Diamondback Energy 10-K 2016-12-31

Cover and table of contents

Item 1. BUSINESS AND PROPERTIES

Item 1A. RISK FACTORS

Item 1B. UNRESOLVED STAFF COMMENTS

Item 3. LEGAL PROCEEDINGS

Item 4. MINE SAFETY DISCLOSURES

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

Item 6. SELECTED FINANCIAL DATA

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

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

Item 9A. CONTROLS AND PROCEDURES

Item 9B. OTHER INFORMATION

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Item 11. EXECUTIVE COMPENSATION

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

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

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Filed 2017-02-15. 20 sections, 649K characters. Original on sec.gov · Markdown · JSON

10-K 1 diamondback201610-k.htm DIAMONDBACK 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, 2016



¨	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. ý

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, 2016 was approximately $4,475,534,237.

As of February 13, 2017, 90,143,934 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2017 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

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2016

TABLE OF CONTENTS



	Page
Glossary of Oil and Natural Gas Terms	ii
Glossary of Certain Other Terms	v
Cautionary Statement Regarding Forward-Looking Statements	vi

PART I
Items 1 and 2. Business and Properties	1
Item 1A. Risk Factors	20
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	47
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	72
Item 8. Financial Statements and Supplementary Data	73
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	73
Item 9A. Controls and Procedures	73
Item 9B. Other Information	76

PART III
Item 10. Directors, Executive Officers and Corporate Governance	76
Item 11. Executive Compensation	76
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	76
Item 13. Certain Relationships and Related Transactions, and Director Independence	76
Item 14. Principal Accountant Fees and Services	76

PART IV
Item 15. Exhibits and Financial Statement Schedules	77
Signatures	S-1
Index to Consolidated Financial Statements
Exhibit Index	E-1

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and natural gas industry terms used in 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.
Basin	A large depression on the earth’s surface in which sediments accumulate.
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	Barrels per day.
BOE	Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d	Barrels of oil equivalent per day.
Brent	Brent sweet light crude oil.
British Thermal Unit or BTU	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
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 that is primarily natural gas.
Crude oil	Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Developed acreage	Acreage assignable to productive wells.
Development costs	Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
Differential	An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole or dry well	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.
Estimated Ultimate Recovery or EUR	Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
Exploitation	A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
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.
Horizontal wells	Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
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	Thousand cubic feet of natural gas per day.
Mineral interests	The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu	Million British Thermal Units.
MMcf	Million cubic feet of natural gas.



Net acres or net wells	The sum of the fractional working interest owned in gross acres.
Net revenue interest	An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
Oil and natural gas properties	Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator	The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
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.
Reserves	Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
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.
Resource 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.
Royalty interest	An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations.
Spacing	The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
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.
Tight formation	A formation with low permeability that produces natural gas with very low flow rates for long periods of time.

iii



Undeveloped acreage	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest	An 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.
WTI	West Texas Intermediate.

GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms that are used in this report.



2012 Plan	The Company’s 2012 Equity Incentive Plan.
Bison	Bison Drilling and Field Services, LLC.
Company	Diamondback Energy, Inc., a Delaware corporation, together with its subsidiaries.
EPA	U.S. Environmental Protection Agency.
Exchange Act	The Securities Exchange Act of 1934, as amended.
FERC	Federal Energy Regulatory Commission.
GAAP	Accounting principles generally accepted in the United States.
General Partner	Viper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
2021 Indenture	The indenture relating to the 2021 Senior Notes, dated as of September 18, 2013, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
2024 Indenture	The indenture relating to the 2024 Senior Notes, dated as of October 28, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
2025 Indenture	The indenture relating to the 2025 Senior Notes, dated as of December 20, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
Muskie	Muskie Proppant LLC.
NYMEX	New York Mercantile Exchange.
OSHA	Federal Occupational Safety and Health Act.
Partnership	Viper Energy Partners LP, a Delaware limited partnership.
Partnership agreement	The first amended and restated agreement of limited partnership, dated as of June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the Viper Offering.
Ryder Scott	Ryder Scott Company, L.P.
SEC	Securities and Exchange Commission.
Securities Act	The Securities Act of 1933, as amended.
2021 Senior Notes	The Company’s 7.625% senior unsecured notes due 2021 in the aggregate principal amount of $450 million.
2024 Senior Notes	The Company’s 4.750% senior unsecured notes due 2024 in the aggregate principal amount of $500 million.
2025 Senior Notes	The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $500 million.
Senior Notes	The 2024 Senior Notes and the 2025 Senior Notes.
Viper	Viper Energy Partners L.P.
Viper LTIP	Viper Energy Partners L.P. Long Term Incentive Plan.
Viper Offering	The Partnerships’ initial public offering.
Wells Fargo	Wells Fargo Bank, National Association.

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 and Section 21E of the Securities 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, including under Part I, Item 1A. “Risk Factors” in this report, 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;


•	acquisitions


•	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 or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. 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.

PART I

Except as noted, 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.”

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. 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 in the Permian Basin. At December 31, 2016, our total net acreage position in the Permian Basin was approximately 105,894 net acres. In addition, we, through our subsidiary Viper Energy Partners LP, or Viper, own mineral interests underlying approximately 107,568 gross (6,404 net royalty) acres primarily in Midland County, Texas in the Permian Basin. Approximately 41% of these net acres are operated by us. We own Viper Energy Partners GP LLC, the general partner of Viper, which we refer to as the general partner, and we own approximately 74% of the limited partner interest in Viper.

Our activities are primarily focused on horizontal development of the Spraberry and Wolfcamp formations of the Midland Basin and the Wolfcamp and Bone Spring formations of the Delaware Basin, both of which are part of the larger Permian Basin in West Texas and New Mexico. The Permian Basin 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.

As of December 31, 2016, our estimated proved oil and natural gas reserves were 205,457 MBOE (which includes estimated reserves of 31,435 MBOE attributable to the mineral interests owned by Viper), based on reserve reports prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers. Of these reserves, approximately 57.9% are classified as proved developed producing. Proved undeveloped, or PUD, reserves included in this estimate are from 120 gross (102 net) horizontal well locations in which we have a working interest, and 14 horizontal wells in which we own only a mineral interest through our subsidiary, Viper. As of December 31, 2016, our estimated proved reserves were approximately 68% oil, 18% natural gas liquids and 14% natural gas.

Based on our evaluation of applicable geologic and engineering data, we currently have approximately 2,722 gross (1,802 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $50.00 per Bbl WTI. We intend to continue to develop our reserves and increase production through development drilling and 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 challenging commodity price environment that we experienced in 2015 continued in 2016, with the posted price of WTI reaching a 12-year low of $26.19 per barrel on February 11, 2016. Commodity prices improved during 2016, but continued to be volatile. Nevertheless, we believe we remain well-positioned in this environment. During 2016, we again demonstrated our operational focus on achieving best-in-class execution, low-cost operations and a conservative balance sheet as we continued to reduce drilling days, well costs and operating expenses while maintaining what we believe to be a peer leading leverage ratio. We intend to continue our operational focus in 2017, emphasizing full cycle economics and financial discipline. We are operating six rigs now and currently intend to operate between six and ten rigs in 2017 depending on market conditions. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans in response to market conditions. We are prepared to decelerate our drilling program if commodity prices deteriorate and continue to accelerate our drilling program should commodity prices remain constant or further improve. We have the option to release up to three of our current six rigs in 2017 should commodity prices deteriorate. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”

Our Pending Acquisition

On December 13, 2016, we entered into a definitive purchase and sale agreement with Brigham Resources Operating, LLC and Brigham Resources Midstream, LLC, or together, Brigham, to acquire certain assets of Brigham, for aggregate consideration consisting of $1.62 billion in cash and the issuance of 7.69 million shares of our common stock to Brigham, subject to certain adjustments. We refer to this transaction as the Pending Acquisition. The assets, located in Pecos and Reeves counties

in Texas include over 93,761 gross (76,319 net) acres, approximately 9,500 BOE/d (77% oil) of average net production for November 2016, based on production, completion and flowback data provided by Brigham that has not been verified by us, from 48 gross producing horizontal wells and 16 gross producing vertical wells. The assets are also estimated to include six drilled but uncompleted wells as of January 1, 2017. Based on our internal estimates and the data provided by Brigham, we believe the assets include approximately 1,149 net royalty acres. Additionally, based on publicly available data with respect to recent horizontal wells on and surrounding the properties, we believe the assets are prospective for four primary targets: Wolfcamp A, Wolfcamp B, the 3rd Bone Spring and the 2nd Bone Spring. We believe that development potential within the footprint of the Pending Acquisition includes 1,213 net identified economic potential horizontal locations, based on 880-foot spacing (six wells per section) in the Wolfcamp A and Wolfcamp B and 1,320-foot inter-lateral spacing (four wells per section) in the 3rd Bone Spring and 2nd Bone Spring. Additional development and downspacing potential may exist throughout the Wolfcamp and Bone Spring intervals. We believe that the identified potential horizontal locations are conducive to more capital efficient longer laterals with an average of approximately 8,500 feet. Assuming all of the acreage in the Pending Acquisition is acquired, our total leasehold interest as of December 31, 2016 would have been approximately 182,000 net acres. The foregoing data and estimates are based primarily on information provided to us by Brigham. We have not yet verified these results and estimates and cannot assure you that actual results will not differ. See Item 1A “Risk Factors-Risks Related to the Pending Acquisition” for a discussion of these risks.

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 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.


•	Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We have targeted various intervals in the Midland Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. Our initial horizontal focus had been on the Wolfcamp B interval, but our recent focus has included the Lower Spraberry, Middle Spraberry and Wolfcamp A intervals. Our first two hor

•

Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We have targeted various intervals in the Midland Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. Our initial horizontal focus had been on the Wolfcamp B interval, but our recent focus has included the Lower Spraberry, Middle Spraberry and Wolfcamp A intervals. Our first two hor

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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 Properties” 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 Pending Acquisition

We may not consummate the Pending Acquisition.

We intend to use the net proceeds from our December 2016 underwritten offering of common stock, together with the net proceeds from our concurrent offering of the 2025 Senior Notes, cash on hand and other financing sources, to fund the cash consideration for the Pending Acquisition, as described under “Item 1. Business and Properties-Our Pending Acquisition.” However, we may not consummate the Pending Acquisition, which is subject to the satisfaction of customary closing conditions. There can be no assurance that such conditions will be satisfied or that the Pending Acquisition will be consummated.

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

Our ability to achieve the anticipated benefits of the Pending Acquisition will depend in part upon whether we can integrate the acquired properties into our existing businesses in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition of producing properties, including those to be acquired in the Pending Acquisition, requires an assessment of several factors, including:


•	recoverable reserves;


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


•	availability and cost of transportation of production to markets;


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


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


•	regulatory, permitting and similar matters; and


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

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we have performed a review of the subject properties that we believe to be generally consistent with industry practices. Our review may not reveal all existing or potential problems or permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies. The integration process may be subject to delays or changed circumstances, and we can give no assurance that the acquired properties will perform in accordance with our expectations. Significant acquisitions, including the Pending Acquisition, and other strategic transactions may involve other risks that may cause our business to suffer, including:


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


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

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

We expect to incur significant costs associated with the Pending Acquisition and integration and/or development of the assets subject to the Pending Acquisition as part of our operations. The substantial majority of the expenses resulting from the Pending Acquisition will be composed of transaction costs related to the Pending Acquisition and the costs involved in financing of the Pending Acquisition. We may also incur transaction fees and costs related to formulating integration and/or development plans for the assets subject to the Pending Acquisition.

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

The Pending Acquisition may be subject to claims that it should be limited, subordinated or voided under applicable law in favor of the seller. These laws include those that relate to fraudulent conveyance or transfer, voidable preference, financial assistance, corporate purpose or benefit, preservation of share capital, thin capitalization and defenses affecting the rights of creditors generally. In general, under fraudulent conveyance and similar laws, a court might void or otherwise decline to enforce the Pending Acquisition if it found that when we entered into the Pending Acquisition, the seller received less than reasonably equivalent value or fair consideration for the Pending Acquisition and one of the following is true:


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


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


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


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

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

The measures of insolvency applied by courts will vary depending upon the particular fraudulent transfer law applied in any proceeding to determine whether a fraudulent transfer has occurred. In the event of a finding that a fraudulent conveyance or transfer has occurred, a court may void, or hold unenforceable, the Pending Acquisition.

Failure to complete the Pending Acquisition could negatively impact our future business and financial results.

If the Pending Acquisition is not completed or if there are significant delays in completing the Pending Acquisition, our future business and financial results and the trading price of our common stock could be negatively affected, including the following:


•	the parties may be liable for damages to one another under the terms and conditions of the purchase agreement for the Pending Acquisition;


•	there may be negative reactions from the financial markets due to the fact that current prices of our common stock may reflect a market assumption that the Pending Acquisition will be completed; and


•	the attention of management will have been div

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None.

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.

Not applicable.

PART II

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:



	High		Low
2016
1st Quarter	$	79.87	$	55.48
2nd Quarter	$	96.01	$	73.12
3rd Quarter	$	99.69	$	83.90
4th Quarter	$	113.23	$	88.74
2015
1st Quarter	$	78.75	$	55.53
2nd Quarter	$	85.82	$	73.36
3rd Quarter	$	77.36	$	60.28
4th Quarter	$	82.19	$	61.51

Holders of Record

There were six holders of record of our common stock on February 13, 2017.

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.

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 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 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, 2016, 2015 and 2014 and the balance sheet data as of December 31, 2016 and 2015 are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The historical financial data for the year ended December 31, 2013 and 2012 and the balance sheet data as of December 31, 2014, 2013 and 2012 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)	2016			2015			2014		2013			2012(1)
Statements of Operations Data:
Total revenues	$	527,107		$	446,733		$	495,718	$	208,002		$	74,962
Total costs and expenses	595,724			1,187,002			283,048		112,808			57,655
Income (loss) from operations	(68,617		)	(740,269		)	212,670		95,194			17,307
Other income (expense)	(96,099		)	(8,831		)	92,286		(8,853		)	1,075
Income (loss) before income taxes	(164,716		)	(749,100		)	304,956		86,341			18,382
Provision for (benefit from) income taxes	192			(201,310		)	108,985		31,754			54,903
Net income (loss)	(164,908		)	(547,790		)	195,971		54,587			(36,521		)
Less: Net income attributable to non-controlling interest	126			2,838			2,216		—			—
Net income (loss) attributable to Diamondback Energy, Inc.	$	(165,034	)	$	(550,628	)	$	193,755	$	54,587		$	(36,521	)
Earnings per common share
Basic	$	(2.20	)	$	(8.74	)	$	3.67	$	1.30
Diluted	$	(2.20	)	$	(8.74	)	$	3.64	$	1.29
Weighted average common shares outstanding
Basic	75,077			63,019			52,826		42,015
Diluted	75,077			63,019			53,297		42,255
Pro forma information(2)
Income before income taxes, as reported												$	18,382
Pro forma provision for income taxes												6,553
Pro forma net income												$	11,829
Pro forma earnings per common share(3)
Basic												$	0.60
Diluted												$	0.60



	As of December 31,
(In thousands)	2016		2015		2014		2013		2012(1)
Balance Sheet Data:
Cash and cash equivalents	$	1,666,574	$	20,115	$	30,183	$	15,555	$	26,358
Net property and equipment	3,390,857		2,597,625		2,791,807		1,446,337		554,242
Total assets	5,349,680		2,750,719		3,095,481		1,521,614		606,701
Current liabilities	209,342		141,421		266,729		121,320		79,232
Long-term debt	1,105,912		487,807		673,500		460,000		193
Total Stockholders’/ Members’ equity(4)	3,697,462		1,875,972		1,751,011		845,541		462,068
Total equity	4,018,292		2,108,973		1,985,213		—		—



	Year Ended December 31,
(In thousands)	2016			2015			2014			2013			2012(1)
Other Financial Data:
Net cash provided by operating activities	$	332,080		$	416,501		$	356,389		$	155,777		$	49,692
Net cash used in investing activities	(1,310,242		)	(895,050		)	(1,481,997		)	(940,140		)	(183,078		)
Net cash provided by financing activities	2,624,621			468,481			1,140,236			773,560			152,785



	Year Ended December 31,
(In thousands)	2016		2015		2014		2013		2012(1)
Consolidated Adjusted EBITDA(5)	$	387,535	$	449,245	$	398,334	$	157,604	$	42,783


(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.

(1)

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


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

(2)

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


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

(3)

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


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


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

Non-GAAP financial measure and reconciliation

Consolidated 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 Consolidated Adjusted EBITDA as net income (loss) plus non-cash loss on derivative instruments, net, interest expense, depreciation, depletion and amortization expense, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, income tax (benefit) provision and non-controlling interest. Consolidated Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. Management believes Consolidated 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 add the items listed above to net income (loss) in arriving at Consolidated 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. Consolidated 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 Consolidated 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 Consolidated Adjusted EBITDA. Our computations of Consolidated Adjusted EBITDA may not be comparable to other similarly titled measure of other companies or to such measure in our revolving credit facility or any of our other contracts.

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



	Year Ended December 31,
(In thousands)	2016			2015			2014			2013			2012
Net income (loss)	$	(164,908	)	$	(547,790	)	$	195,971		$	54,587		$	(36,521	)
Non-cash (gain) loss on derivative instruments, net	26,522			112,918			(117,109		)	(5,346		)	(8,057		)
Interest expense	40,684			41,510			34,515			8,059			3,610
Depreciation, depletion and amortization	178,015			217,697			170,005			66,597			26,273
Impairment of oil and natural gas properties	245,536			814,798			—			—			—
Non-cash equity-based compensation expense	33,532			24,572			14,253			2,724			3,482
Capitalized equity-based compensation expense	(7,079		)	(6,043		)	(4,437		)	(972		)	(1,005		)
Asset retirement obligation accretion expense	1,064			833			467			201			98
Loss on extinguishment of debt	33,134			—			—			—			—
Income tax (benefit) provision	192			(201,310		)	108,985			31,754			54,903
Non-controlling interest	843			(7,940		)	(4,316		)	—			—
Consolidated Adjusted EBITDA	$	387,535		$	449,245		$	398,334		$	157,604		$	42,783

The following discussion and analysis should be read in conjunction with our 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 Statement 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 horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and 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.

The following table sets forth our production data for the periods indicated:



	Year Ended December 31,
	2016		2015		2014
Oil (Bbls)	73	%	75	%	76	%
Natural gas (Mcf)	11	%	11	%	10	%
Natural gas liquids (Bbls)	16	%	14	%	14	%
	100	%	100	%	100	%

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

2016 Transactions and Recent Developments

Our Equity Offerings

In January 2016, 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 underwriter. The stock was sold to the underwriter at $55.33 per share and we received proceeds of approximately $254.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions, which we used to repay the borrowings outstanding under our revolving credit facility and to fund a portion of our exploration and development activities and for general corporate purposes.

In July 2016, we completed an underwritten public offering of 6,325,000 shares of common stock, which included 825,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the underwriters at $87.24 per share and we received proceeds of approximately $551.8 million from the sale of these shares of common stock, net of estimated offering expenses and underwriting discounts and commissions, which we used to fund a portion of the purchase price for the acquisition of certain leasehold interests and related assets in the Southern Delaware Basin.

In December 2016, we completed an underwritten public offering of 12,075,000 shares of common stock, which included 1,575,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the underwriters at $95.3025 per share and we received proceeds of approximately $1,150.8 million from the sale of these shares of common stock, net of estimated offering expenses and underwriting discounts and commissions. We intend to use these net proceeds, together with the net proceeds from our offering of the 2025 senior notes, cash on hand and other financing sources, to fund the cash consideration for the Pending Acquisition.

Viper’s Equity Offerings

In August 2016, Viper completed an underwritten public offering of 8,050,000 common units, which included 1,050,000 common units issued pursuant to an option to purchase additional common units granted to the underwriter. In this offering, we purchased 2,000,000 common units from the underwriter at $15.60 per unit, which is the price per common unit paid by the underwriter to Viper. Following this public offering, we had an approximate 83% limited partner interest in Viper. Viper received proceeds from this offering of approximately $125.0 million, net of estimated offering expenses and underwriting discounts and commissions, which Viper used to repay outstanding borrowings under Viper’s revolving credit facility and fund the acquisition of mineral interests.

In January 2017, Viper completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following the January 2017 public offering, we had an approximate 74% limited partner interest in Viper. Viper received net proceeds from this offering of approximately $147.6 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which Viper used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and intends to use the remaining net proceeds for general partnership purposes, which may include additional acquisitions.

Senior Note Transactions

On October 28, 2016, we completed an offering of $500.0 million in aggregate principal amount of our 4.75% senior notes due 2024, which we refer to as the 2024 senior notes. We received approximately $496.0 million in net proceeds from the offering of the 2024 senior notes, which were used primarily to repurchase all of our outstanding 7.625% senior notes due 2021, which we refer to as the 2021 senior notes, accepted for purchase in a related tender offer, to pay fees and expenses thereof and to redeem the 2021 senior notes that remained outstanding after completion of the tender offer discussed below. We intend to use the remaining net proceeds from the offering of the 2024 senior notes for general corporate purposes, which may include the funding of a portion of the our capital development plans.

On October 21, 2016, we commenced a cash tender offer to purchase any and all of our 2021 senior notes, which tender offer expired on October 27, 2016 and settled on October 28, 2016. An aggregate of $330.1 million principal amount of the 2021 senior notes was validly tendered in the tender offer. The remaining 2021 senior notes that were not tendered in the tender offer were redeemed by us, and the indenture governing the 2021 senior notes was fully satisfied and discharged. The cash tender offer for the 2021 senior notes and redemption of the remaining 2021 senior notes were funded with a portion of the net proceeds from the offering of the 2024 senior notes.

On December 20, 2016, we completed an offering of $500.0 million in aggregate principal amount of our 5.375% senior notes due 2025, which we refer to as the 2025 senior notes. We received approximately $495.8 million in net proceeds from the offering of the 2025 senior notes, which we intend to use, together with the net proceeds from our December 2016 underwritten public offering of common stock, cash on hand and other financing sources, to fund the cash consideration for the Pending Acquisition.

Our Recent Acquisition

On September 1, 2016, we acquired from an unrelated third party leasehold interests and related assets in the Southern Delaware Basin for an aggregate purchase price of $558.5 million. This transaction included approximately 26,797 gross (19,262 net) acres primarily in Reeves and Ward counties, 19 gross producing vertical wells, 11 gross producing horizontal w

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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, including basis swaps, to reduce price volatility associated with certain of our oil and natural gas 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 reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX WTI.

At December 31, 2016, we had a net liability derivative position of $22.6 million related to our price swap and price basis swap derivatives, as compared to a net asset derivative position of $4.6 million as of December 31, 2015 related to our price swap and price basis swap derivatives. Utilizing actual derivative contractual volumes under our fixed price swaps and fixed price basis swaps as of December 31, 2016, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $40.7 million, an increase of $18.0 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position to $4.6 million, a decrease of $18.0 million. 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 $49.5 million at December 31, 2016) and receivables from the sale of our oil and natural gas production (approximately $70.6 million at December 31, 2016).

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, 2016, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). For the year ended December 31, 2014, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (64%); and Enterprise Crude Oil LLC (16%). 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, 2016, we had three customers that represented approximately 75% of our total joint operations receivables. At December 31, 2015, we had five customer that represented approximately 73% 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 an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base.

As of December 31, 2016, we had no borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 1.92% on January 19, 2016, the last day on which borrowings were outstanding under such facility. An increase or decrease of 1% in the interest rate would have a corresponding decrease or

increase in our interest expense of approximately $0.1 million based on the $11.0 million outstanding in the aggregate under our revolving credit facility as of such date.

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

None.

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer 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 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, 2016, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2016, 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 year ended December 31, 2016 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.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internal control over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2016.

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, 2016. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2016, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial 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, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2016, and our report dated February 15, 2017 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

February 15, 2017

None.

PART III

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, 2016.

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. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. The Company also has made the Code of Business Conduct and Ethics available on our website under the “Corporate Governance” section at http://ir.diamondbackenergy.com. 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.

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, 2016.

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, 2016.

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, 2016.

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, 2016.

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



(a)	Documents included in this report:
	1. Financial Statements
	Report of Independent Registered Public Accounting Firm	F-1
	Consolidated Balance Sheets	F-2
	Consolidated Statements of Operations	F-3
	Consolidated Statement of Stockholders' Equity	F-4
	Consolidated Statements of Cash Flows	F-5
	Notes to Consolidated Financial Statements	F-7

	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 consolidated financial statements and related notes.

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

SIGNATURES

Pursuant to the requirements of the Securities and 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 15, 2017
		/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities and 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 15, 2017
Steven E. West

/s/ Travis D. Stice	Chief Executive Officer and Director	February 15, 2017
Travis D. Stice	(Principal Executive Officer)

/s/ Michael P. Cross	Director	February 15, 2017
Michael P. Cross

/s/ David L. Houston	Director	February 15, 2017
David L. Houston

/s/ Mark L. Plaumann	Director	February 15, 2017
Mark L. Plaumann

/s/ Teresa L. Dick	Chief Financial Officer, Senior Vice President, and Assistant Secretary	February 15, 2017
Teresa L. Dick	(Principal Financial and Accounting Officer)

S-1

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, 2016 and 2015, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016. 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 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 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, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 15, 2017 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

February 15, 2017

F-1

Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets



	December 31,
	2016			2015
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	1,666,574		$	20,115
Restricted cash	500			500
Accounts receivable:
Joint interest and other	49,476			41,309
Oil and natural gas sales	70,349			36,004
Related party	297			1,591
Inventories	1,983			1,728
Derivative instruments	—			4,623
Prepaid expenses and other	2,987			2,875
Total current assets	1,792,166			108,745
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($1,730,519 and $1,106,816 excluded from amortization at December 31, 2016 and December 31, 2015, respectively)	5,160,261			3,955,373
Pipeline and gas gathering assets	8,362			7,174
Other property and equipment	58,290			48,621
Accumulated depletion, depreciation, amortization and impairment	(1,836,056		)	(1,413,543		)
Net property and equipment	3,390,857			2,597,625
Funds held in escrow	121,391			—
Derivative instruments	709			—
Other assets	44,557			44,349
Total assets	$	5,349,680		$	2,750,719
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	47,648		$	20,008
Accounts payable-related party	1			217
Accrued capital expenditures	60,350			59,937
Other accrued liabilities	55,330			44,293
Revenues and royalties payable	23,405			16,966
Derivative instruments	22,608			—
Total current liabilities	209,342			141,421
Long-term debt	1,105,912			487,807
Asset retirement obligations	16,134			12,518
Total liabilities	1,331,388			641,746
Commitments and contingencies (Note 15)
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 90,143,934 issued and outstanding at December 31, 2016; 66,797,041 issued and outstanding at December 31, 2015	901			668
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