of the equity and stock based compensation plans and related costs:



	2013		2012		2011
General and administrative expenses	$	2,983	$	3,757	$	438
Stock based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	972		2,537		106
Related income tax benefit	704		930		—

Stock Options

In accordance with the 2012 Plan, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. The shares issued under the 2012 Plan will consist of new shares of Company stock. Unless otherwise specified in an agreement, options become exercisable ratably over a five-year period. However, as described above, options associated with the modification vest in 4 substantially equal annual installments and are exercisable for 5 years from the date of grant.

The fair value of the stock options on the date of grant is expensed over the applicable vesting period. The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company does not have a long history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards and remaining vesting term at the modification date. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero. All such amounts represent the weighted-average amounts for each year.



	2013			2012
Grant-date fair value	$	6.51		$	4.41
Expected volatility	36.9		%	40.0		%
Expected dividend yield	0.0		%	0.0		%
Expected term (in years)	3.8			3.8
Risk-free rate	0.57		%	0.33		%

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Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

The following table presents the Company’s stock option activity under the 2012 Plan for the year ended December 31, 2013:



			Weighted Average
			Exercise		Remaining	Intrinsic
	Options		Price		Term	Value
					(In years)
Outstanding at December 31, 2012	850		$	17.50
Granted	63		$	22.72
Exercised	(200	)	$	17.50
Expired/Forfeited	—		$	—
Outstanding at December 31, 2013	713		$	17.96	2.69	$	24,895

Vested and Expected to vest at December 31, 2013	713		$	17.96	2.69	$	24,895
Exercisable at December 31, 2013	250		$	17.50	2.11	$	8,843

The aggregate intrinsic value of stock options that were exercised during 2013 was $5,717. As of December 31, 2013, the unrecognized compensation cost related to unvested stock options was $1,718. Such cost is expected to be recognized over a weighted-average period of 1.7 years.

Restricted Stock Awards and Units

Under the 2012 Plan, approved by the Board of Directors, the Company is authorized to issue restricted stock and restricted stock units to eligible employees. The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents a summary of the Company’s restricted stock awards and units.

The following table presents the Company’s restricted stock awards and units activity under the 2012 Plan for the year ended December 31, 2013:



			Weighted Average
	Restricted Stock		Grant-Date
	Awards & Units		Fair Value
Unvested at December 31, 2012	206		$	17.50
Granted	11		$	41.66
Vested	(81	)	$	18.03
Forfeited	(4	)	$	17.50
Unvested at December 31, 2013	132		$	19.20

The aggregate fair value of restricted stock units that vested in 2013 and 2012 was $3,310 and $1,269, respectively. As of December 31, 2013, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $2,053. Such cost is expected to be recognized over a weighted-average period of 1.4 years.

Equity-Based Compensation

During the year ended December 31, 2011, Windsor Permian granted to its executive officers options to acquire membership interests in Windsor Permian. Such options vested in four equal annual installments commencing on the first anniversary of the date of grant and were exercisable for five years from the date of grant. Summarized below are the grant dates with the total exercise prices and total fair values of the underlying options:

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)



Grants Made During the Months Ended	Membership Interest Granted	Exercise Price		Fair Value at Date of Grant
April 2011	1.00%	$	3,600	$	1,453
August 2011	1.20%	6,000		1,384
September 2011	1.25%	5,900		1,533
November 2011	0.25%	1,250		288
	3.70%	$	16,750	$	4,658

At December 31, 2011, the intrinsic value for all outstanding options was $113 and the weighted-average remaining contractual terms were 4.6 years. Also, at December 31, 2011, no options were exercisable.

The Company accounted for such options issued using a fair-value-based method calculated on the grant-date of the award. The resulting cost was recognized on a straight-line basis over the vesting period of the entire option.

The fair value of the options issued was estimated using the Black-Scholes option-pricing model. One of the inputs to this model was the estimate of the fair value of the underlying membership interest on the date of grant. The other inputs include an estimate of the expected volatility of the membership interest, an option’s expected term, the risk-free interest rate over the option’s expected term, the option’s exercise price and expectations regarding dividends.

Windsor Permian did not have a history of market prices for its membership interests because such interests were not publicly traded. The expected volatility was determined using the historical volatility for a peer group of companies. The expected term for options issued was determined based on the contractual term of the awards. The weighted-average risk-free interest rate was based on the daily U.S. treasury yield curve rate whose term was consistent with the expected life of the options. Windsor Permian did not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero.

A summary of the significant assumptions used to estimate the fair value of the options to acquire membership interests during the year ended December 31, 2011 was as follows:



Expected term	5 years
Risk-free interest rate	0.96%
Expected volatility	45.5%
Expected dividend yield	0.00%

These equity-based awards were canceled and replaced with the right to receive a cash payment, restricted stock units and stock options as described in the above sections of this Note.

10. RELATED PARTY TRANSACTIONS

Administrative Services

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began March 1, 2008. Through December 31, 2011, amounts charged to the Company included those costs directly attributable to the Company as well as indirect costs allocated to the Company. The reimbursement amount for indirect costs is determined by the affiliate’s management based on estimates of time devoted to the Company. The initial term of this shared service agreement was two years. Since the expiration of such two-year period on March 1, 2010, the agreement by its terms, continued on a month-to-month basis. For the years ended December 31, 2013, 2012 and 2011, the Company incurred total costs of $207, $4,419 and $10,110, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration and development of proved oil and natural gas properties have been capitalized. The expensed costs were partially offset in general and administrative expenses by overhead reimbursements of $2,548 and $1,954 for the years ended December 31, 2012 and 2011, respectively. As of December 31, 2013 and

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

December 31, 2012, the Company owed the administrative services affiliate $17 and $13, respectively. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets.

Effective January 1, 2012, the Company entered into an additional shared services agreement with this entity. Under this agreement, the Company provides this entity and, at its request, certain affiliates, with consulting, technical and administrative services. The initial term of the additional shared services agreement is two years. Upon expiration of the initial term the agreement will continue on a month-to-month basis until canceled by either party upon thirty days prior written notice. Costs that are attributable to and billed to other affiliates are reported as other income-related party. For the years ended December 31, 2013 and 2012, the affiliate reimbursed the Company $1,077 and $2,132, respectively for services under the shared services agreement. As of December 31, 2013 and December 31, 2012, the affiliate owed the Company no amounts and $1, respectively. These amounts are included in accounts receivable-related party in the accompanying consolidated balance sheets.

Operating Services

The Company is the operator of substantially all of its properties. As operator of these properties, the Company is responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties.

As of December 31, 2013 and December 31, 2012, amounts due from an affiliate (a greater than 5% stockholder) related to joint interest billings and included in accounts receivable-related party in the accompanying consolidated balance sheets were no amounts and $742, respectively.

Drilling Services

Bison has performed drilling and field services for the Company under master drilling and field service agreements. Under the Company’s most recent master drilling agreement with Bison, effective as of January 1, 2013, Bison committed to accept orders from the Company for the use of at least two of its rigs. At December 31, 2013, Bison was providing drilling services to the Company using one of its rigs. This master drilling agreement is terminable by either party on 30 days prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. For the three months ended March 31, 2011, Bison was a wholly owned subsidiary and intercompany amounts were eliminated in consolidation. For the years ended December 31, 2013, 2012 and 2011 the Company incurred total costs of $13,921, $16,040 and $16,357, respectively, payable to Bison. The Company owed Bison no amounts as of December 31, 2013 and $120 as of December 31, 2012.

Effective September 9, 2013, the Company entered into a master service agreement with Panther Drilling Systems LLC (“Panther Drilling”), an entity controlled by Wexford. Panther Drilling provides directional drilling and other services. This master service agreement is terminable by either party on 30 days prior written notice, although neither party will be relieved of its respective obligations arising from work performed prior to the termination of the master service agreement. In the third quarter 2013, the Company began using Panther Drilling’s directional drilling services. For the year ended December 31, 2013, the Company incurred $176 for services performed by Panther Drilling. The Company owed Panther Drilling no amounts as of December 31, 2013.

Marketing Services

The Company entered into an agreement on March 1, 2009 with an entity under common management that purchased and received a significant portion of the Company’s oil volumes. December 1, 2011, the Company ceased all sales of its production under this agreement and effective January 1, 2012 the agreement with the affiliate was canceled. The Company’s revenues from the affiliate were $38,873 for the year ended December 31, 2011, and such amounts are included in oil sales–related party in the accompanying combined consolidated statements of operations.

Coronado Midstream

The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC (“Coronado Midstream”), formerly known as MidMar Gas LLC, an entity affiliated with Wexford that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, Coronado Midstream is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage.

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Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

Following the expiration of the initial ten year term, the agreement will continue on a year-to-year basis until terminated by either party on 30 days’ written notice. Under the gas purchase agreement, Coronado Midstream is obligated to pay the Company 87% of the net revenue received by Coronado Midstream for all components of the Company’s dedicated gas, including the liquid hydrocarbons, and the sale of residue gas, in each case extracted, recovered or otherwise processed at Coronado Midstream’s gas processing plant, and 94.56% of the net revenue received by Coronado Midstream from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. The Company recognized revenues from Coronado Midstream of $7,230, $4,050 and $2,190 for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013 and December 31, 2012, Coronado Midstream owed the Company $1,303 and $6, respectively, for the Company’s portion of the net proceeds from the sale of gas, gas products and residue gas.

Sand Supply

Muskie, an entity affiliated with Wexford, processes and sells fracking grade sand for oil and natural gas operations. The Company began purchasing sand from Muskie in March 2013. On May 16, 2013, the Company entered into a master services agreement with Muskie, pursuant to which Muskie agreed to sell custom natural sand proppant to the Company based on the Company’s requirements. The Company is not obligated to place any orders with, or accept any offers from, Muskie for sand proppant. The agreement may be terminated at the option of either party on 30 days’ notice. The Company incurred costs of $743 for the year ended December 31, 2013. As of December 31, 2013, the Company did not owe Muskie any amounts.

Midland Lease

Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $214, $155 and $40 for the years ended December 31, 2013, 2012 and 2011, respectively, under this lease. In the second and third quarters of 2013, the Company amended this agreement to increase the size of the leased premises. The monthly rent under the lease increased from $13 to $15 beginning on August 1, 2013 and increased further to $25 beginning on October 1, 2013. The monthly rent will continue to increase approximately 4% annually on June 1 of each year during the remainder of the lease term.

Oklahoma City Lease

Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $244 and $329 for the years ended December 31, 2013 and 2012, respectively, under this lease. Effective April 1, 2013, this lease was amended to increase the size of the leased premises, at which time our monthly base rent increased to $19 for the remainder of the lease term. The Company is also responsible for paying a portion of specified costs, fees and expenses associated with the operation of the premises.

Advisory Services Agreement & Professional Services from Wexford

The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company with general financial and strategic advisory services related to the business in return for an annual fee of $500, plus reasonable out-of-pocket expenses. The Advisory Services Agreement has a term of two years commencing on October 18, 2012, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Company terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’s independent directors for such services as may be provided by Wexford at the Company’s request in connection with future acquisitions and divestitures, financings or other transactions in which the Company may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Company’s day-to-day business or operations. The Company has agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Company incurred total costs of $500 and $191 for the years ended December 31, 2013 and 2012, respectively, under the Advisory Services Agreement. Wexford provides certain professional services to the Company, for which the Company incurred total costs of $119 for the year ended December 31, 2012. As of December 31, 2013 and December 31, 2012, the Company owed Wexford no amounts

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Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

and $113, respectively. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets. The Company did not incur any costs for professional services from Wexford during the year ended December 31, 2011.

Secondary Offering Costs

On November 13, 2013, Gulfport completed an underwritten secondary public offering of 2,000 shares of the Company’s common stock that were owned by Gulfport. The shares were sold to the public at $53.46 per share and the selling stockholder received all proceeds from this offering. The Company incurred costs of approximately $53 related to the secondary public offering.

11. INCOME TAXES

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. As discussed in Note 2—Summary of Significant Accounting Policies, Diamondback Energy LLC merged with and into Diamondback on October 11, 2012 and, accordingly, Diamondback has filed a consolidated return for the period October 11, 2012 through December 31, 2012. Prior to the Merger, the Predecessors were not subject to corporate income taxes. The Company is subject to corporate income taxes and the Texas margin tax.

The components of the provision for income taxes for the years ended December 31, 2013 and 2012 are as follows:



	Year Ended December 31,
	2013		2012
Current income tax provision:
Federal	$	191	$	—
State	—		—
Total current income tax provision	191		—
Deferred income tax provision:
Federal	30,768		53,319
State	795		1,584
Total deferred income tax provision	31,563		54,903
Total provision for income taxes	$	31,754	$	54,903

Deferred recognized at date of Merger - change in tax status of Predecessors			54,142
Deferred as a result of operations from October 11, 2012 through December 31, 2012			761

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)



	Year Ended December 31,
	2013		2012
Income tax expense at the federal statutory rate (35%)	$	30,231	$	6,434
Deduction for pre-merger LLC earnings	—		(5,717		)
Income tax expense relating to change in tax status	—		54,142
State income tax expense, net of federal tax benefit	517		42
Non-deductible expenses	1,006		2
Provision for income taxes	$	31,754	$	54,903

The components of the Company’s deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:



	December 31,
	2013		2012
Current:
Deferred tax assets
Derivative instruments	$	—	$	1,857
Other	265		—
Total current deferred tax assets	265		1,857
Deferred tax liabilities
Derivative instruments	153		—
Total current deferred tax liabilities	153		—
Net current deferred tax assets	112		1,857
Noncurrent:
Deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	—		1,577
Stock based compensation	346		930
Alternative minimum tax credit carryforward	191		—
Other	20		—
Total noncurrent deferred tax assets	557		2,507
Deferred tax liabilities
Oil and natural gas properties and equipment	92,321		64,636
Other	—		566
Total noncurrent deferred tax liabilities	92,321		65,202
Net noncurrent deferred tax liabilities	91,764		62,695
Net deferred tax liabilities	$	91,652	$	60,838

As of December 31, 2013, the Company had a federal net operating loss carryforward of $5,833. However, a related deferred tax asset is not reflected as the excess tax benefit has not been recognized for certain stock-based compensation deductions which have not reduced current taxes payable. As of December 31, 2013, the Company also had recognized a $191 deferred tax asset related to alternative minimum tax credits which have no expiration date and will be available or use against tax on future taxable income.

12. DERIVATIVES

All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and

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Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

recognizes the cash and non-cash changes in fair value in the combined consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

The Company has used price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixed price swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing, Argus Louisiana light sweet pricing or Inter–Continental Exchange (“ICE”) pricing for Brent crude oil. The counterparty to the Company’s derivative contracts is Wells Fargo Bank, N.A., who the Company believes is an acceptable credit risk.

As of December 31, 2013, the Company had open crude oil derivative positions with respect to future production as set forth in the tables below. When aggregating multiple contracts, the weighted average contract price is disclosed.



Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
January - December 2014	944,000	$	98.78
January 2015	31,000	101.00

Crude Oil—ICE Brent Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
January–April 2014	120,000	$	109.70

Balance sheet offsetting of derivative assets and liabilities

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement.

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2013 and December 31, 2012.



	December 31, 2013
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets Presented in the Consolidated Balance Sheet
Derivative assets	$	998	$	(567	)	$	431

	December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
Derivative liabilities	$	5,205	$	—		$	5,205

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Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:



	December 31,		December 31,
	2013		2012
Current Assets: Derivative instruments	$	213	$	—
Noncurrent Assets: Derivative instruments	218		—
Total Assets	$	431	$	—

Current Liabilities: Derivative instruments	$	—	$	4,817
Noncurrent Liabilities: Derivative instruments	—		388
Total Liabilities	$	—	$	5,205

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the combined consolidated statements of operations:



	Year Ended December 31,
	2013			2012			2011
Non-cash gain (loss) on open non-hedge derivative instruments	$	5,346		$	8,057		$	(12,972	)
Loss on settlement of non-hedge derivative instruments	(7,218		)	(5,440		)	(37		)
Gain (loss) on derivative instruments	$	(1,872	)	$	2,617		$	(13,009	)

13. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s fixed price crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and December 31, 2012.



	Fair value measurements at December 31, 2013 using:
	Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total
Assets:
Fixed price swaps	$	—	$	431	$	—	$	431

	Fair value measurements at December 31, 2012 using:
	Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total
Liabilities:
Fixed price swaps	$	—	$	5,205	$	—	$	5,205

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the combined consolidated financial statements.



	December 31, 2013				December 31, 2012
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Debt:
Revolving credit facility	$	10,000	$	10,000	$	—	$	—
7.625% Senior Notes due 2021	450,000		460,406		—		—
Note payable	—		—		338		305

The fair value of the revolving credit facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the December 31, 2013 quoted market price, a Level 1 classification in the fair value hierarchy. The fair value of the note payable is determined using internal discounted cash flow calculations based on the interest rate and payment terms of the note payable. The fair value of the note payable is classified as Level 3 in the fair value hierarchy.

14. COMMITMENTS AND CONTINGENCIES

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

acquire mining permits prior to the enactment of the moratorium by Goodhue County. In an order filed on July 10, 2013, the judge ordered the damage phase to be set for trial following a pretrial and scheduling conference, and the parties have agreed upon a schedule for pretrial activities. Subsequently, the plaintiff disclosed a new damage theory, and the defendants filed motions with the court to dismiss plaintiff’s claims on the grounds that the damage claim is speculative and that plaintiff cannot prove damages as a matter of law. Plaintiff also filed a motion for leave to amend its complaint to assert a punitive damage claim. The motions were argued in December 2013 and the Company currently anticipate a ruling before the end of March 2014. The Company believes these claims are without merit and will continue to vigorously defend this action. While management has determined that the possibility of loss is remote, litigation is inherently uncertain and management cannot determine the amount of loss, if any, that may result.

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

Lease Commitments

The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2013.



Year Ending December 31,	Office and Equipment Leases

2014	$	667
2015	682
2016	505
2017	301
2018	25
Thereafter	—
Total	$	2,180

The Company leases office space in Midland, Texas from a third party and leases office space in Midland, Texas and Oklahoma City, Oklahoma from related parties. Refer to Note 10—Related Party Transactions for further information on the related party lease agreements. In March 2011, the Company began leasing field office space in Midland, Texas from a third party. The lease term is 84 months with equal monthly installments that escalate 3% annually on March 1st of each year. The following table presents rent expense for the years ended December 31, 2013, 2012 and 2011.



	For the years ended
	December 31,
	2013		2012		2011
Rent Expense	$	571	$	547	$	74

Drilling contracts

As of December 31, 2013, the Company had entered into drilling rig contracts with one related party and various third parties in the ordinary course of business to ensure rig availability to complete the Company’s drilling projects. Refer to Note 10—Related Party Transactions for further information on the related party drilling agreement. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as of December 31, 2013 total approximately $4,729.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

Oil production purchase agreement

On May 24, 2012, the Company entered into an oil purchase agreement with Shell Trading, in which the Company is obligated to commence delivery of specified quantities of oil to Shell Trading upon completion of the reversal of the Magellan Longhorn pipeline and its conversion for oil shipment, which occurred on October 1, 2013. The Company’s agreement with Shell Trading has an initial term of 5 years from the completion date. The Company’s maximum delivery obligation under this agreement is 8 gross barrels per day. The Company has a one-time right to elect to decrease the contract quantity by not more than 20% of the then-current quantity, which decreased contract quantity will be effective for the remainder of the term of the agreement. The Company will receive the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the New York Mercantile Exchange over the one-month period, as adjusted based on adjustment formulas specified in the agreement. If the Company fails to deliver the required quantities of oil under the agreement during any three-month period following the service commencement date, the Company has agreed to pay Shell Trading a deficiency payment, which is calculated by multiplying (i) the volume of oil that the Company failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect for transportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiency volume is calculated. The agreement may be terminated by Shell Trading in the event that Shell Trading’s contract for transportation on the pipeline is terminated.

Fracturing and well stimulation agreement

The Company has a contractual obligation with a third-party service provider for fracturing and well stimulation services. The agreement has a term through March 31, 2014. As of December 31, 2013, the future minimum commitment was approximately $3,600.

Defined contribution plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee’s compensation and may make additional discretionary contributions for eligible employees. Employer contributions vest in equal annual installments over a 4 year period. For the year ended December 31, 2013 and 2012 the Company paid $262 and $86, respectively, in contributions to the plan. Prior to 2012, the previous plan was sponsored under the shared service agreements discussed in Note 10—Related Party Transactions and the Company did not directly contribute to the previous plan.

15. SUBSEQUENT EVENTS

On January 2, 2014 the Company granted 79 performance awards with a combination of market and service vesting criteria and 79 restricted stock awards with service vesting criteria under the 2012 Plan. For the performance awards the Company will use an appropriate fair value model to determine the fair value on the date of grant of the performance stock awards, which is expensed over the applicable two year vesting period of these awards. For the restricted stock awards the Company will estimate the fair values of restricted stock awards as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable two year vesting period of these awards.

On January 28, 2014, the Company entered into a new commodity contract with JP Morgan Chase Bank, National Association. The derivative is a fixed price oil swap that will settle against the weighted average price per barrel of Argus Louisiana light sweet during the calculation period. The following table presents the terms of the contract:



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	365,000	$	96.75	February 2014	-	January 2015

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Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

On February 19, 2014, the Company entered into a new commodity contract with Wells Fargo Bank, N. A. The derivative is a fixed price oil swap that will settle against the calendar month average price per barrel of Argus Louisiana light sweet during the calculation period. The following table presents the terms of the contract:



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	365,000	$	100.60	March 2014	-	February 2015

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Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

16. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:



	December 31,
	2013			2012
Oil and Natural Gas Properties:
Proved properties	$	1,278,799		$	576,497
Unproved properties	369,561			121,245
Total Oil and Natural Gas Properties	1,648,360			697,742
Less Accumulated depreciation, depletion, amortization and impairment	(210,837		)	(145,102		)
Net oil and natural gas properties capitalized	$	1,437,523		$	552,640

Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:



	Year Ended December 31,
	2013		2012		2011
Acquisition costs
Proved properties	$	339,130	$	115,760	$	—
Unproved properties	279,402		117,395		3,704
Development costs	88,460		106,261		75,374
Exploration costs	242,929		17,547		11,226
Capitalized asset retirement costs	697		948		297
Total	$	950,618	$	357,911	$	90,601

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Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and natural gas liquids operations.



	Year Ended December 31,
	2013			2012			2011
Oil, natural gas and natural gas liquid sales	$	208,002		$	74,962		$	47,875
Lease operating expenses	(21,157		)	(15,247		)	(9,931		)
Production and ad valorem taxes	(12,899		)	(5,237		)	(3,032		)
Gathering and transportation	(918		)	(424		)	(202		)
Depreciation, depletion, and amortization	(65,821		)	(25,772		)	(15,377		)
Asset retirement obligation accretion expense	(201		)	(98		)	(65		)
Income tax expense	(31,754		)	(54,903		)	—
Results of operations	$	75,252		$	(26,719	)	$	19,268

Pro forma information
Pro forma results of operations before income taxes				$	28,184
Pro forma income tax⁽¹⁾				(10,083		)
Pro forma results of operations				$	18,101



(1	)	Diamondback Energy, Inc. was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback Energy, Inc. is a C-Corp under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision as if the Company and the Predecessors were subject to income taxes since December 31, 2011. 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.

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2013, 2012 and 2011 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

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Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

The changes in estimated proved reserves are as follows:



			Natural Gas
	Oil		Liquids		Natural Gas
	(Bbls)		(Bbls)		(Mcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2011	19,630,160		5,832,967		22,695,080

Extensions and discoveries	1,799,175		466,538		1,884,192
Revisions of previous estimates	(2,879,429	)	(1,163,130	)	(3,614,167	)
Purchase of reserves in place	—		—		—
Production	(449,433	)	(86,815	)	(413,640	)
As of December 31, 2011	18,100,473		5,049,560		20,551,465

Extensions and discoveries	3,106,433		869,741		3,759,684
Revisions of previous estimates	(1,464,243	)	(5,811	)	383,335
Purchase of reserves in place	7,210,482		2,521,053		10,709,180
Production	(756,286	)	(183,114	)	(833,516	)
As of December 31, 2012	26,196,859		8,251,429		34,570,148

Extensions and discoveries	17,041,744		4,597,856		24,184,540
Revisions of previous estimates	(5,943,164	)	(3,455,306	)	(5,786,180	)
Purchase of reserves in place	7,328,162		1,672,824		10,441,485
Production	(2,022,749	)	(361,079	)	(1,730,497	)
As of December 31, 2013	42,600,852		10,705,724		61,679,496

Proved Developed Reserves:
January 1, 2011	3,371,460		1,126,431		4,336,720
December 31, 2011	3,949,099		1,263,711		5,285,945
December 31, 2012	7,189,367		2,999,440		12,864,941
December 31, 2013	19,789,965		4,973,493		31,428,756

Proved Undeveloped Reserves:
January 1, 2011	16,258,700		4,706,536		18,358,360
December 31, 2011	14,151,375		3,785,850		15,265,520
December 31, 2012	19,007,492		5,251,989		21,705,207
December 31, 2013	22,810,887		5,732,231		30,250,740

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

The Company experienced downward reserve revisions in estimated proved oil, natural gas and natural gas liquid reserves in 2013. The downward revisions were primarily a result of downgrading 92 vertical locations that were booked as PUDs to probable in accordance with the SEC five year PUD rule.

The Company experienced downward reserve revisions in estimated proved oil and natural gas liquid reserves in 2012. These downward revisions were primarily a result from lower product pricing in 2012 as compared to 2011 causing wells to reach their economic limit sooner. The upward revision in natural gas reserves is the result of higher producing natural gas to oil ratios than previously projected, which more than offset the reduction resulting from lower natural gas prices.

The Company experienced downward reserve revisions in estimated proved reserves in 2011. These downward revisions were primarily the result of negative revisions in proved undeveloped wells due to offset well performance; exclusion of proved undeveloped locations that were not scheduled to be drilled within the next five

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

years; and the movement of reserves previously categorized as proved undeveloped to probable reserves due to changes in booking methodology used by our independent petroleum engineers as well as performance of wells in one prospect area.

Standardized Measure of Discounted Future Net Cash Flows

The following information has been prepared in accordance with the provisions of the FASB Codification, Topic 932– “Extractive Activities—Oil and Gas.” The standardized measure of discounted future net cash flows are based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2013, 2012 and 2011.



	December 31,
	2013			2012			2011
Future cash inflows	$	4,604,241		$	2,769,485		$	2,049,520
Future development costs	(517,075		)	(541,445		)	(410,350		)
Future production costs	(806,895		)	(773,611		)	(497,808		)
Future production taxes	(318,396		)	(140,758		)	(104,856		)
Future income tax expenses	(674,260		)	(334,903		)	—
Future net cash flows	2,287,615			978,768			1,036,506
10% discount to reflect timing of cash flows	(1,311,976		)	(611,548		)	(671,894		)
Standardized measure of discounted future net cash flows	$	975,639		$	367,220		$	364,612

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.



	December 31,
	2013		2012		2011
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	92.59	$	88.13	$	93.09
Natural gas (per Mcf)	$	4.13	$	2.86	$	3.91
Natural gas liquids (per Bbl)	$	37.82	$	43.88	$	56.33

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)



	Year Ended December 31,
	2013			2012			2011
Standardized measure of discounted future net cash flows at the beginning of the period	$	367,220		$	364,612		$	339,001
Sales of oil and natural gas, net of production costs	(173,946		)	(54,208		)	(34,711		)
Purchase of minerals in place	305,109			107,897			—
Extensions and discoveries, net of future development costs	552,450			79,293			73,571
Previously estimated development costs incurred during the period	76,631			88,849			87,530
Net changes in prices and production costs	51,828			(76,515		)	82,364
Changes in estimated future development costs	(5,822		)	8,309			(82,855		)
Revisions of previous quantity estimates	(126,993		)	(22,882		)	(98,533		)
Accretion of discount	57,988			36,461			33,900
Net change in income taxes	(168,570		)	(125,542		)	—
Net changes in timing of production and other	39,744			(39,054		)	(35,655		)
Standardized measure of discounted future net cash flows at the end of the period	$	975,639		$	367,220		$	364,612

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Diamondback Energy, Inc. and Subsidiaries

Notes to Combined Consolidated Financial Statements-(Continued)

(Amounts in thousands, except per share, per BOE and acreage amounts)

17. QUARTERLY FINANCIAL DATA (Unaudited)

The Company’s unaudited quarterly financial data for 2013 and 2012 is summarized below.



	2013
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Revenues	$	28,909	$	45,394	$	57,791	$	75,908
Income from operations	8,662		19,383		29,423		37,726
Income tax expense	3,162		7,802		9,099		11,691
Net income (loss)	$	5,396	$	14,471	$	14,596	$	20,124
Earnings per common share
Basic	$	0.15	$	0.37	$	0.33	$	0.43
Diluted	$	0.15	$	0.36	$	0.33	$	0.42

	2012
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Revenues	$	16,351	$	16,030	$	16,814	$	25,767
Income from operations	6,737		4,307		4,086		2,177
Income tax expense	—		—		—		54,903
Net income (loss)	$	1,477	$	13,624	$	452	$	(52,074	)

Pro forma information
Income before income taxes	$	1,477	$	13,624	$	452	$	2,829
Pro forma provision for income taxes	526		4,857		161		1,009
Pro forma net income	$	951	$	8,767	$	291	$	1,820
Pro forma earnings per share:
Basic	$	0.06	$	0.60	$	0.02	$	0.05
Diluted	$	0.06	$	0.60	$	0.02	$	0.05

Pro Forma Income Taxes

Diamondback Energy, Inc. was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback Energy, Inc. is a C-Corp under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision as if the Company and the Predecessors were subject to income taxes since December 31, 2011. 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.

Pro Forma Earnings per Share

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EXHIBIT INDEX

Exhibit Number				Description
2.1#				Purchase and Sale Agreement, dated August 28, 2013, by and between IBEX Mineral Resources, LLC and Beehive Partners, LLC, together, as seller, and Diamondback E&P LLC, as buyer (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on September 4, 2013).
2.2#				Purchase and Sale Agreement dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, and FC Permian Properties, Inc., as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, 2014).
2.3#				Purchase and Sale Agreement, dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, FC Permian Properties, Inc., Blake Braun, Richard D. Campbell, and Thomas J. Woodside, as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, 2014).
3.1				Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).

3.2				Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).

4.1				Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

4.2				Registration Rights Agreement, dated as of October 11, 2012, by and between the Company and DB Energy Holdings LLC (incorporated by reference to Exhibit 4.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).

4.3				Investor Rights Agreement, dated as of October 11, 2012, by and between the Company and Gulfport Energy Corporation (incorporated by reference to Exhibit 4.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
4.4				Indenture, dated as of September 18, 2013, among Diamondback Energy, Inc., the subsidiary guarantors party thereto and Wells Fargo, N.A., as trustee (including the form of Diamondback Energy, Inc.’s 7.625% Senior Note due October 2021 (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on September 18, 2013).
4.5*				First Supplemental Indenture, dated as of November 5, 2013, by and between Diamondback Energy, the subsidiary guarantors party thereto and Wells Fargo, N.A, as trustee.
4.6				Registration Rights Agreement, dated as of September 18, 2013, among Diamondback Energy, Inc., the subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on September 18, 2013).
10.1+				Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).

10.2+				Form of Stock Option Agreement (incorporated by reference to Exhibit 10.13 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

10.3+				Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.14 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

10.4+				Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.15 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

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Exhibit Number				Description
10.5				Advisory Services Agreement, dated as of October 11, 2012, by and between Diamondback Energy, Inc. and Wexford Capital LP (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).

10.6				Merger Agreement, dated as of October 11, 2012, by and between the Company and Diamondback Energy LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).

10.7+				Amended and Restated Employment Agreement, dated as of August 20, 2012, by and between Travis Stice and Windsor Permian LLC (incorporated by reference to Exhibit 10.29 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).

10.8+				First Amendment effective as of January 1, 2013 to the Amended and Restated Employment Agreement dated as of August 20, 2012 by and between Travis Stice and Windsor Permian LLC, as subsequently assigned to Diamondback E&P LLC (incorporated by reference to Exhibit 10.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).

10.9+				Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Teresa Dick and Windsor Permian LLC (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on July 5, 2012).

10.10+				First Amendment effective as of January 1, 2013 to the Amended and Restated Employment Agreement dated as of August 20, 2012 by and between Teresa Dick and Windsor Permian LLC, as subsequently assigned to Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).

10.11+				Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Jeff White and Windsor Permian LLC (incorporated by reference to Exhibit 10.31 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

10.12+				Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Jeff White and Windsor Permian LLC (incorporated by reference to Exhibit 10.31 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

10.13				Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.7 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on June 11, 2012).

10.14				Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

10.15				Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

10.16				Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

10.17				Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

10.18				Lease Amendment No. 5 to Lease Agreement, dated as of July 25, 2012, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.36 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).

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Exhibit Number		Description
10.19		Contribution Agreement, dated May 7, 2012, by and between the Company and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

10.20		Master Drilling Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

10.21		Gas Purchase Agreement, dated May 1, 2009, by and between Windsor Permian LLC and Feagan Gathering Company (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

10.22		Amendment to Gas Purchase Agreement, dated July 1, 2011, by and between Windsor Permian LLC and MidMar Gas LLC (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

	10.23	Amendment to Gas Purchase Agreement, dated January 11, 2012, by and between Windsor Permian LLC and MidMar Gas LLC (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

	10.24	Shared Services Agreement, dated January 1, 2012 by and between Windsor Permian LLC and Everest Operations Management LLC (incorporated by reference to Exhibit 10.23 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on June 11, 2012).

	10.25	Subordinated note made by Windsor Permian LLC in favor of Lambda Investors LLC, dated May 14, 2012 (incorporated by reference to Exhibit 10.23 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on June 11, 2012).

	10.26	First Amendment to Subordinated Note made by Windsor Permian LLC in favor of Lambda Investors LLC, dated September 28, 2012 (incorporated by reference to Exhibit 10.35 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).

	10.27	Crude Oil Purchase Agreement, dated May 24, 2012, by and between Windsor Permian LLC and Shell Trading (US) Company (incorporated by reference to Exhibit 10.26 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

	10.28	Shared Services Agreement, dated as of March 1, 2008, by and between Windsor Energy Resources LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).

	10.29	Office Lease Agreement, dated June 8, 2012, by and between Windsor Permian LLC and Caliber Investment Group LLC (incorporated by reference to Exhibit 10.27 to Amendment No. 3 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on July 5, 2012).

	10.30	Assignment and Assumption of Office Lease Agreement, effective as of June 1, 2012, by and between Windsor Permian LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.28 to Amendment No. 3 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on July 5, 2012).

	10.31	Master Drilling Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).

	10.32	Master Field Services Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).

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Exhibit Number		Description
	10.33	First Amendment to Master Field Services Agreement, dated as of February 21, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.35 to the Form 10-K, file No. 001-35700, filed by the Company with the SEC on March 1, 2013).

	10.34+	Amended and Restated Employment Agreement dated as of August 20, 2012, by and between Michael Hollis and Windsor Permian LLC (incorporated by reference to Exhibit 10.36 to the Form 10-K/A, file No. 001-35700, filed by the Company with the SEC on April 10, 2013).

	10.35+	First Amendment effective as of January 1, 2013 to the Amended and Restated Employment Agreement dated as of August 20, 2012 by and between Michael Hollis and Windsor Permian LLC, as subsequently assigned to Diamondback E&P LLC (incorporated by reference to Exhibit 10.37 to the Form 10-K/A, file No. 001-35700, filed by the Company with the SEC on April 10, 2013).

	10.36+	Form of Amendment to Restricted Stock Unit Certificate (incorporated by reference to Exhibit 10.38 to the Form 10-K/A, file No. 001-35700, filed by the Company with the SEC on April 10, 2013).

	10.37	Lease Amendment No. 6 effective May 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.39 to the Form 10-K/A, file No. 001-35700, filed by the Company with the SEC on April 10, 2013).

	10.38	First Amendment to Office Lease Agreement effective as of April 1, 2013 by and between Caliber Investment Group LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.40 to the Registration Statement on Form S-1, File No. 333-189176, filed by the Company with the SEC on June 7, 2013).

	10.39		Lease Amendment No. 7 effective September 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 8, 2013).

	10.40		Lease Amendment No. 8 effective October 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 8, 2013).
	10.41		Lease Amendment No. 9 effective August 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).
	10.42		Lease Amendment No. 10 effective October 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.7 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).
	10.43		Second Amended and Restated Credit Agreement, dated as of November 1, 2103, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).

	21.1*		Subsidiaries of the Registrant.

	23.1*		Consent of Grant Thornton LLP.

	23.2*		Consent of Ryder Scott Company, L.P.

	31.1*		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
	31.2*		Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
	32.1+		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

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Exhibit Number		Description
	32.2+	Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
	99.1*	Report of Ryder Scott Company, L.P.
	101.INS**	XBRL Instance Document.
	101.SCH**	XBRL Taxonomy Extension Schema Document.
	101.CAL**	XBRL Taxonomy Extension Calculation Linkbase.
	101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document.
	101.LAB**	XBRL Taxonomy Extension Labels Linkbase Document.
	101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document.

_______________




*	Filed herewith.
**	Furnished herewith. Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are not deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.
+	The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
#	The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.

E-5