UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2017~~2018

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-37964

~~WildHorse~~ BRAZOS ~~Resource~~VALLEY ~~Development~~LONGHORN, ~~Corporation~~L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

(Exact name of Registrant as specified in its Charter)

Delaware		8183-~~3470246~~3294278
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
9805 Katy Freeway, Suite 400, Houston, TX		77024
6100 N. Western Avenue, Oklahoma City, OK		73118
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (~~713~~405) ~~568~~848-~~4910~~8000

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

Common Stock, par value $0.01 per share		New York Stock Exchange
(Title of each class)		(Name of each exchange on which registered)

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

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

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

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 ☒ 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 ☒ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) 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, a smaller reporting company, or an emerging growth company. See the definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ☐ Accelerated filer ☒☐ Non-accelerated filer ☐☒ ~~(Do~~Smaller ~~not check if a small~~ reporting company) ~~Small reporting company~~ ☐ Emerging growth company ☒☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 ☒

The ~~aggregate market value of the 21,438,051 shares of voting stock held by non-affiliates of the~~ registrant, ~~based~~is ~~upon~~a ~~the~~wholly ~~closing~~owned ~~sale~~subsidiary ~~price~~ of ~~the~~Chesapeake ~~registrant’s~~Energy ~~common~~Corporation ~~stock~~and onmeets ~~June 30, 2017,~~ the ~~last~~conditions ~~business~~set ~~day~~forth ofin ~~the~~General ~~registrant’s~~Instruction ~~most~~I(1)(a) ~~recently~~and ~~completed~~(b) ~~second fiscal quarter,~~ of ~~$12.37~~Form ~~per~~10-K ~~share as reported on the New York Stock Exchange was $265.2 million. Shares of common stock held by each director~~ and ~~executive~~is ~~officer~~therefore ~~and~~filing bythis ~~each~~Form ~~person~~with ~~who owns 10 percent or more of~~ the ~~outstanding~~reduced ~~common~~disclosure ~~stock~~format oras ~~who~~permitted ~~is otherwise believed~~ by ~~the~~Instruction ~~registrant to be in a control position have been excluded~~I(2). ~~This determination of affiliate status is limited to this calculation and is not intended to be determinative for any other purpose.~~

As of ~~February~~March 284, ~~2018~~2019, Chesapeake ~~the~~owns ~~registrant~~100% ~~had~~of ~~101,304~~the ~~,079~~outstanding ~~shares~~LLC units of ~~common~~Brazos ~~stock~~Valley Longhorn, $0L.01L.C., ~~par~~the ~~value~~successor ~~outstanding~~company to WildHorse Resource Development Corporation.

~~DOCUMENTS~~ Table ~~INCORPORATED~~of ~~BY REFERENCE~~Contents

~~The~~ BRAZOS ~~Company’s~~VALLEY ~~definitive proxy statement relating to the annual meeting of shareholders (to be held May 17~~LONGHORN, 2018) will be filed with the Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2017 and is incorporated by reference in Part III to the extent described hereinL.L.C.

~~WILDHORSE~~ (Successor ~~RESOURCE~~in ~~DEVELOPMENT~~interest ~~CORPORATION~~to WildHorse Resource Development Corporation)

TABLE OF CONTENTS

		Page	~~Page~~
	PART I	~~PART I~~
Item 1.	Business	~~Business~~10	10
Item 1A.	Risk Factors	~~Risk Factors~~20	31
Item 1B.	Unresolved Staff Comments	~~Unresolved Staff Comments~~34	52
Item 2.	Properties	~~Properties~~34	52
Item 3.	Legal Proceedings	~~Legal Proceedings~~34	52
Item 4.	Mine Safety Disclosures	~~Mine Safety Disclosures~~34	52
	PART II	~~PART II~~
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	~~Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities~~35	53
Item 6.	Selected Financial Data	~~Selected Financial Data~~35	55
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~36	57
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	~~Quantitative and Qualitative Disclosures About Market Risk~~48	75
Item 8.	Financial Statements and Supplementary Data	~~Financial Statements and Supplementary Data~~50	78
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	~~Changes in and Disagreements With Accountants on Accounting and Financial Disclosure~~51	78
Item 9A.	Controls and Procedures	~~Controls and Procedures~~51	79
Item 9B.	Other Information	~~Other Information~~51	79
	PART III	~~PART III~~
Item 10.	Directors and Executive Officers of the Registrant	~~Directors, Executive Officers and Corporate Governance~~52	80
Item 11.	Executive Compensation	~~Executive Compensation~~52	80
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters~~52	80
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~Certain Relationships and Related Transactions, and Director Independence~~52	80
Item 14.	Principal Accountant Fees and Services	~~Principal Accounting Fees and Services~~52	80
	PART IV	~~PART IV~~
Item 15.	Exhibits and Financial Statement Schedules	~~Exhibits and Financial Statement Schedules~~53	81
Item 16.	Form 10‑K Summary	~~Form 10-K Summary~~55	84

Table of Contents

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

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 natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl: One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.

Bcf: One billion cubic feet of natural gas.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This isratio reflects an energy content ~~correlation~~equivalency and ~~does~~ not ~~reflect~~ a ~~value~~price or ~~price~~revenue ~~relationship~~equivalency. ~~between~~Despite ~~the~~holding ~~commodities~~this ratio constant at six mcf to one bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

Boe/d: One Boe per day.

British thermal unit or Btu: The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion: Installation of permanent equipment for production of oil or natural gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Condensate: A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Delineation: The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

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

Development costs: Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs refer to the SEC’'s Regulation S-X, Rule 4-‑10(a)(7).

Development project: The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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

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.

Downspacing: Additional wells drilled between known producing wells to better develop the reservoir.

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.

Economically producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’'s Regulation S-X, Rule 4-‑10(a)(10).

Estimated ultimate recovery or EUR: The sum of reserves remaining as of a given date and cumulative production as of that date.

Exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

~~Field:~~ Table ~~An area consisting~~ of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).Contents

Exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field: An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC's Regulation S-X, Rule 4‑10(a)(15).

Formation: A layer of rock which has distinct characteristics that differs from nearby rock.

Generation 1: With respect to our Eagle Ford Acreage, a hybrid fracking technique using approximately 1,500 pounds per foot of sand and 33 Bbls per foot of fluid, with 200 foot stages and five clusters per stage at 80 barrels per minute. With respect to our North Louisiana Acreage, a slickwater fracking technique using approximately 1,450 pounds per foot of sand, with 200 foot stages and one cluster per stage at 57 barrels per minute.

Generation 3: With respect to our Eagle Ford Acreage, a slickwater fracking technique using approximately 3,700 pounds per foot of sand and 75 Bbls per foot of fluid, with 150 foot stages and nine clusters per stage at 90 barrels per minute.

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

Held by production: Acreage covered by a mineral lease that perpetuates a company’'s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.

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 within a specified interval.

MBbls: One thousand barrels of crude oil, condensate or NGLs.

MBoe: One thousand Boe.

Mcf: One thousand cubic feet of natural gas.

MMBbls: One million barrels of crude oil, condensate or NGLs.

MMBoe: One million Boe.

MMBtu: One million British thermal units.

Net acres or net wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.

Net production: Production that is owned less royalties and production due to others.

NGLs: Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

NYMEX: The New York Mercantile Exchange.

Offset operator: Any entity that has an active lease on an adjoining property for oil, natural gas or NGLs purposes.

Operator: The individual or company responsible for the development and/or production of an oil or natural gas well or lease.

Play: A geographic area with hydrocarbon potential.

Possible Reserves: Reserves that are less certain to be recovered than probable reserves.

Present value of future net revenues or PV-‑10 (non-GAAP): The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

Probable Reserves: Reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered.

~~Production~~ Table ~~costs: Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs~~ of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).Contents

Probable Reserves: Reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered.

Production costs: Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC's Regulation S-X, Rule 4‑10(a)(20).

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 area: Part of a property to which proved reserves have been specifically attributed.

Proved developed reserves: Reserves that can be expected to be recovered through (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved properties: Properties with proved reserves.

Proved reserves: Those quantities of oil, natural gas and NGLs, 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’'s Regulation S-X, Rule 4-‑10(a)(22).

Proved undeveloped reserves or PUDs: 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. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Realized price: The cash market price less all expected quality, transportation and demand adjustments.

Reasonable certainty: A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’'s Regulation S-X, Rule 4-‑10(a)(24).

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Table of Contents

Reliable technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves: 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 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 oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resources: Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Royalty: An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’'s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

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.

Spot market price: The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized measure: Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

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.

Unproved properties: Properties with no proved reserves.

Wellbore: The hole drilled by the bit that is equipped for oil and natural gas production on a completed well. Also called well or borehole.

Working interest: The right granted to the lessee of a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

Workover: Operations on a producing well to restore or increase production.

WTI: West Texas Intermediate.

Table of Contents

Commonly Used Defined Terms

As used in this Annual Report unless the context indicates or otherwise requires, the terms listed below have the following meanings:

•· the “Company,” “WildHorse Development,” “we,” “our,” “us” or like terms refer collectively to WHR II and Esquisto, together with their consolidated subsidiaries before the completion of our Corporate Reorganization and to WildHorse Resource Development Corporation and its consolidated subsidiaries, including WHR II, Esquisto and Acquisition Co., as of and following the completion of our Corporate Reorganization, and to Brazos Valley Longhorn, L.L.C., a Delaware limited liability company and successor to WildHorse Resource Development Corporation, following the completion of the Merger;

•· “~~WHR II~~Chesapeake” ~~or our “predecessor”~~ refers to ~~WildHorse~~Chesapeake ~~Resources~~Energy ~~II,~~Corporation ~~LLC,~~and ~~together with~~ its consolidated subsidiaries, ~~which~~as ~~owns all of our North Louisiana Acreage~~applicable;

•· “~~Esquisto~~WHR II” ~~refers~~or ~~(i)~~our ~~for~~“predecessor” ~~the~~refers ~~period beginning January 1, 2014 through June 19, 2014,~~ to ~~the~~WildHorse ~~Initial~~Resources ~~Esquisto Assets~~II, ~~(ii) for the period beginning June 20~~LLC, ~~2014~~together ~~through~~with ~~February~~its ~~16,~~consolidated ~~2015~~subsidiaries, towhich ~~Esquisto~~previously Iowned ~~(iii)~~all ~~for the period beginning February 17, 2015 (date~~ of ~~common control) through January 11, 2016, to Esquisto I and Esquisto II on a combined basis and (iv) for the period beginning January 12, 2016 through the completion of~~ our ~~initial~~North ~~public~~Louisiana ~~offering on December 19, 2016, to Esquisto II~~Acreage;

•· “Esquisto” refers (i) for the period beginning January 1, 2014 through June 19, 2014, to the Initial Esquisto Assets”, ~~refers~~(ii) tofor the ~~oil~~period ~~and~~beginning ~~natural~~June ~~gas~~20, ~~properties~~2014 ~~contributed~~through February 16, 2015, to Esquisto I in(iii) ~~connection~~for ~~with~~ the ~~formation~~period beginning February 17, 2015 (date of common control) through January 11, 2016, to Esquisto I and Esquisto II on ~~June~~a 20combined basis and (iv) for the period beginning January 12, ~~2014~~2016 through the completion of our initial public offering on December 19, 2016, to Esquisto II;

•· “Initial Esquisto IAssets” refers to the oil and natural gas properties contributed to Esquisto ~~Resources~~I in connection with the formation of Esquisto I on June 20, ~~LLC~~2014;

•· “Esquisto III” refers to Esquisto Resources II, LLC;

•· “Esquisto ~~Merger~~II” refers to ~~the merger of~~ Esquisto IResources ~~with and into Esquisto~~ II ~~on January 12~~, ~~2016~~LLC;

•· “~~Acquisition~~Esquisto ~~Co.~~Merger” refers to ~~WHE~~the ~~AcqCo.,~~merger ~~LLC,~~of anEsquisto ~~entity~~I ~~formed~~with toand ~~acquire~~into ~~the~~Esquisto ~~Burleson~~II ~~North~~on ~~Assets~~January 12, 2016;

•· “~~Previous~~Acquisition ~~owner~~Co.” refers to ~~both~~WHE ~~Esquisto~~AcqCo., ~~and~~LLC, ~~Acquisition~~an ~~Co.~~entity formed to acquire the Burleson North Assets;

•· “~~Management~~Previous ~~Members~~owner” refers ~~(i) in the case of WHR II, collectively~~ to ~~the~~both ~~individual founders and employees and other individuals who, together with NGP, initially formed WHR II and (ii) in the case of~~ Esquisto, ~~collectively to the individual founders~~ and ~~employees~~Acquisition ~~and other individuals who initially formed Esquisto~~Co.;

•· ~~the~~ “~~Corporate~~Management ~~Reorganization~~Members” refers to (~~prior to and in connection with our initial public offering) (~~i) ~~the former owners of WHR II exchanging all of their interests~~ in ~~WHR II for equivalent interests in WildHorse Investment Holdings and~~ the ~~former~~case ~~owners~~ of Esquisto exchanging all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) the contribution by WildHorse Investment Holdings to WildHorse Holdings of all of the interests in WHR II, ~~the~~collectively ~~contribution by Esquisto Investment Holdings~~ to ~~Esquisto Holdings of all of~~ the ~~interests~~individual infounders ~~Esquisto~~ and ~~the~~employees ~~contribution~~and byother ~~the~~individuals ~~former owner of Acquisition Co. of all its interests in Acquisition Co. to Acquisition Co. Holdings~~who, ~~(iii)~~together ~~the~~with ~~issuance of management incentive units by WildHorse Holdings~~NGP, ~~Esquisto~~initially ~~Holdings~~formed ~~and~~WHR ~~Acquisition~~II ~~Co. Holdings to certain of our officers~~ and ~~employees and~~ (ivii) in the ~~contribution~~case byof ~~WildHorse Holdings~~Esquisto, ~~Esquisto~~collectively ~~Holdings and Acquisition Co. Holdings~~ to ~~us of all of~~ the ~~interests~~individual infounders ~~WHR~~and ~~II,~~employees ~~Esquisto~~ and ~~Acquisition~~other ~~Co.,~~individuals ~~respectively,~~who ininitially ~~exchange~~formed ~~for shares of our common stock~~Esquisto;

•· the “~~WildHorse~~Corporate ~~Holdings~~Reorganization” refers to (prior to and in connection with our initial public offering) (i) the former owners of WHR II exchanging all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings and the former owners of Esquisto exchanging all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, ~~LLC~~(ii) the contribution by WildHorse Investment Holdings to WildHorse Holdings of all of the interests in WHR II, athe ~~limited~~contribution ~~liability~~by ~~company~~Esquisto ~~formed~~Investment Holdings to ~~own~~Esquisto aHoldings ~~portion~~of all of the interests in Esquisto and the contribution by the former owner of Acquisition Co. of all its interests in Acquisition Co. to Acquisition Co. Holdings, (iii) the issuance of management incentive units by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings to certain of our ~~common~~officers ~~stock~~and ~~following~~employees and (iv) the ~~Corporate~~contribution ~~Reorganization~~by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings to us of all of the interests in WHR II, Esquisto and Acquisition Co., respectively, in exchange for shares of our common stock;

• “WildHorse Investment Holdings” refers to WildHorse Investment Holdings, LLC, a limited liability company formed to own all of the outstanding equity interests in WildHorse Holdings other than certain management incentive units issued by WildHorse Holdings in connection with our initial public offering as further described elsewhere in this Annual Report;

• “Esquisto Holdings” refers to Esquisto Holdings, LLC, a limited liability company formed to own a portion of our common stock following the Corporate Reorganization;

• “Esquisto Investment Holdings” refers to Esquisto Investment Holdings, LLC, a limited liability company formed to own all of the outstanding equity interests in Esquisto Holdings other than certain management incentive units issued by Esquisto Holdings in connection with our initial public offering as further described elsewhere in this Annual Report;

• “Acquisition Co. Holdings” refers to WHE AcqCo Holdings, LLC, a limited liability company formed to own a portion of our common stock following the Corporate Reorganization;

• “North Louisiana Acreage” refers to our acreage in North Louisiana in and around the highly prolific Terryville Complex, which has been historically owned and operated by WHR II, and where we primarily target the overpressured Cotton Valley play;

• Table ~~“Terryville~~of ~~Complex” refers to the play located primarily in Lincoln Parish, Louisiana, and northern Jackson Parish, Louisiana;~~Contents

•· “~~RCT~~WildHorse ~~Area~~Holdings” refers to ~~our~~WHR ~~Ruston-Choudrant-Tremont~~Holdings, ~~acreage~~LLC, ~~within~~a ~~the~~limited ~~Terryville~~liability ~~Complex~~company ~~located~~formed ~~primarily~~to inown ~~Lincoln~~a ~~Parish,~~portion ~~Louisiana~~of our common stock following the Corporate Reorganization;

•· “~~Weyerhaeuser~~WildHorse ~~Area~~Investment Holdings” refers to ~~the~~WildHorse ~~acreage~~Investment ~~that~~Holdings, weLLC, ~~have~~a ~~the~~limited ~~right~~liability company formed to ~~lease~~own ~~within~~all of the ~~Terryville~~outstanding ~~Complex~~equity ~~located~~interests in ~~northern~~WildHorse ~~Jackson~~Holdings ~~Parish,~~other ~~Louisiana,~~than ~~which~~certain ~~acreage~~management isincentive ~~included~~units issued by WildHorse Holdings in ~~our~~connection ~~North~~with ~~Louisiana~~our ~~acreage~~initial inpublic ~~this~~offering ~~Annual~~as ~~Report~~further ~~(see~~described ~~“Business—Development~~elsewhere ofin ~~Proved~~this ~~Undeveloped~~Annual ~~Reserves—Acreage)~~Report;

•· “~~Eagle~~Esquisto ~~Ford Acreage~~Holdings” refers to ~~our~~Esquisto ~~acreage~~Holdings, inLLC, ~~the~~a ~~northern~~limited ~~area~~liability ofcompany ~~the~~formed ~~Eagle~~to ~~Ford~~own ~~Shale~~a inportion ~~East~~of ~~Texas,~~our ~~which~~common ~~has~~stock ~~historically~~following ~~been~~the ~~owned~~Corporate ~~and operated by Esquisto~~Reorganization;

•· “~~Burleson~~Esquisto ~~North~~Investment ~~Assets~~Holdings” refers to ~~certain~~Esquisto ~~producing~~Investment ~~properties~~Holdings, ~~and~~LLC, ~~undeveloped~~a ~~acreage~~limited ~~that~~liability ~~Acquisition~~company ~~Co.~~formed ~~acquired~~to ~~from~~own ~~Clayton~~all ~~Williams~~of ~~Energy,~~the ~~Inc.~~outstanding ~~prior~~equity tointerests orin ~~contemporaneously~~Esquisto ~~with~~Holdings ~~the~~other ~~closing~~than ofcertain management incentive units issued by Esquisto Holdings in connection with our initial public offering, ~~which~~as ~~acquisition~~further isdescribed ~~referred~~elsewhere toin asthis ~~the~~Annual ~~“Burleson North Acquisition~~Report;”

•· “Acquisition Co. Holdings” refers to ~~certain~~WHE ~~oil~~AcqCo ~~and~~Holdings, ~~gas working interests and the associated production in the Eagle Ford Shale acquired from Anadarko E&P Onshore~~ LLC ~~(“APC”)~~, ~~Admiral~~a Alimited ~~Holding~~liability ~~L.P.,~~company TEformed ~~Admiral~~to Aown ~~Holding~~a ~~L.P.~~portion ~~and~~of ~~Aurora~~our ~~C-I~~common ~~Holding~~stock ~~L.P.~~following ~~(collectively,~~the ~~“KKR”)~~Corporate ~~located in Burleson, Brazos, Lee, Milam, Robertson and Washington Counties, Texas~~Reorganization;

•· “~~NGP~~North Louisiana Acreage” refers to ~~Natural~~acreage ~~Gas~~in ~~Partners,~~North aLouisiana ~~family~~in ofand ~~private~~around ~~equity~~the ~~investment~~highly ~~funds~~prolific ~~organized~~Terryville toComplex, ~~make~~which ~~direct~~was ~~equity~~historically ~~investments~~owned inand ~~the~~operated ~~energy~~by ~~industry~~WHR II, ~~including~~and where we primarily targeted the ~~funds~~overpressured ~~invested~~Cotton inValley ~~WHR~~play ~~II,~~until ~~Esquisto~~it ~~and~~was ~~Acquisition~~sold ~~Co.;~~in ~~and~~March 2018;

•· “~~Carlyle~~Eagle Ford Acreage” refers to ~~The~~our ~~Carlyle~~acreage ~~Group, L.P. and certain of its affiliates, which indirectly own an interest~~ in ~~certain~~the ~~gross~~northern ~~revenues~~area of ~~NGP~~the ~~Energy~~Eagle ~~Capital~~Ford ~~management,~~Shale L.L.C., (“NGP ECM”), own a limited partner entitled to a percentage of carried interest from NGP XI US Holdings, L.P. (“NGP XI”), own a carried interest from NGP X US Holdings, L.P. (“NGP X US Holdings”) and ~~purchased~~in ~~all~~the ~~435,000~~Giddings ~~shares~~Austin ofChalk ~~our~~Trend ~~preferred~~in ~~stock,~~Southeast ~~par value $0.01 per share, designated as “Series A Perpetual Convertible Preferred Stock” (the “Preferred Stock”).~~Texas;

“Burleson North Assets” refers to certain producing properties and undeveloped acreage that Acquisition Co. acquired from Clayton Williams Energy, Inc. prior to or contemporaneously with the closing of our initial public offering, which acquisition is referred to as the “Burleson North Acquisition;”

“Acquisition” refers to certain oil and gas working interests and the associated production in the Eagle Ford Shale acquired from Anadarko E&P Onshore LLC (“APC”), Admiral A Holding L.P., TE Admiral A Holding L.P. and Aurora C-I Holding L.P. (collectively, “KKR”) located in Burleson, Brazos, Lee, Milam, Robertson and Washington Counties, Texas;

“NGP” refers to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the funds invested in WHR II, Esquisto and Acquisition Co.; and

“Carlyle” refers to The Carlyle Group, L.P. and certain of its affiliates, which indirectly own an interest in certain gross revenues of NGP Energy Capital management, L.L.C., (“NGP ECM”), own a limited partner entitled to a percentage of carried interest from NGP XI US Holdings, L.P. (“NGP XI”), own a carried interest from NGP X US Holdings, L.P. (“NGP X US Holdings”) and purchased all 435,000 shares of our preferred stock, par value $0.01 per share, designated as “Series A Perpetual Convertible Preferred Stock” (the “Preferred Stock”).

"First Merger" refers to the acquisition of WildHorse Development by Chesapeake pursuant to a merger between a wholly owned subsidiary of Chesapeake and WildHorse Development, with WildHorse Development surviving the merger as a direct, wholly owned subsidiary of Chesapeake; immediately following the effective time of the First Merger, the surviving corporation merged with and into Brazos Valley Longhorn, L.L.C., a wholly owned limited liability company subsidiary of Chesapeake, with Brazos Valley Longhorn, L.L.C. continuing as a wholly owned subsidiary of Chesapeake (together with the First Merger, the "Merger").

Table of Contents

FORWARD–LOOKING STATEMENTS

This Annual Report on Form 10-‑K (“Annual Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report, 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 Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’'s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Item 1A. Risk Factors” included in this Annual Report.

Forward-looking statements may include statements about:

•· ~~our~~the ~~business~~effects ~~strategy~~of the Merger;

•· our ~~estimated~~business ~~proved, probable and possible reserves~~strategy;

•· our ~~drilling~~estimated ~~prospects~~proved, ~~inventories,~~probable ~~projects~~ and ~~programs~~possible reserves;

•· our ~~ability~~drilling toprospects, ~~replace~~inventories, ~~the~~projects ~~reserves we produce through drilling~~ and ~~property acquisitions~~programs;

•· our ~~financial~~ability ~~strategy,~~to ~~liquidity~~replace ~~and~~the ~~capital~~reserves ~~required~~we ~~for~~produce ~~our~~through ~~development~~drilling ~~program~~and property acquisitions;

•· our ~~realized~~financial ~~oil~~strategy, ~~natural~~liquidity ~~gas~~ and ~~NGL~~capital ~~prices~~required for our development program;

•· ~~the timing and amount of~~ our ~~future~~realized ~~production of~~ oil, natural gas and ~~NGLs~~NGL prices;

•· the timing and amount of our ~~hedging~~future ~~strategy~~production of oil, natural gas and ~~results~~NGLs;

•· our ~~future~~hedging ~~drilling~~strategy ~~plans~~and results;

•· ~~competition~~our ~~and~~future ~~government~~drilling ~~regulations~~plans;

•· ~~our~~competition ~~ability to obtain permits~~ and ~~governmental~~government ~~approvals~~regulations;

•· ~~pending~~our ~~legal~~ability orto ~~environmental~~obtain ~~matters~~permits and governmental approvals;

•· ~~our~~pending ~~marketing~~legal ofor ~~oil,~~environmental ~~natural gas and NGLs~~matters;

•· our ~~leasehold~~marketing orof ~~business~~oil, ~~acquisitions~~natural gas and NGLs;

•· ~~costs~~our ofleasehold ~~developing~~or ~~our~~business ~~properties~~acquisitions;

•· ~~general~~costs ~~economic~~of ~~conditions~~developing our properties;

•· ~~credit~~general ~~markets~~economic conditions;

•· ~~uncertainty~~credit ~~regarding our future operating results~~markets;

~~• the consummation of the NLA Divestiture (as defined below); and~~ 8

• Table ~~plans,~~of ~~objectives, expectations and intentions contained in this Annual Report that are not historical.~~Contents

uncertainty regarding our future operating results; and

plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Item 1A. Risk Factors” included in this Annual Report.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development program. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

Table of Contents

PART I

ITEM 1. BUSINESS

Overview

~~WildHorse~~ We ~~Resource~~operate ~~Development~~in ~~Corporation~~one ~~(the~~reportable ~~“Company”)~~segment isengaged ain ~~Delaware~~the ~~corporation~~acquisition, ~~the~~exploration, ~~common~~development ~~stock~~and production of oil, ~~par~~natural ~~value~~gas ~~$0.01~~and ~~per~~NGL ~~share,~~resources. ofOur ~~which~~assets are ~~listed~~characterized onby ~~the~~concentrated ~~New~~acreage ~~York~~positions ~~Stock~~in ~~Exchange~~Southeast ~~(“NYSE”)~~Texas ~~under~~with ~~the~~multiple ~~symbol~~producing ~~“WRD~~stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return.” We ~~completed~~primarily ~~our~~operate ~~initial~~in ~~public~~Burleson, ~~offering~~Lee onand ~~December~~Washington ~~19,~~Counties ~~2016~~where we primarily target the Eagle Ford Shale and the Austin Chalk Trend.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in East Texas and North Louisiana with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. In East Texas, we primarily operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale. In North Louisiana, we have historically operated in and around the highly prolific Terryville Complex, where we primarily targeted the overpressured Cotton Valley play. Following the NLA Divestiture (as defined below), our operations will be focused exclusively in East Texas, though all references to our assets and operations in this Annual Report do not give effect to the NLA Divestiture unless otherwise specified.

As of December 31, 2017, we had assembled a total leasehold position of approximately 585,941 gross (477,153 net) acres across our expanding acreage, including approximately 460,000 gross (387,091 net) acres in the Eagle Ford and approximately 125,941 gross (90,062 net) acres in North Louisiana. We have identified a total of approximately 6,069 gross (3,739 net) drilling locations across our acreage. For the year ended December 31, 2017, approximately 80%, 14% and 5% of our revenues were attributable to oil, natural gas and NGLs, respectively.

Recent Developments

~~Acquisition~~ Merger ofwith ~~Lee~~Chesapeake ~~County~~Energy ~~Properties~~Corporation

On In ~~March~~February 12019, ~~2018,~~ we ~~through~~were ~~our~~acquired ~~wholly~~by ~~owned~~Chesapeake ~~subsidiary~~for ~~WHR~~approximately ~~Eagle~~717.3 ~~Ford~~million ~~LLC~~shares ~~(“WHR~~of ~~EF”),~~Chesapeake ~~closed~~common onstock ~~our~~and ~~acquisition~~$381.1 million in cash. Immediately following the completion of ~~producing~~the acquisition, WildHorse Development merged with and ~~non-producing~~into ~~properties~~Brazos inValley ~~Lee~~Longhorn, ~~County~~L.L.C., ~~Texas~~a ~~for~~newly ~~approximately~~formed ~~$18.6~~Delaware ~~million~~limited ~~from~~liability ancompany ~~undisclosed~~and ~~seller~~wholly owned subsidiary of Chesapeake. ~~The~~Following ~~properties~~the ~~consist~~completion of ~~approximately~~the ~~17,500~~Merger ~~net~~on ~~acres~~February ~~immediately~~1, ~~contiguous~~2019, toBrazos ~~our~~Valley ~~existing~~Longhorn, ~~Eagle~~L.L.C., ~~Ford~~as ~~properties~~successor ~~and~~to ~~one~~WildHorse ~~operated~~Development, ~~(four~~was ~~non-operated)~~a ~~producing~~wholly ~~horizontal~~owned ~~wells.~~subsidiary of Chesapeake.

Pending Divestiture of North Louisiana Assets

On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos Energy Holdings III, LLC (“Tanos”) for the sale of all of our producing and non-producing oil and natural gas properties (including Oakfield), primarily located in Webster, Claiborne, Lincoln, Jackson and Ouachita Parishes, Louisiana (“NLA Assets”) for a total sales price of approximately $217.0 million (the “NLA Divestiture”), subject to customary purchase price adjustments. The NLA Assets consist of all of our assets in our North Louisiana Acreage. In addition, WRD could receive contingent payments of up to $35.0 million based on the number of wells spud over the next four years. The effective date of the proposed sale is January 1, 2018, and we expect to close the transaction by the end of March 2018. The NLA Assets include approximately 90,000 net acres. As of December 31, 2017, estimated proved reserves from these properties were approximately 68.7 MMBoe, or 15% of our estimated year-end 2017 proved reserves. The sale includes approximately 620 gross (356.8 net) wells that produced approximately 7.2 MBoe/d (96% gas) for the year ended December 31, 2017. Our well count on these properties consisted of 473 gross (346.1 net) operated wells and 147 gross (10.7 net) non-operated wells.

The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the Purchase and Sale Agreement, Tanos paid WHR II a deposit of $21.7 million at signing, which amount will be applied to the sales price if the transaction closes.

The completion of the NLA Divestiture is subject to customary closing conditions. The parties may terminate the Purchase and Sale Agreement by mutual written consent or if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or approximately $43 million, or the transaction has not closed on or before April 30, 2018. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that we will sell the NLA Assets on the terms or timing described or at all. If the NLA Divestiture closes, we intend to use the net proceeds to repay amounts outstanding under our credit facility and for general corporate purposes. Please see Item 1A “Risk Factors—Risks Related to our Business—Our pending NLA Divestiture may not be consummated.”

Development of In-field Sand Mine

On February 12, 2018, we announced that Burleson Sand LLC, a wholly owned subsidiary had previously acquired surface and sand rights on approximately 727 acres in Burleson County, Texas to construct and operate an in-field sand mine. We expect that the

total capital expenditure for the full development of the sand mine will be approximately $65.0 - $75.0 million in 2018, which includes the property acquisition and third-party engineering studies.

North Louisiana Settlement

On February 1, 2018, we settled a dispute related to a possible area of mutual interest (“AMI”) associated with our North Louisiana properties with a third party. This settlement is referred to as the “North Louisiana Settlement.” See Note 21 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding the North Louisiana Settlement.

Tax Reform Legislation

On December 22, 2017, the United States ("U.S.") government enacted Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), which made significant changes to U.S. federal income tax law. We expect that certain aspects of these changes will positively impact our future after-tax earnings primarily due to the lower federal statutory income tax rate. We were required to recognize the effect of this rate change on our deferred tax assets and liabilities in 2017, the period the tax rate change was enacted. Key aspects of the Tax Act include, but are not limited to, (i) establishing a flat corporate income tax rate of 21% to replace previous rates that ranged from 15% to 35% and eliminating the corporate alternative minimum tax (“AMT”); (ii) reducing the maximum deduction for net operating loss (“NOL”) carryforwards arising in tax years beginning after December 31, 2017 to 80% of the taxpayer’s taxable income, allowing any NOLs generated in tax years beginning after December 31, 2017 to be carried forward indefinitely, and generally repealing carrybacks; (iii) limiting the deduction for net interest expense; (iv) allowing businesses to immediately expense the cost of new investments in certain qualified depreciable assets acquired after September 27, 2017 (with a phase-down of such expensing starting in 2023); and (v) repealing the Section 199 domestic production deduction beginning in 2018.; The Tax Act did not include any changes with respect to the current option to expense Intangible Drilling Costs or the Percentage Depletion deduction. See Note 17 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our income taxes.

2017 Developments

APC/KKR Acquisition

On May 10, 2017, we, through our wholly owned subsidiary, WHR EF, entered into a Purchase and Sale Agreement (the “First Acquisition Agreement”) by and among WHR EF, as purchaser, and Anadarko E&P Onshore LLC (“APC”), Admiral A Holding L.P., TE Admiral A Holding L.P. and Aurora C-I Holding L.P. (collectively, “KKR” and, together with APC, the “First Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson and Washington Counties, Texas (the “Purchase”). Also on May 10, 2017, WHR EF entered into a Purchase and Sale Agreement (together, with the First Acquisition Agreement, the “Acquisition Agreements”), by and among WHR EF, as purchaser, and APC and Anadarko Energy Services Company (together, with APC, the “APC Subs” and together with the First Sellers, the “Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson, and Washington Counties, Texas (together, with the Purchase, the “Acquisition”).

Pursuant to the Acquisition Agreements, on June 30, 2017, we completed the acquisition of approximately 111,000 acres and the associated production therefrom. The aggregate purchase price for the assets, as described in the Acquisition Agreements, consisted of an aggregate of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR. The common stock portion of the purchase price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed, on May 10, 2017, by and among us and KKR.

Preferred Stock Issuance

We partially funded the Acquisition through the issuance of 435,000 shares of Preferred Stock in exchange for $435.0 million on June 30, 2017, pursuant to a Preferred Stock Purchase Agreement (the “Preferred Stock Purchase Agreement”), by and among us and CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), an affiliate of The Carlyle Group, L.P. See Note 10 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our preferred stock issuance.

Amendments to Credit Agreement

On ~~June 30~~February 1, ~~2017~~2019, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto entered into a ~~second~~Sixth ~~amendment~~Amendment (the “~~Second~~Sixth Amendment”) to the Credit Agreement dated as of December 19, 2016, among the Company, the Administrative Agent and the other agents and lenders party thereto (as amended, the “Credit Agreement”). Among other things, the Sixth Amendment (i) amended the merger covenant and the definition of change of control to permit the Merger and (ii) permits borrowings under the Credit Agreement to be used to redeem or repurchase the $700 million aggregate principal amount of 6.875% Senior Notes due 2025 issued by WildHorse (the “2025 Senior Notes”) so long as certain conditions are met.

11 On October 15, 2018, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into a Fifth Amendment (the “Fifth Amendment”) to the Credit Agreement. The Fifth Amendment, among other things, modified the Credit Agreement to increase the borrowing base from $1.05 billion to $1.30 billion.

~~The~~ On ~~Second~~March ~~Amendment~~23, ~~among other things~~2018, ~~modified~~ the ~~Credit Agreement to (a) permit the~~ Company ~~to enter into the Acquisition~~, ~~and~~each ~~the Preferred Stock Purchase Agreement, and perform its obligations under and in connection therewith, including the issuance~~ of the ~~Preferred Stock, (b) increase the~~ Company’s ~~borrowing~~wholly ~~base~~owned ~~and~~subsidiaries ~~elected~~(each ~~commitment~~as ~~amount~~a ~~from $450 million to $650 million~~guarantor), ~~(c) increase~~ the ~~annual~~Administrative ~~cap on certain restricted payments from $50 million to $75 million~~Agent, and ~~(d) modify~~ the ~~definition~~lenders ofparty ~~net~~thereto ~~debt~~entered sointo ~~that~~a ~~certain~~Fourth ~~contingent~~Amendment ~~obligations,~~(the ~~accounts~~“Fourth ~~payable,~~Amendment”) ~~obligations~~ to ~~make~~the ~~deliveries~~Credit inAgreement. The ~~respect~~Fourth ~~of advance payments~~Amendment, ~~take~~among orother ~~pay obligations~~things, ~~disqualified~~modified ~~capital~~the ~~stock~~Credit ~~and~~Agreement ~~obligations~~to inincrease ~~respect~~the ofborrowing ~~production~~base ~~payments are excluded~~ from ~~net~~$875.0 ~~debt~~million ~~for~~to ~~purposes~~$1.05 ~~of the Company’s leverage covenant~~billion.

On WildHorse ~~October~~Senior 4, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into a Third Amendment (the “Third Amendment”) to the Credit Agreement. The Third Amendment, among other things, modified the Credit Agreement to (i) increase the aggregate maximum credit amount to $2.0 billion from $1.0 billion, (ii) increase the borrowing base from $612.5 million to $875.0 million and (iii) add additional lenders.Notes

As a result of the completion of the Merger, Brazos Valley Longhorn, L.L.C. assumed the obligations under the 2025 Senior Notes ~~Offering~~and Brazos Valley Longhorn Finance Corp. (“BVL Finance Corp.”), a wholly owned subsidiary of Brazos Valley Longhorn, L.L.C. became a co-issuer of the 2025 Senior Notes.

On The ~~February~~2025 1,Senior ~~2017,~~Notes weare ~~completed~~the asenior ~~private~~unsecured ~~placement~~obligations of ~~$350.0~~Brazos ~~million~~Valley ~~aggregate~~Longhorn, ~~principal~~L.L.C., ~~amount~~BVL ofFinance 6Corp.~~875%~~ ~~senior~~and ~~unsecured notes due 2025 (~~the ~~“2025~~other ~~Senior~~BVL ~~Notes”)~~Guarantors. The 2025 Senior Notes ~~were~~will ~~issued~~not atbe aobligations ~~price~~ of ~~99.244%~~Chesapeake ofor ~~par~~any ~~and resulted in net proceeds~~ of ~~approximately~~its ~~$338.6~~subsidiaries ~~million. In~~other ~~addition,~~than onBrazos ~~September~~Valley 19Longhorn, ~~2017~~L.L.C., weBVL ~~completed~~Finance ~~another private placement of $150~~Corp.0 ~~million~~and ~~aggregate~~the ~~principal~~other ~~amount~~BVL ofGuarantors. ~~the~~The 2025 Senior Notes ~~issued~~will atrank ~~98.26%~~equally ~~of par, which resulted~~ in ~~net~~right ~~proceeds~~ of ~~approximately~~payment ~~$144.7~~with ~~million.~~all ~~The~~other ~~notes~~senior ~~issued~~unsecured inindebtedness ~~September 2017 are treated as a single class~~ of ~~debt~~Brazos ~~securities~~Valley ~~with~~Longhorn, ~~the 2025 Senior Notes issued in February 2017~~L. ~~The 2025 Senior Notes will mature on February 1~~L.C., ~~2025~~BVL ~~and~~Finance ~~interest is payable on February 1 and August 1 of each year~~Corp. ~~The~~ ~~2025 Senior Notes are fully~~ and ~~unconditionally~~the ~~guaranteed~~other onBVL aGuarantors, ~~joint~~ and ~~several~~will ~~basis~~be byeffectively ~~all~~subordinated ~~of our existing and certain future subsidiaries (subject~~ to ~~customary~~Brazos ~~release~~Valley ~~provisions). We~~Longhorn ~~have no material assets or operations that are independent of our existing subsidiaries~~L. ~~There~~L.C.’s, ~~are~~BVL noFinance ~~restrictions on our ability to obtain funds from our subsidiaries through dividends or loans~~Corp. ~~The~~’s ~~net~~and ~~proceeds from each of~~ the ~~offerings~~other ofBVL ~~the~~Guarantors’ ~~2025~~senior ~~Senior~~secured ~~Notes~~indebtedness, ~~were~~including ~~used~~their toobligations ~~repay borrowings outstanding under our revolving credit facility and for general corporate purposes.~~

Pursuant to registration rights agreements entered into in connection with the offerings of the 2025 Senior Notes, we agreed to file a registration statement with the Securities and Exchange Commission (the “SEC”) so that holders of the 2025 Senior Notes could exchange the unregistered 2025 Senior Notes for registered notes with substantially identical terms. In addition, we agreed to exchange the unregistered guarantees related to the 2025 Senior Notes for registered guarantees with substantially identical terms. On November 20, 2017, substantially all of the outstanding 2025 Senior Notes were exchanged for an equal principal amount of registered 6.875% senior notes due 2025 pursuant to an effective registration statement on Form S-4. 10

We Table ~~may redeem all or any part~~ of the 2025 Senior Notes at a “make-whole” redemption price, plus accrued and unpaid interest, at any time before February 1, 2020. We may also redeem up to 35% of the aggregate principal amount of the 2025 Senior Notes prior to February 1, 2020 in an amount not greater than the net cash proceeds from one or more equity offerings at a redemption price of 106.875% of the principal amount of the 2025 Senior Notes, plus accrued and unpaid interest.Contents

~~Exercise~~under ofWildHorse ~~Underwriters~~Development’s ~~Over-allotment~~revolving ~~Option~~credit facility, to the extent of the value of the collateral securing such indebtedness.

On April ~~January~~2018 ~~17,~~Issuance ~~2017, we issued and sold 2,297,100 shares~~ of ~~our~~Additional ~~common~~2025 ~~stock~~Senior at an offering price of $15.00 per share pursuant to the partial exercise of the underwriters’ over-allotment option associated with our initial public offering (the “Option Exercise”). We received net proceeds of $32.6 million from the Option Exercise, all of which was used to repay outstanding borrowings under our revolving credit facility.Notes

On April 20, 2018, we completed a private placement of an additional $200.0 million in aggregate principal amount of our 2025 Senior Notes (the “April Notes”). The April Notes are treated as a single class of debt securities with the other outstanding 2025 Senior Notes. The April Notes were issued at a price of 102% of par. This issuance resulted in net proceeds of approximately $201.0 million, after deducting the initial purchaser’s discount and commissions and estimated offering expenses and excluding accrued interest. We used the net proceeds to repay borrowings outstanding under our revolving credit facility and for general corporate purposes. On September 24, 2018, all of the then-outstanding 2025 Senior Notes, including the April Notes, were exchanged for an equal principal amount of registered 6.875% senior notes due 2025 pursuant to an effective registration statement on Form S-4.

North Louisiana Divestiture

On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos for the sale of all of our producing and non-producing oil and natural gas properties, including Oakfield, primarily located in Webster, Claiborne, Lincoln, Jackson and Ouachita Parishes, Louisiana (“NLA Assets”). On March 29, 2018, we completed the sale of the NLA Assets for a preliminary sales price of approximately $206.4 million. Including final purchase price adjustments of $4.8 million, the final sales price of $211.2 million has been fully collected at December 31, 2018. The Company has paid $3.8 million in expenses related to the divestiture and has received $0.4 million in contingent payments from Tanos.

In addition, we may receive contingent payments of up to $35.0 million based on the number of wells spud on such properties over the next three years. We have made an accounting policy election to record the contingent consideration when it is deemed to be realizable. In October 2018, we received contingent payments of $0.4 million from Tanos.

Our NLA Assets were deemed to meet held-for-sale accounting criteria as of February 12, 2018, at which point we ceased recording depletion and depreciation. Based on the Company’s sale proceeds after preliminary customary purchase price adjustments, we recorded an impairment charge of $214.3 million during the first quarter of 2018 to adjust the carrying amount of the disposal group to its estimated fair value less costs to sell. See “Note 3—Acquisitions and Divestitures” of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.

Development of In-field Sand Mine

On February 12, 2018, we announced that Burleson Sand LLC, a wholly owned subsidiary, had previously acquired surface and sand rights on approximately 727 acres in Burleson County, Texas to construct and operate an in-field sand mine. Total capital expenditure for 2018 for the development of the sand mine was approximately $66.1 million. The sand mine commenced operations in February 2019.

Our Properties

Eagle Ford Acreage

~~The~~ We Eagle Ford Shale is one of the most active unconventional shale trends in North America. According to weekly rig count metrics published by Baker Hughes, the Eagle Ford Shale has consistently been one of the most active basins in the United States since 2011 and currently ~~has~~target ~~the~~a ~~second~~portion ~~highest rig count~~ of ~~all major U.S. basins. The Eagle Ford Shale trends across Texas from~~ the ~~Mexican border north into East Texas and is roughly 50 miles wide and 400 miles long. The~~ Eagle Ford Shale ~~rests between the Austin Chalk and the Buda Lime~~ at adepths ~~depth~~between ~~of approximately 4~~6,000 tofeet 14and 13,000 feet. Asprimarily ofin ~~December 31~~Burleson, ~~2017~~Lee, ~~there~~Brazos ~~were~~and ~~approximately~~Washington 36Counties,~~000~~ ~~producing wells in the Eagle Ford with an average production of 2~~Texas.1 ~~MMBoe/d in December 2017.~~

We ~~currently~~have ~~target~~completed amultiple ~~portion~~bolt-on ofacquisitions ~~the Eagle Ford Shale at depths between 6,000 feet~~ and ~~13,000 feet primarily~~ in-fill ~~Burleson,~~leases ~~Lee,~~to ~~Brazos~~build ~~and~~our ~~Washington~~current ~~Counties,~~position ~~Texas.~~in ~~This portion of~~ the Eagle Ford Shale ~~averages 125 feet in thickness~~ and ~~contains~~have ~~70%~~identified ~~carbonate. We~~a ~~believe~~substantial ~~that~~inventory ~~the elevated carbonate percentages are in large part responsible for the brittleness~~ of ~~the~~drilling ~~Eagle~~locations ~~Ford~~across ~~and~~Burleson, ~~successful completions which exhibit high productivity when fractured. The overall clay content of the Eagle Ford increases regionally as it continues progressively northeast into~~ Brazos, ~~Grimes~~Lee, Robertson and ~~Madison~~Washington Counties~~, Texas~~.

12 As of December 31, 2018, our Eagle Ford Acreage included approximately 419,293 net acres.

We are focused on maximizing returns and expect operational efficiencies to extend beyond our existing drilling inventory to additional horizons. In addition, our acreage has been extensively developed for more than 40 years through the development of the Giddings Austin Chalk Trend. Based on analysis and interpretation of well results and other geologic and engineering data, we believe our acreage is also prospective for the Georgetown, Buda, Woodbine and Pecan Gap formations. Historical operators in the Giddings Austin Chalk Trend have experienced drilling and production success during our industry’s pre-multistage frac era (1970s-2000s). Future development results achieved by us and offset operators may allow us to expand our existing location inventory throughout our leasehold. 11

We Table ~~entered the Eagle Ford with the goal~~ of redeveloping the area with horizontal drilling and modern completion techniques. Since that time, we have completed multiple bolt-on acquisitions and in-fill leases to build our current position in the Eagle Ford. We have identified a substantial inventory of 4,675 gross drilling locations within our Eagle Ford Acreage across Burleson, Brazos, Lee, Robertson and Washington Counties. The wells in our Eagle Ford Acreage have shown a strong track record of increasing EURs and a decreasing trend in drilling and completion capital costs. Contents

As of December 31, 2017, our Eagle Ford position included approximately 387,091 net acres. Also, as of December 31, 2017, approximately 69% of our Eagle Ford Acreage was held by production, with an average working interest of 84%, and, as of December 31, 2017, 22% of our 385.6 MMBoe of proved reserves were developed, 88% of which were liquids. Since January 2014, we and our previous owner have drilled and completed 125 wells, acquired 878 wells and participated in 26 wells resulting in total net production of approximately 23.5 MBoe/d (76% oil, 10% natural gas and 14% NGLs), including non-operated production.

North Louisiana Acreage

Within our North Louisiana Acreage we primarily target the overpressured Cotton Valley formation in the Terryville Complex. The Cotton Valley formation, extending across East Texas, North Louisiana and Southern Arkansas, has been under development since the 1930s and is characterized by thick, multi-zone natural gas and oil reservoirs with well-known geologic characteristics and long-lived, predictable production profiles. In 2005, operators started redeveloping the Cotton Valley using horizontal drilling and advanced hydraulic fracturing techniques. Some large, analogous redevelopment projects in the Terryville Complex include the Terryville play in Lincoln Parish, the Nan-Su-Gail area in Freestone County, East Texas and the Carthage Complex in Panola County, East Texas.

Our North Louisiana Acreage spans across the Webster, Claiborne, Bienville, Lincoln, Jackson and Ouachita Parishes, focusing on the Bear Creek field and the RCT and Weyerhaeuser Areas, where we are targeting overpressured Cotton Valley opportunities in multiple zones. We believe the Terryville Complex, which has been producing since 1954, is one of North America’s most prolific liquids rich natural gas plays, characterized by high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields, long reserve life, multiple stacked pay zones, available infrastructure and a large number of service providers. The RCT Area is a direct offset of the Terryville Field and is part of the same Terryville Complex trend. Following the NLA Divestiture, we do not expect to continue operating in this area.

As of December 31, 2017, our North Louisiana Acreage included approximately 90,000 net acres. Also, as of December 31, 2017, 58% of our acreage was then held by production, with an average working interest of 72%, and 41% of our 68.7 MMBoe of proved reserves were developed, 97% of which were natural gas. Since the inception of our predecessor, we had drilled and completed 18 wells, acquired 597 wells and participated in 5 non-operated wells resulting in a total 2017 net production of approximately 7.2 MBoe/d (2% oil, 96% natural gas and 2% NGLs), including non-operated production.

On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos for the sale of the NLA Assets for a total sales price of approximately $217.0 million before customary adjustments. The NLA Divestiture is expected to close by the end of March 2018.

Reserve Summary

Our estimated proved reserves of were prepared by our internal reserve engineers and audited by Cawley, Gillespie and Associates, Inc. (“Cawley”), our independent reserve engineers. As of December 31, 2017, we had 454.3 MMBoe of estimated proved reserves. As of this date, our proved reserves were 75% oil and NGLs and 25% natural gas. The following table provides summary information regarding our estimated proved reserves data and our average net daily production by area based on our reserve reports as of December 31, 2017:

Region	Proved Total (MMBoe) (1)		% Oil & Liquids			% Developed			Average Net Daily Production (MBoe/d) (2)
Eagle Ford		385.6		87.8	%		22.4	%		36.0
North Louisiana		68.7		2.3	%		41.0	%		9.9
Total		454.3								45.9

(1) Our estimated net proved reserves as of December 31, 2017 were determined using average first-day-of-the month prices for the prior 12 months in accordance with SEC rules. For oil and NGL volumes, the average WTI posted price of $51.34 per barrel as of December 31, 2017 was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.976 per MMBtu as of December 31, 2017 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of our properties are $49.80 per barrel of oil, $16.27 per barrel of NGL and $2.849 per Mcf of natural gas as of December 31, 2017.

(2) Represents average daily net production for the three months ended December 31, 2017.

Business Strategies

To achieve our primary objective of delivering shareholder value, we intend to execute the following business strategies:

Grow production, reserves and cash flow through the development of our extensive drilling inventory. We believe our extensive inventory of drilling locations in the Eagle Ford and Austin Chalk formations following the consummation of the NLA Divestiture, combined with our operating expertise, will enable us to continue to deliver accretive production, reserves and cash flow growth and create shareholder value. We have identified a total of approximately 4,675 gross (3,097 net) drilling locations across our Eagle Ford acreage, with further upside potential given the multiple stacked pay zones across much of our acreage in addition to potential downspacing. We will continue to closely monitor offset operators as they delineate adjoining acreage and zones, providing us further data to optimize our development plan over time. We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs will allow us to efficiently develop our core areas and to allocate capital to maximize the value of our resource base.

Maximize returns by optimizing drilling and completion techniques and improving operating efficiencies. Our management is intently focused on driving efficiencies in the development of our resource base by maximizing our hydrocarbon recovery per well while minimizing our drilling, completion and operating costs. To achieve these efficiencies, we focus on:

• minimizing the costs of drilling and completing horizontal wells through our knowledge of the target formations, pad drilling and reduced drilling times;

• maximizing EURs through advanced drilling, completion and production techniques, such as by optimizing lateral lengths, the number of hydraulic fracturing stages and perforation intervals, water and proppant volumes, fluid chemistry, choke management and the strategic use of artificial lift techniques;

• maximizing our cash flows by targeting specific areas within our balanced portfolio of oil and natural gas drilling opportunities based on the existing commodity price environment; and

• minimizing operating costs through our experience in efficient well management.

In our Eagle Ford Acreage, we have reduced our drilling and completion costs per completed lateral foot by approximately 66%, from $2,958 per foot for our wells completed using Generation 1 hydraulic fracturing design to approximately $1,000 per foot for our wells completed using Generation 3 hydraulic fracturing design. Additionally, as we have transitioned our completion techniques in our Eagle Ford Acreage from Generation 1 to Generation 3 hydraulic fracturing designs, we have increased EURs by approximately 29% per completed lateral foot from an average of 76 Boe per foot to 99 Boe per foot. Our drilling and completion cost reductions coupled with our completion design improvements are generating enhanced single-well recoveries and attractive returns in the current commodity environment, and we believe we can further optimize our results through these and other technologies across our acreage position.

Capture additional horizontal development opportunities on current acreage. Our existing asset base provides numerous opportunities for our management team to create shareholder value by increasing our inventory beyond our currently identified drilling locations. Based on results from our horizontal drilling program and those of offset operators, including offset production trends, mud

logs, 2-D and 3-D seismic, well data analysis and geologic trend mapping, we believe our acreage has multiple productive zones providing significant upside potential to our current inventory of identified drilling locations. We have excluded from our identified drilling locations potential opportunities associated with downspacing and with additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County and (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage.

Utilize extensive acquisition and technical expertise to grow our core acreage position. We have a demonstrated track record of identifying and cost effectively acquiring attractive resource development opportunities, including the recent acquisition and development highlighted under “—Recent Developments.” To date, our management and technical teams have completed numerous acquisitions, and we expect to continue to identify and opportunistically lease or acquire additional acreage and producing assets to add to our multi-year drilling inventory. We have followed a geologically driven strategy to establish large, contiguous leasehold positions in our Eagle Ford Acreage and strategically expand those positions through bolt-on acquisitions over time. We believe our Eagle Ford Acreage creates a platform upon which we can add value by acquiring additional acreage and incremental drilling locations near our current acreage. In this regard, NGP and its affiliates are not limited in their ability to compete with us for future acquisitions, and we do not expect to enter into any agreements or arrangement to apportion future opportunities between us, on the one hand, and NGP and its affiliates, on the other hand.

Maintain a disciplined, growth-oriented financial strategy. We prudently manage our liquidity and leverage levels by monitoring cash flow, capital spending and debt capacity. We had approximately $588.6 million of available borrowing capacity under our revolving credit facility as of December 31, 2017. We intend to fund our growth primarily with internally generated cash flows and borrowings under our revolving credit facility while maintaining ample liquidity and access to the capital markets, which we believe will allow us to accelerate our development program and maximize the present value of our resource potential. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations, enabling us to protect cash flows and maintain liquidity to fund our capital program and investment opportunities.

Business Strengths

We believe that the following strengths will allow us to successfully execute our business strategies.

Extensive, contiguous acreage position in one of North America’s leading oil and gas plays. We own an extensive and substantially contiguous acreage position targeting one of the premier plays in North America, the Eagle Ford Shale formation. As of December 31, 2017, we had approximately 585,941 gross (477,153 net) acres and we had 454.3 MMBoe of proved reserves (62% oil, 25% natural gas and 13% NGLs) across our acreage. In February 2018, WHR II entered into a Purchase and Sale Agreement for the sale of the NLA Assets. We believe that our recent well results demonstrate that many of the wells on our high-quality acreage are capable of producing single-well rates of return that are competitive with many of the top performing basins in the United States. Furthermore, the location of our acreage provides us with lower operating costs and better realized pricing than other companies operating in different basins around the country due to our acreage’s proximity to the end markets for oil, natural gas and NGLs.

Multi-year inventory of drilling opportunities across our acreage position. We have identified approximately 4,675 gross (3,097 net) drilling locations across our Eagle Ford Acreage, providing us with approximately 44.5 years gross (29.5 years net) of drilling inventory based on our 2018 drilling program. On our Eagle Ford Acreage, our horizontal drilling locations target the Eagle Ford Shale in Burleson and Lee Counties and the Austin Chalk in Washington County. In addition, we believe our acreage position includes a number of additional areas and zones that are prospective for hydrocarbons. For example, we believe we may identify additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County and (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage. Furthermore, we also believe that we may add horizontal drilling locations across our entire acreage position through downspacing.

Significant operational control over our assets with low-cost operations. As the operator of a majority of our acreage, we have significant operational control over our assets. We seek to allocate capital among projects in a manner that optimizes both costs and returns, which we believe results in a highly efficient drilling program. We believe maintaining operational control will enable us to enhance returns by implementing more efficient and cost-effective operating practices, such as through the selection of economic drilling locations, the opportunistic timing of development and ongoing improvement of drilling, completion and operating techniques. Our contiguous acreage blocks, and our practice and history of exchanging and consolidating acreage with adjacent operators, allow us to increase our working interest in our wells and provide flexibility to adjust our drilling and completion techniques, such as pad drilling and the length of our horizontal laterals, in order to optimize our well results, drilling costs and returns.

Management and technical teams with substantial technical and operational expertise. Our management and technical teams have significant industry experience and a long history of collaboration in the identification, execution and integration of acquisitions and in cost-efficient management of profitable, large-scale drilling programs. Additionally, we have substantial expertise in advanced drilling and completion technologies and decades of collective experience in operating in the Eagle Ford. Mr. Graham, our Chief Executive Officer, and Mr. Bahr, our President, co-founded one of the predecessors to, and Mr. Graham served as Chief Executive

Officer of, Memorial Resource Development Corp. (“MRD”), which pioneered the horizontal redevelopment of the Terryville Complex, participating in the drilling of MRD’s initial 55 horizontal wells. Further, our management team has a proven track record of returning value to shareholders and a significant economic interest in us directly and through its equity interests in each of WildHorse Holdings and Esquisto Holdings. We believe our management team is motivated to use its experience in identifying and creating value across our acreage and drilling highly productive wells to deliver attractive returns, maintain safe and reliable operations and create shareholder value.

Geographically advantaged assets with significant midstream infrastructure to service our production. Our acreage position is in close proximity to end markets for oil, natural gas and NGLs, providing us with a regional price advantage. For example, low oil and natural gas basis differentials along the Gulf Coast represent a competitive advantage when compared to other plays, such as the Bakken, Marcellus, Utica, Permian and DJ. Recently developed and low-cost legacy infrastructure is in place across significant portions of our acreage to support our development program. In addition, we own and operate a large portion of our necessary midstream infrastructure which provides us with improved netbacks. On our Eagle Ford Acreage, we own substantial fresh water supply and storage, developed saltwater disposal wells and are in the process of developing an in-field sand mine. Our midstream infrastructure allows us to realize lower operating costs and provides us with increased flexibility in our development program. In addition, while not currently contemplated, our midstream infrastructure could prove to be a future source of additional capital if monetized at an attractive valuation.

Our Principal Stockholders

WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP XI US Holdings, L.P. (“NGP XI”), and management directly own 21.0%, 38.3%, 2.5%, 8.9% and 2.6%, respectively, of our common stock. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings are controlled by NGP. Carlyle beneficially owned 435,000 shares of Preferred Stock, which, based on the conversion rate as of December 31, 2017, represented approximately 24.3% of our common stock on an as converted basis. NGP and its affiliates (through WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and NGP XI) beneficially own approximately 70.7% of our common stock. Based solely on the Schedule 13G filed on February 5, 2018 with the SEC by KKR, KKR owned approximately 5.5% of our common stock as of June 30, 2017.

Reserve Data

Preparation of Reserve Estimates

Our reserve estimates as of December 31, ~~2017~~2018 included in this Annual Report are based on evaluations prepared by ~~our~~Cawley, ~~management~~Gillespie ~~and~~& ~~audited~~Associates, byInc. ~~the~~(“CG&A”), ~~independent~~a ~~petroleum~~third-party engineering firm ~~of Cawley~~ in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. ~~Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering similar resources.~~

Proved reserves are reserves 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 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 estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. If deterministic methods are used, the term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. If probabilistic methods are used, there should at least be a 90% probability that the quantities actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. ~~Our~~Reserve ~~independent reserve~~ engineers use this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and EURs per well are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy).

Internal Controls

We maintain adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. Our internal staff of petroleum engineers and geoscience professionals ~~works~~work closely with ~~our~~CG&A ~~independent~~ reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to ~~our independent reserve engineers in their reserve auditing process~~CG&A. Periodically, our technical team meets with ~~the~~CG&A ~~independent~~ reserve engineers to review properties and discuss methods and assumptions used ~~by us~~ to prepare reserve estimates.

Reserve engineering is and must be recognized as 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, natural gas and NGLs that are ultimately recovered. Estimates of economically recoverable oil, natural gas and NGLs 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. Please read “Item 1A. Risk Factors” appearing elsewhere in this Annual Report.

16 For the year ended December 31, 2018, our reserve estimates and related reports were prepared by CG&A and reviewed by our Corporate Reserves Department and approved by our Director – Corporate Reserves who is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for coordinating any reserves work conducted by third-party engineering firms. Her qualifications include the following:

~~and~~· ofOver ~~engineering~~15 ~~and~~years ~~geological interpretation. As a result, the estimates~~ of ~~different~~practical ~~engineers~~experience ~~often~~in ~~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, ~~natural gas~~ and ~~NGLs that are ultimately recovered. Estimates of economically recoverable oil, natural~~ gas ~~and NGLs and of future net revenues are based on a number of variables and assumptions~~industry, ~~all~~with of12 ~~which~~years ~~may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Item 1A. Risk Factors” appearing elsewhere~~ in ~~this~~reservoir ~~Annual Report.~~engineering;

~~For~~· ~~the~~Bachelor year ended December 31, 2017, our reserve estimates and related reports were prepared internally and reviewed and approved by Jason Pearce. Mr. Pearce is our Senior Vice President, Reserves and has approximately 19 years of ~~experience~~Science indegree oil and gas operations, reservoir engineering, reserve management, unconventional reservoir characterization and strategic planning. Cawley performed audits of our internally prepared reserves estimates on our proved reserves as of December 31, 2017. Our proved reserves are, in ~~the~~Geology ~~aggregate, reasonable~~ and ~~within~~Environmental ~~the established audit tolerance guidelines of 10%. The report of Cawley contains further discussion of the reserves estimates and its audit procedure.~~Sciences;

~~Cawley~~· ~~was~~Master’s ~~founded~~Degree in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within Cawley, the technical person primarily responsible for preparing the estimates shown herein with respect to WHR II and Esquisto, was Todd Brooker. Prior to joining Cawley, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker has been an employee of Cawley since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum ~~Engineering,~~ and isNatural aGas ~~registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.~~Engineering;

Table of Contents

Executive Master of Business Administration; and

Member in good standing of the Society of Petroleum Engineers.

CG&A was founded in 1961 and performs petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CG&A, the technical person primarily responsible for preparing the estimates shown herein, was Todd Brooker. Mr. Brooker has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in North America and worldwide, including oil and gas shale plays. Mr. Brooker graduated Magna Cum Laude from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering, and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

Estimated Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves as of December 31, ~~2017~~2018, based on our audited reserve report.

	Oil (MBbls)			Natural Gas (MMcf)			NGLs (MBbls)		Total (MBoe)
	Oil		Natural Gas	NGLs		Total
Estimated Proved Reserves
	(MBbls)		(MMcf)	(MBbls)		(MBoe)
Total Proved Developed		65,023			221,517			12,553		114,495
Estimated Proved Reserves
Total Proved Undeveloped		217,775			462,291			44,996		339,820
Total Proved Developed	66,398		88,936	14,135		95,356
Total Proved Reserves		282,798			683,808			57,549		454,315
Total Proved Undeveloped	218,868		289,237	43,620		310,694
Total Proved Reserves	285,266		378,173	57,755		406,050

Development of Proved Undeveloped Reserves

As of December 31, ~~2017~~2018, we had ~~339~~310.87 MMBoe of proved undeveloped reserves consisting of ~~217~~218.89 MMBbls of oil, ~~462~~289.32 ~~MMcf~~Bcf of natural gas and 4543.06 ~~MBbls~~MMBbls of NGLs, compared to ~~105~~339.28 MMBoe of proved undeveloped reserves at December 31, ~~2016~~2017, consisting of 68217.38 MMbbls of oil, ~~179~~462.23 ~~MMcf~~Bcf of natural gas and 745.10 ~~MBbls~~MMBbls of NGLs. None of our PUDs as of December 31, ~~2017~~2018 are scheduled to be developed on a date more than five years from the date the reserves were initially booked to PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Our PUDs changed during ~~2017~~2018 as a result of:

•· ~~upward~~downward performance and price revisions of 7369.41 MMBoe;

•· acquisitions of 490.5 MMBoe;

•· ~~reserve~~divestures ~~additions~~ of ~~116~~40.80 MMBoe; ~~and~~

•· ~~transfers~~reserve toadditions ~~proved developed producing~~ of 586.08 MMBoe; and

We· ~~estimate~~transfers ~~that we incurred $91.9 million of costs~~ to ~~convert~~ proved ~~undeveloped reserves from 13 locations into proved~~ developed ~~reserves~~producing inof ~~2017~~7.3 MMBoe

~~Reconciliation~~ We ofestimate ~~PV-10~~that we incurred $80.9 million to ~~Standardized~~convert ~~Measure~~proved undeveloped reserves from 13 locations into proved developed reserves in 2018.

PV-10 is a non-GAAP financial measure and differs from the Standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to 13

17 Table of Contents

investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized measure of discounted future net cash flows. Our PV-10 measure and the Standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV-10 of our proved reserves to the Standardized measure of discounted future net cash flows at December 31, 2017, 2016 and 2015:

	At December 31,
	2017			2016			2015
	(in thousands)
PV-10	$	3,539,337		$	749,988		$	457,861
Less: present value of future income taxes discounted at 10%		(695,432	)		(206,947	)		(5,931	)
Standardized measure	$	2,843,905		$	543,041		$	451,930

Reserves Sensitivity

Historically, commodity prices have been extremely volatile and we expect this volatility to continue for the foreseeable future. For example, for the three years ended December 31, 2017, the NYMEX-WTI oil spot price ranged from a high of $61.36 per Bbl to a low of $26.19 per Bbl, while the NYMEX-Henry Hub natural gas spot price ranged from a high of $3.80 per MMBtu to a low of $1.49 per MMBtu. For the year ended December 31, 2017, the West Texas Intermediate posted price ranged from a high of $60.46 per Bbl on December 29, 2017 to a low of $42.48 per Bbl on June 21, 2017 and the Henry Hub spot market price ranged from a high of $3.71 per MMBtu on January 2, 2017 to a low of $2.44 per MMBtu on February 27, 2017. The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

While it is difficult to quantify the impact of the continuation of low commodity prices on our estimated proved reserves with any degree of certainty because of the various components and assumptions used in the process of estimating reserves, the following sensitivity table is provided to illustrate the estimated impact of pricing changes on our estimated proved reserve volumes and Standardized measure. In addition to different price assumptions, the sensitivity cases below include assumed capital and operating expense changes we would expect to realize under each scenario. Sensitivity cases are used to demonstrate the impact that a change in price and cost environment may have on reserves volumes and Standardized measure. There is no assurance that these prices or cost savings will actually be achieved.

	Base Case (1)			Case A (2)			Case B (2)
Crude oil price ($/Bbl)	$	51.34		$	55.75		$	60.00
Natural gas price ($/Mcf)	$	2.98		$	2.93		$	2.88
NGL price ($/Bbl)	$	51.34		$	55.75		$	60.00
Capital expenditure increase	n/a			Flat				5	%
Operating expenditure increase	n/a			Flat				5	%
Proved developed reserves (MMBoe)		114.5			115.3			115.3
Proved undeveloped reserves (MMBoe)		339.8			339.3			339.3
Total proved reserves (MMBoe)		454.3			454.6			454.6
PV-10 value (in thousands) (3)	$	3,539,337		$	4,104,991		$	4,454,357
Less: present value of future income taxes discounted at 10% (in thousands)		(695,432	)		(811,607	)		(890,810	)
Standardized measure (in thousands)	$	2,843,905		$	3,293,384		$	3,563,547

(1) SEC pricing as of December 31, 2017 before adjustment for market differentials.

(2) Prices represent potential SEC pricing based on different pricing assumptions before adjustments for market differentials.

(3) PV-10 is a non-GAAP financial measure. For a definition of PV-10, see “—Reconciliation of PV-10 to Standard Measure.”

Production, Revenue and Price History

~~For~~ The afollowing ~~description~~tables ofsummarize ~~ours,~~ our ~~predecessor’s~~average ~~and~~net ~~the previous owners’ combined historical~~ production, ~~revenues and~~ average unhedged sales prices ~~and~~by ~~unit~~product ~~costs, see “Item 7. Management’s Discussion~~ and ~~Analysis~~average ofproduction ~~Financial~~costs ~~Condition~~by ~~and~~geographic ~~Results~~region offor ~~Operations~~the –years ~~Results~~ended ofDecember ~~Operations.” For~~31, ~~certain financial information about our operations~~2018, ~~see~~2017 ~~“Item 6. Selected Financial Data”~~ and ~~“Item~~2016, ~~8. Financial Statements and Supplementary Data.”~~respectively:

The following tables summarize our average net production, average unhedged sales prices by product and average production costs by geographic region for the years ended December 31, 2017, 2016 and 2015, respectively:


	Year Ended December 31, 2018
	Oil			Natural Gas			NGLs			Total
		Average			Average			Average			Average		Lease
	Production	Sales		Production	Sales		Production	Sales		Production	Sales		Operating
	Volumes	Price		Volumes	Price		Volumes	Price		Volumes	Price		Expense
	(MBbls)	($/Bbl)		(MMcf)	($/Mcf)		(MBbls)	($/Bbl)		(MBoe)	($/MBoe)		($/MBoe)
Eagle Ford Shale	12,559	$	67.02	15,117	$	2.57	2,132	$	19.53	17,210	$	53.58	$	3.38
North Louisiana	26	$	61.93	6,414	$	3.31	11	$	30.84	1,106	$	20.97	$	3.13
Total	12,585			21,531			2,143			18,316			$	3.36
Average net production (MBoe/d)										50.2

	Year Ended December 31, 2017
	Oil					Natural Gas		~~Natural Gas~~		NGLs			Total	~~NGLs~~					~~Total~~
	Production Volumes				Average Sales Price			Production Volumes			Average Sales Price			Production Volumes			Average Sales Price		Production Volumes		Average Sales Price		Lease Operating Expense
			Average				Average				Average				Average		Lease
	(MBbls)				($/Bbl)			(MMcf)			($/Mcf)			(MBbls)			($/Bbl)		(MBoe)		($/MBoe)		($/MBoe)
	Production		Sales			Production	Sales			Production	Sales		Production		Sales		Operating
Eagle Ford		6,541			$	51.94			5,275		$	2.60			1,158		$	18.93		8,578	$	43.76	$	3.70
	Volumes		Price			Volumes	Price			Volumes	Price		Volumes		Price		Expense
North Louisiana		65			$	48.05			15,188		$	3.04			48		$	21.74		2,644	$	19.05	$	3.03
	(MBbls)		($/Bbl)			(MMcf)	($/Mcf)			(MBbls)	($/Bbl)		(MBoe)		($/MBoe)		($/MBoe)
Total		6,606							20,463						1,206					11,222			$	3.54
Eagle Ford Shale	6,541		$	51.94		5,275	$	2.60		1,158	$	18.93	8,578		$	43.76	$	3.70
Average net production (MBoe/d)																				30.7
North Louisiana	65		$	48.05		15,188	$	3.04		48	$	21.74	2,644		$	19.05	$	3.03
Total	6,606					20,463				1,206			11,222				$	3.54
Average net production (MBoe/d)													30.7

	Year Ended December 31, 2016
	Oil					Natural Gas		~~Natural Gas~~		NGLs			Total	~~NGLs~~					~~Total~~
	Production Volumes				Average Sales Price			Production Volumes			Average Sales Price			Production Volumes			Average Sales Price		Production Volumes		Average Sales Price		Lease Operating Expense
			Average				Average				Average				Average		Lease
	(MBbls)				($/Bbl)			(MMcf)			($/Mcf)			(MBbls)			($/Bbl)		(MBoe)		($/MBoe)		($/MBoe)
	Production		Sales			Production	Sales			Production	Sales		Production		Sales		Operating
Eagle Ford		1,765			$	41.21			1,750		$	2.20			404		$	11.74		2,461	$	33.05	$	2.42
	Volumes		Price			Volumes	Price			Volumes	Price		Volumes		Price		Expense
North Louisiana		83			$	38.70			16,070		$	2.47			67		$	15.54		2,828	$	15.52	$	2.25
	(MBbls)		($/Bbl)			(MMcf)	($/Mcf)			(MBbls)	($/Bbl)		(MBoe)		($/MBoe)		($/MBoe)
Total		1,848							17,820						471					5,289			$	2.33
Eagle Ford Shale	1,765		$	41.21		1,750	$	2.20		404	$	11.74	2,461		$	33.05	$	2.42
Average net production (MBoe/d)																				14.5
North Louisiana	83		$	38.70		16,070	$	2.47		67	$	15.54	2,828		$	15.52	$	2.25
Total	1,848					17,820				471			5,289				$	2.33
Average net production (MBoe/d)													14.5

	Year Ended December 31, 2015
	Oil				Natural Gas				NGLs				Total
	Production Volumes		Average Sales Price		Production Volumes		Average Sales Price		Production Volumes		Average Sales Price		Production Volumes		Average Sales Price		Lease Operating Expense
	(MBbls)		($/Bbl)		(MMcf)		($/Mcf)		(MBbls)		($/Bbl)		(MBoe)		($/MBoe)		($/MBoe)
Eagle Ford		895	$	44.45		1,210	$	2.34		248	$	11.38		1,345	$	33.78	$	4.05
North Louisiana		73	$	43.98		13,637	$	2.63		103	$	14.24		2,449	$	16.54	$	3.51
Total		968				14,847				351				3,794			$	3.70
Average net production (MBoe/d)														10.4

Reconciliation of PV‑10 to Standardized Measure

PV‑10 is a non-GAAP financial measure and differs from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV‑10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV‑10 is equal to the Standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV‑10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV‑10, however, is not a substitute for the Standardized measure of discounted future net cash flows. Our PV‑10 measure and the Standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

Table of Contents

The following table provides a reconciliation of PV‑10 of our proved reserves to the Standardized measure of discounted future net cash flows at December 31, 2018, 2017 and 2016:


	At December 31,
	2018		2017		2016
	(in thousands)
PV-10	$	5,089,918	$	3,539,337	$	749,988
Less: present value of future income taxes discounted at 10%		(972,482)		(695,432)		(206,947)
Standardized measure	$	4,117,436	$	2,843,905	$	543,041

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 own an interest, and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, ~~2017~~2018.

	Oil					Natural Gas				~~Natural Gas~~
	Gross Wells			Net Wells			Average Working Interest			Gross Wells		Net Wells		Average Working Interest
				Average					Average
Eagle Ford Acreage
	Gross		Net	Working		Gross	Net		Working
Operated		830.0			796.8			96.0	%		47.0		41.1		87.4	%
	Wells		Wells	Interest		Wells	Wells		Interest
Non-operated		125.0			26.7			21.4	%		27.0		6.6		24.4	%
Eagle Ford Acreage
North Louisiana Acreage
Operated	942.0		901.7	95.7%		53.0	48.0		90.6%
Operated		7.0			4.8			68.6	%		466.0		341.3		73.2	%
Non-operated	212.0		30.9	14.6%		30.0	6.3		21.0%
Non-operated		1.0			0.1			10.0	%		146.0		10.6		7.3	%
Total	1,154.0		932.6	80.8%		83.0	54.3		65.4%
Total		963.0			828.4			86.0	%		686.0		399.6		58.3	%

Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, ~~2017~~2018.

Region

Developed Acres(1)

Undeveloped Acres

Total Acres

Developed Acres

Undeveloped Acres

Total Acres

Gross (2)

Net (3)

Gross (2)

Net (3)

Gross (2)

Net (3)

Region

Gross

Net

Gross

Net

Gross

Net

Eagle Ford Acreage

33,106

~~24,040~~

28,066

438,141

~~21,028~~

297,605

471,247

~~435,960~~

325,671

~~366,063~~

~~460,000~~

~~387,091~~

North Louisiana Acreage

83,580

51,899

42,361

38,163

125,941

90,062

Total

107,620

72,927

478,321

404,226

585,941

477,153

~~(1)~~ Approximately ~~Developed~~74% ~~acres~~of ~~are~~our ~~acres~~net ~~spaced~~Eagle orFord ~~assigned~~Acreage towas ~~productive~~held ~~wells~~by orproduction ~~wells~~at ~~capable~~December of31, ~~production~~2018.

(2) A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(3) A net acre is deemed to exist when the sum of our 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.

Approximately 69% of our net Eagle Ford Acreage and 58% of our net North Louisiana Acreage was held by production at December 31, 2017. Included in our North Louisiana Acreage in the table above are approximately 12,848 net acres we have the right to lease pursuant to an oil and gas lease option agreement with affiliates of Weyerhaeuser Company (“Weyerhaeuser”). Pursuant to that agreement, we have the right, upon notice to Weyerhaeuser, to lease acreage in exchange for a specified bonus payment. Upon such notice and our payment of the applicable bonus payment, Weyerhaeuser is obligated under the option agreement to enter into a three-year lease with us for the acreage we specify in the notice. The purchase price of this option was $0.5 million, and in addition, we also made a prepayment of $0.4 million as an initial lease bonus for 1,285 unspecified net acres associated with leases under the option. In October 2016, we made a payment of $1.5 million to extend the option for one year. In January 2018, we exercised our option to lease approximately 12,848 net acres from Weyerhaeuser and paid $3.9 million. On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos for the sale of the NLA Assets, which include the recently leased acreage from Weyerhaeuser, for a total sales price of approximately $217.0 million. The transaction is expected to close by the end of March 2018.

Undeveloped Acreage Expirations

The following table sets forth the number of total net undeveloped acres as of December 31, ~~2017~~2018 across our Eagle Ford ~~and North Louisiana~~ Acreage that will expire in ~~2018,~~ 2019, 2020, 2021, 2022 and ~~2022~~2023, unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.

Region	~~2018~~2019		2020	~~2019~~2021		2022	~~2020~~2023		~~2021~~		~~2022~~
Eagle Ford Acreage	31,031	~~31,447~~	27,616	12,434	~~30,920~~	552	20	~~20,445~~		~~2,774~~		~~109~~
North Louisiana Acreage		23,694			11,700			2,583		6		—
Total		55,141			42,620			23,028		2,780		109

We intend to extend substantially all of the net acreage associated with our drilling locations through a combination of development drilling and leasehold extension and renewal payments. Of the 31,447 net acres expiring in 2018 across our Eagle Ford Acreage, we have the option to extend or renew the leases covering 13,124 net acres and have budgeted approximately $4.2 million in 2018 to execute extensions and renewals. With respect to the remaining 18,323 net acres for which we do not have an option to extend or renew in the Eagle Ford, 3,105 net acres are associated with 42 gross (30.0 net) wells of proved undeveloped reserves where the leases covering such expected wells will expire prior to our expected drilling date though we expect to extend or renew such leases. Further, with respect to the total remaining 18,323 net acres for which we do not have an option to extend or renew in the Eagle Ford, we intend to retain substantially all such acreage by negotiating lease extensions or renewals or drilling wells. Of the 23,694 net acres expiring in 2018 across our North Louisiana Acreage, we have the option to extend 19,101 of the 23,694 net acres in the RCT, Athens and Weyerhaeuser Areas, and we have budgeted approximately $6.8 million in 2018 to execute such extensions. As of December 31, 2017, 12,848 of the 23,694 net acres were related to the Weyerhaeuser Area. In January 2018, we exercised our option to lease approximately 12,848 net acres from Weyerhaeuser for approximately $3.9 million. We plan, in the event the NLA Divestiture is not consummated, to amend and extend or obtain new leases for the remaining approximately 4,593 net acres for an estimated cost of approximately $5.3 million. Please see Item 1A “Risk Factors—Risks Related to Our Business—Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.”

Drilling Activities

The following table summarizes our approximate gross and net interest in wells completed during the periods indicated (including both operated and non-operated wells), regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. A dry well is a well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion. A productive well is a well that is not a dry well. Completion refers to installation of permanent

20 15

~~equipment~~ Table ~~for production~~ of ~~oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.~~ Contents

	Year Ended December 31,
	2017				2016				2015
	Gross		Net		Gross		Net		Gross		Net
Eagle Ford Acreage
Development wells:
Productive		85.00		83.99		20.00		16.06		18.00		17.84
Dry		—		—		—		—		—		—
Exploratory wells:
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
North Louisiana Acreage
Development wells:
Productive		11.00		6.94		4.00		1.78		6.00		4.51
Dry		—		—		—		—		—		—
Exploratory wells:
Productive		—		—		—		—		2.00		1.70
Dry (1)		—		—		—		—		1.00		1.00
Total wells
Development wells:
Productive		96.00		90.93		24.00		17.84		24.00		22.35
Dry		—		—		—		—		—		—
Total development wells		96.00		90.93		24.00		17.84		24.00		22.35
Exploratory wells:
Productive		—		—		—		—		2.00		1.70
Dry		—		—		—		—		1.00		1.00
Total exploratory wells		—		—		—		—		3.00		2.70
Total		96.00		90.93		24.00		17.84		27.00		25.05

among the number of productive wells drilled, quantities of reserves found or economic value. A dry well is a well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion. A productive well is a well that is not a dry well. Completion refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

(1) Our predecessor encountered mechanical malfunctions during drilling and was unable to complete the well.


	Year Ended December 31,
	2018		2017		2016
	Gross	Net	Gross	Net	Gross	Net
Eagle Ford Acreage
Development wells:
Productive	99.00	94.16	85.00	83.99	20.00	16.06
Dry	—	—	—	—	—	—
Total development wells	99.00	94.16	85.00	83.99	20.00	16.06
Exploratory wells:
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total exploratory wells	—	—	—	—	—	—
Total	99.00	94.16	85.00	83.99	20.00	16.06

At December 31, ~~2017~~2018, 1627.0 gross (1425.29 net) wells (including wells temporarily suspended) were in the process of being drilled. We are currently running a ~~six~~four-rig program in our Eagle Ford Acreage ~~and a one-rig program in North Louisiana Acreage~~, which we are utilizing on a well-to-well basis. We are not currently a party to any long-term drilling rig contracts. We plan to operate an average of ~~4.8~~four drilling rigs in the Eagle Ford Shale and Austin Chalk Trend in ~~2018~~2019.

~~Delivery~~ Major ~~Commitments~~Customers

We The ~~have~~following notable ~~commitments~~sets toforth ~~deliver~~the percentage aof ~~fixed~~our ~~and~~revenues ~~determinable~~attributed ~~quantity~~to of our ~~oil~~customers orwho ~~natural~~have ~~gas~~accounted ~~production~~for to10% ~~customers~~or inmore ~~the~~of ~~near~~our ~~future~~revenues ~~under~~during ~~our~~2018, ~~existing~~2017 ~~contracts~~and 2016.

We have a firm gas transportation service agreement with Regency Intrastate Gas LLC (“RIGS”) for properties in North Louisiana. Under the terms of the agreement, we are obligated to pay total daily transportation fees not to exceed $0.30 per MMBtu per day for quantities of 40,000 MMBtu per day to RIGS until March 5, 2019. This agreement will be assigned to Tanos upon completion of the NLA Divestiture.


	For the Year Ended December 31,
Major Customers	2018		2017		2016
Energy Transfer Equity, L.P. and subsidiaries	49	%	56	%	63	%
Koch Industries, Inc.	19	%	4	%	n/a
Royal Dutch Shell plc and subsidiaries	18	%	21	%	12	%
Cima Energy LTD	n/a		n/a		15	%

~~Our~~ Based ~~Operations~~on the current demand for oil, natural gas and NGLs and the availability of other purchasers, we believe that the loss of any such purchaser would not have a material adverse effect on our financial condition and results of operations.

General

We have leased or acquired approximately 585,941 gross (477,153 net) acres where we had a weighted-average working interest of approximately 81%, as of December 31, 2017. As operator of a majority of our acreage, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Facilities

We maintain active development of our infrastructure to reduce lease operating costs and support our drilling schedule and production growth. Our production facilities are located near the producing well and consist of storage tanks, two-phase and three-phase

separation equipment, flowlines, metering equipment and safety systems. Predominate artificial lift methods include foamer, gas, plunger and rod lift.

In the Eagle Ford, our crude oil is trucked by third-party purchasers in a process that is actively managed to ensure the best available market for our oil. For gas gathering, processing and fractionation, our Eagle Ford assets are in proximity to active third-party low-pressure systems across our acreage. We have favorable long-term agreements in place with two gas gathering and processing companies with the benefit of minimal connection costs. We own substantial fresh water supply and storage, have developed saltwater disposal wells and are in the process of developing an in-field sand mine.

In North Louisiana, approximately half of our gas production is gathered into a company owned, high-pressure pipeline system and then delivered and sold to various intrastate and interstate markets on a competitive pricing basis. The majority of our gas production is not currently processed due to current processing economics, but we have access to several third-party gas processors if processing is economically justified. We also own and operate a salt water disposal well, which currently receives the majority of our associated water production. We own another saltwater disposal well that is currently inactive.

Marketing and Customers

The following table sets forth the percentage of our revenues attributed to our customers who have accounted for 10% or more of our revenues during 2017, 2016 or 2015.

	Years Ending December 31,
Major Customers	2017			2016 (1)			2015 (1)
Energy Transfer Equity, L.P. and subsidiaries		56	%		63	%		36	%
Royal Dutch Shell plc and subsidiaries		21	%		12	%		20	%
Cima Energy LTD	n/a				15	%		16	%

(1) The amounts listed represent the percentage of WHR II and Esquisto’s total revenue on a combined basis and WRD subsequent to the initial public offering.

We market the majority of our production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our oil, natural gas and NGL production to purchasers at market prices. We sell all of our oil and certain of our natural gas and NGLs under contracts with terms of twelve months or less and the remainder of our natural gas and NGLs under contracts with terms of greater than twelve months.

No other purchaser accounted for 10% or more of our revenue in the years ended December 31, 2017, 2016 or 2015. The loss of any such purchaser could adversely affect our revenues in the short term. However, based on the current demand for oil, natural gas and NGLs and the availability of other purchasers, we believe that the loss of any such purchaser as a purchaser would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Competition

~~The~~ We ~~oil~~compete ~~and~~with ~~natural~~both ~~gas~~major ~~industry~~integrated isand ~~intensely~~other ~~competitive,~~independent oil and wenatural ~~compete~~gas ~~with other~~ companies ~~that~~in ~~have~~all ~~greater~~aspects ~~resources. Many~~ of ~~these~~our ~~companies~~business ~~not~~to ~~only~~ explore, ~~for~~develop and ~~produce~~operate ~~oil~~our properties and ~~natural~~market ~~gas,~~our ~~but~~production. ~~also~~Some ~~carry~~of onour ~~midstream~~competitors ~~and~~may ~~refining~~have ~~operations~~larger ~~and~~financial ~~market petroleum~~ and other ~~products~~resources onthan ~~a regional, national or worldwide basis~~us. ~~These~~Competitive ~~companies~~conditions may be ~~able~~affected toby ~~pay~~future ~~more~~legislation ~~for productive oil~~ and ~~natural~~regulations ~~gas~~as ~~properties~~the ~~and~~United ~~exploratory~~States ~~prospects~~develops ornew toenergy ~~define, evaluate, bid for~~ and ~~purchase~~climate-related ~~a greater number of properties and prospects than our financial or human resources permit~~policies. In addition, ~~these~~some ~~companies~~of our competitors may have a ~~greater~~competitive ~~ability~~advantage towhen ~~continue~~responding ~~exploration~~to ~~activities~~factors ~~during~~that ~~periods~~affect ofdemand ~~low~~for oil and natural gas ~~market prices. Our larger or more integrated competitors may be able to absorb the burden of existing~~production, ~~and~~such ~~any~~as ~~changes~~changing toprices, ~~federal,~~domestic ~~state~~ and ~~local~~foreign ~~laws~~political ~~and~~conditions, ~~regulations~~weather ~~more easily than we can~~conditions, ~~which~~the ~~would~~price ~~adversely affect our competitive position. Our ability to acquire additional properties~~ and toavailability ~~discover~~of ~~reserves~~alternative infuels, the ~~future~~proximity ~~will~~and becapacity ~~dependent~~of ~~upon~~natural ~~our~~gas ~~ability~~pipelines ~~to evaluate~~ and ~~select~~other ~~suitable~~transportation ~~properties~~facilities and tooverall ~~consummate~~economic ~~transactions in a highly competitive environment~~conditions. InWe ~~addition,~~also ~~because~~face weindirect ~~have~~competition ~~fewer~~from ~~financial~~alternative ~~and~~energy ~~human resources than many companies in our industry~~sources, weincluding ~~may~~wind ~~be at a disadvantage in bidding for exploratory prospects~~ and ~~producing~~solar ~~oil~~power. ~~and~~We ~~natural~~believe ~~gas~~that ~~properties.~~our

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger 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. 16

22 Table of Contents

technological expertise, combined with our exploration, land, drilling and production capabilities and the experience of our management team, enables us to compete effectively.

Seasonality of Business

Weather conditions can affect the demand for, and prices of, oil, natural gas and NGLs. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher prices while the demand for oil is typically higher during the second and third quarters. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

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 in connection with acquisition of leasehold acreage. 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.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report.

~~Oil~~ Public Policy and ~~Natural~~Government ~~Gas Leases~~Regulation

~~The~~ All ~~typical~~of ~~oil~~our operations are conducted onshore in the United States. Our industry is subject to a wide range of regulations, laws, rules, taxes, fees and ~~natural~~other ~~gas~~policy ~~lease~~implementation ~~agreement~~actions ~~covering~~that ~~our~~have ~~properties~~been ~~provides~~pervasive and are under constant review for ~~the~~amendment ~~payment~~or expansion. Numerous government agencies have issued extensive regulations which are binding on our industry, some of ~~royalties~~which carry substantial penalties for failure to ~~the~~comply. ~~mineral~~These ~~owner~~laws ~~for~~and ~~all~~regulations ~~oil~~increase the cost of doing business and ~~natural~~consequently ~~gas~~affect ~~produced~~profitability. ~~from~~Additionally, ~~any~~currently ~~wells~~unforeseen ~~drilled~~environmental onincidents ~~the~~may ~~leased~~occur ~~premises~~or past non-compliance with environmental laws or regulations may be discovered. We ~~The~~actively ~~lessor~~monitor ~~royalties~~regulatory developments applicable to our industry in order to anticipate, design and ~~other~~implement ~~leasehold~~required ~~burdens~~compliance onactivities ~~our~~and ~~properties~~systems. The ~~generally~~following ~~range~~are ~~from~~significant ~~approximately~~areas ~~20%~~of togovernment ~~30%~~control and regulation affecting our operations.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), the United States Environmental Protection Agency (“EPA”), the Bureau of Land Management (“BLM”), the Department of Transportation (“DOT”), other federal and state agencies, and the courts. We cannot predict when or whether any such proposals may become effective.

In addition, unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Texas and Louisiana, which regulate drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells.

The laws of both states also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, various states impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Sales and Transportation of Oil

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.

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 and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993.

The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC for any entity, directly or indirectly, to: (i) use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services 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. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.

Regulation of Pipeline Safety and Maintenance

We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, (“PHMSA”), of the DOT, pursuant to the NGPSA, and the Pipeline Safety Improvement Act of 2002, or the PSIA, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the Pipeline Safety Act, was signed into law. In addition to reauthorizing the PSIA through 2015, the Pipeline Safety Act expanded the DOT’s authority under the PSIA and requires the DOT to evaluate whether integrity management programs should be expanded beyond high consequence areas, authorizes the DOT to promulgate regulations requiring the use of automatic and remote-controlled shut-off valves for new or replaced pipelines, and requires the DOT to promulgate regulations requiring the use of excess flow values where feasible. In addition, new pipeline safety legislation, the “Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016” (the “PIPES Act”), was signed into law in June 2016. The PIPES Act provides PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions, and safety measures on owners and operators of gas or hazardous liquids pipeline facilities. The

Act also directs PHMSA to issue minimum safety standards for natural gas storage facilities by June 2018, and calls for a review, study, and analysis of a number of issues related to pipeline management and safety.

PHMSA has also proposed additional regulations for gas pipeline safety. For example, in March 2016 PHMSA proposed a rule that would explain integrity management requirements beyond “High Consequence Areas” to apply to natural gas pipelines in newly defined “Moderate Consequence Areas.” Many gas pipelines that were in place before 1970, and thus grandfathered from certain pressure testing obligations, would be required to be pressure tested to determine their maximum allowable operating pressures. Many gathering lines in rural areas that are currently not regulated at the federal level would also be covered by this proposal. To date, no further action has been taken by PHMSA. Any new or amended pipeline safety regulations may require us to incur additional capital expenditures and may increase our operating costs. We cannot predict what future action the DOT will take, but we do not believe that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas gatherers with which we compete.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Changes in existing regulations or future pipeline construction activities may subject some of our pipelines to more stringent DOT regulations, and could adversely affect our business.

Regulation of Environmental and Occupational Safety and Health Matters

Our ~~oil and natural gas development~~ operations are subject to ~~numerous stringent~~ federal, ~~state and local statutes and regulations governing occupational safety and health~~tribal, ~~the discharge of materials into the environment or otherwise relating to the protection of the environment or natural resources~~state, ~~some of which carry substantial administrative, civil~~ and ~~criminal~~local ~~fines~~laws and ~~penalties for failure to comply~~regulations. These laws and regulations ~~may~~relate ~~require~~to ~~the~~matters ~~acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances~~ that ~~can be released into the environment in connection with drilling~~include, ~~production~~but ~~and~~are ~~transporting~~not ~~oil~~limited and natural gas through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, ~~these laws and regulations may restrict~~ the ~~rate of production.~~following:

~~The~~Ÿ ~~following~~reporting ~~is a summary~~ of ~~the~~workplace ~~more~~injuries ~~significant existing environmental~~ and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.illnesses;

~~Hazardous~~Ÿ ~~Substances~~industrial ~~and~~hygiene ~~Waste Handling~~monitoring;

~~The~~Ÿ ~~Comprehensive~~worker ~~Environmental~~protection ~~Response, Compensation,~~ and ~~Liability~~workplace Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and persons that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and 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. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.safety;

~~The~~Ÿ ~~Resource~~mine Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and certain environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Pursuant to the consent decree, the EPA must complete any revisions to RCRA's Subtitle safety;

26Ÿ approval or permits to drill and to conduct operations;

DŸ ~~regulations~~provision ~~by 2021. A loss~~ of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial ~~position.~~assurances ~~In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes,~~ (such as ~~paint~~bonds) ~~wastes,~~covering ~~waste~~drilling ~~solvents, laboratory wastes~~ and ~~waste~~well compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.operations;

WeŸ ~~currently~~calculation ~~own, lease or operate numerous properties that have been used for oil~~ and ~~natural~~disbursement gas development and production activities for many years. Although we believe that the operations on these properties have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of ~~our~~royalty ~~properties~~payments ~~have been operated by third parties or by previous owners or operators whose treatment~~ and ~~disposal~~production of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.taxes;

~~Water~~Ÿ ~~Discharges~~seismic operations and data;

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable 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 discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. The 2015 rule was previously stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule and announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction. Recently, in January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction to hear challenges to the 2015 rule resides with the federal district courts; consequently, the previously-filed district court cases will be allowed to proceed. Following the Supreme Court’s decision, the EPA and the Corps stayed implementation of the 2015 rule for two years. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time. To the extent the rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. 17

~~Pursuant~~ Table ~~to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge~~ of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. Contents

~~The~~Ÿ ~~primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”)~~location, which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For exampledrilling, ~~operators~~cementing ~~of certain oil~~ and ~~natural~~casing ~~gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees~~ of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.wells;

~~Air~~Ÿ ~~Emissions~~well design and construction of pad and equipment;

~~The~~Ÿ ~~federal~~construction ~~Clean Air Act~~ and ~~comparable~~operations ~~state~~activities ~~laws~~in ~~restrict~~sensitive ~~the emission of air pollutants from many sources (e.g.~~areas, ~~compressor~~such ~~stations),~~as ~~through the imposition of air emissions standards~~wetlands, ~~construction~~coastal ~~and~~regions ~~operating permitting programs and other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction~~ or ~~modification~~areas ofthat ~~certain~~contain ~~projects~~endangered or ~~facilities~~threatened ~~expected~~species, totheir ~~produce or significantly increase air emissions~~habitats, ~~obtain and strictly comply with stringent air permit requirements~~ or ~~utilize~~sites ~~specific equipment or technologies to control emissions~~ of ~~certain~~cultural pollutants. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. Subsequently, in November 2017, the EPA published a list of areas that are in compliance with the new ozone standards and separately in December 2017 issued responses to state recommendation for designating non-attainment areas. States have the opportunity to submit new air significance;

27Ÿ method of completing wells;

~~quality~~Ÿ ~~monitoring~~hydraulic ~~to the EPA prior to the EPA finalizing any non-attainment designations. The EPA has stated that it intends to issue final non-attainment designations during the first half of 2018.~~fracturing;

~~State~~Ÿ ~~implementation~~water of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.withdrawal;

InŸ addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound and methane emissions from certain fractured and refractured oil and natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production~~-related~~ ~~wet seal~~ and ~~reciprocating~~operations ~~compressors,~~including ~~and~~processing ~~from pneumatic controllers~~ and ~~storage~~gathering vessels. In addition, the regulations place new requirements to detect and repair volatile organic compound and methane at certain well sites and compressor stations. In May 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant.systems;

~~Regulation~~Ÿ ofemergency ~~GHG~~response, ~~Emissions~~contingency plans and spill prevention plans;

~~The~~Ÿ EPA has determined that emissions of carbon dioxide, methane and other greenhouse gasses (“GHGs”) present an endangerment to public health and the environment and has adopted regulations pursuant to the federal Clean Air Act to reduce GHG emissions from various sources. For example, the EPA requires certain large stationary sources to obtain preconstruction and operating permits for pollutants regulated under the Prevention of Significant Deterioration and Title V programs of the Clean Air Act. Facilities required to obtain preconstruction permits for such pollutants are also required to meet “best available control technology” standards that are being established by the states. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air ~~permits for new or modified sources. The EPA has adopted rules requiring the monitoring and reporting of GHG~~ emissions ~~from specified onshore~~ and ~~offshore~~fluid oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. In June 2016, the EPA published performance standards that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas sector, including production, processing, transmission and storage activities. Compliance will require enhanced record-keeping practices, the purchase of new equipment, and increased frequency of maintenance and repair activities to address emissions leakage at certain well sites and compressor stations, and also may require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance. However, over the past year the EPA has taken several steps to delay implementation of the June 2016 methane rule, and the agency proposed a separate rulemaking in June 2017 to stay the methane requirements for a period of two years and revisit implementation of the standards in their entirety. The EPA has not yet published a final rule but, even though the rule is currently in effect, future implementation and enforcement of the 2016 standards is uncertain at this time.discharges;

~~There~~Ÿ has been no significant activity with respect to federal legislation to reduce GHG emissions in recent years. In the absence of such federal legislation, a number of state and regional efforts have emerged that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes, or encouraging the use of renewable energy or alternative low-carbon fuels. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States signed the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016 and includes non-binding pledges to limit or reduce future emissions. However, in June 2017, the President stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, resulting in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as delay or restrict our ability to permit GHG emissions from new or modified sources. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.;

~~Recently,~~Ÿ ~~activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies~~use, ~~which has resulted in certain financial institutions~~transportation, ~~funds~~storage and ~~other~~disposal ~~sources~~ of ~~capital~~fluids ~~restricting~~and ormaterials ~~eliminating~~incidental ~~their~~to ~~investment in~~ oil and ~~natural~~ gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency operations;

28Ÿ surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;

~~estimates~~Ÿ ~~that~~plugging ~~global energy demand will continue to rise~~ and ~~will~~abandoning ~~not peak until after 2040 and that oil and gas will continue to represent a substantial percentage~~ of global energy use over that time. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic eventswells; ~~if any such effects were to occur, they could have a material adverse effect on our operations.~~and

~~Hydraulic~~Ÿ ~~Fracturing~~transportation ~~Activities~~of production.

~~Hydraulic~~ Failure ~~fracturing~~to iscomply anwith ~~important~~these laws and ~~common~~regulations ~~practice~~can ~~that~~lead ~~is used~~ to ~~stimulate~~the ~~production~~imposition of ~~oil~~remedial ~~and/or~~liabilities, ~~natural~~fines, ~~gas~~or ~~from~~criminal ~~dense~~penalties ~~subsurface~~or ~~rock~~to ~~formations.~~injunctions ~~The~~limiting ~~hydraulic~~our ~~fracturing~~operations ~~process~~in ~~involves~~affected ~~the~~areas. ~~injection~~Moreover, ofmultiple ~~water,~~environmental ~~proppants~~laws ~~and~~provide ~~chemicals~~for ~~under~~citizen ~~pressure~~suits ~~into~~which ~~targeted~~allow ~~subsurface~~environmental ~~formations~~organizations to ~~fracture~~act in the ~~surrounding~~place ~~rock~~of ~~and~~the ~~stimulate~~government ~~production.~~and Wesue ~~regularly~~operators ~~use~~for ~~hydraulic~~alleged ~~fracturing~~violations ~~as part~~ of ~~our~~environmental ~~operations~~law. ~~Hydraulic~~We ~~fracturing~~consider isthe ~~typically~~costs ~~regulated~~of byenvironmental ~~state~~protection ~~oil~~ and ~~natural~~of ~~gas~~safety ~~commissions,~~and ~~but~~health ~~the~~compliance ~~EPA~~to ~~has~~be ~~asserted~~necessary, ~~federal~~manageable ~~regulatory~~parts ~~authority~~of ~~pursuant~~our tobusiness. ~~the~~We ~~SDWA~~have ~~over~~been ~~certain~~able ~~hydraulic~~to ~~fracturing~~plan ~~activities~~for ~~involving~~and ~~the~~comply ~~use~~with ofenvironmental, ~~diesel~~safety ~~fuels~~ and ~~published~~health ~~permitting~~initiatives ~~guidance~~without inmaterially ~~February~~altering ~~2014~~our ~~addressing~~operating ~~the~~strategy ~~performance~~or ofincurring ~~such~~significant ~~activities~~unreimbursed ~~using diesel fuels~~expenditures. ~~The~~However, ~~EPA~~based ~~has~~on ~~issued~~regulatory ~~final~~trends ~~regulations~~and ~~under~~increasingly ~~the~~stringent ~~federal~~laws, ~~Clean~~our ~~Air~~capital ~~Act~~expenditures ~~establishing~~and ~~performance~~operating ~~standards,~~expenses ~~including~~related ~~standards~~to ~~for~~compliance with the ~~capture~~protection of ~~air~~the ~~emissions~~environment, ~~released~~safety ~~during~~and ~~hydraulic~~health ~~fracturing,~~have ~~and~~increased ~~also~~over ~~finalized~~the ~~rules~~years inand ~~June~~may ~~2016~~continue ~~that~~to ~~prohibit~~increase. ~~the~~We ~~discharge~~cannot ofpredict ~~wastewater~~with ~~from~~any ~~hydraulic~~reasonable ~~fracturing~~degree ~~operations~~of tocertainty ~~publicly~~our ~~owned~~future ~~wastewater~~exposure ~~treatment~~concerning ~~plants.~~such matters.

At Our ~~the~~operations ~~state~~are ~~level,~~also ~~several~~subject ~~states~~to ~~have~~conservation ~~adopted~~regulations, orincluding ~~are~~the ~~considering~~regulation ~~legal~~of ~~requirements~~the ~~that~~size ~~could~~of ~~impose~~drilling ~~more~~and ~~stringent~~spacing ~~permitting,~~units ~~disclosure~~or ~~and~~proration ~~well~~units, ~~construction~~the ~~requirements~~number onof ~~hydraulic~~wells ~~fracturing~~that ~~activities.~~may ~~For~~be ~~example,~~drilled in ~~May~~a ~~2013~~unit, the ~~Railroad~~rate ~~Commission~~ of ~~Texas~~production (allowable from oil and gas wells, and the ~~“Railroad~~unitization ~~Commission”)~~or ~~issued~~pooling aof ~~“well~~oil ~~integrity~~and ~~rule,”~~gas ~~which~~properties. ~~updates~~In the ~~requirements~~United ~~for drilling~~States., ~~putting~~some ~~pipe~~states ~~down~~allow ~~and~~the ~~cementing~~forced ~~wells.~~pooling ~~The~~or ~~rule~~integration ~~also~~of ~~includes~~tracts ~~new~~to ~~testing~~facilitate ~~and~~exploration. Other ~~reporting~~states ~~requirements,~~rely ~~such~~on asvoluntary ~~(i)~~pooling ~~the~~of ~~requirement~~lands toand ~~submit~~leases ~~cementing~~which ~~reports~~may ~~after~~make ~~well~~it ~~completion~~more ordifficult ~~after~~to ~~cessation~~develop ofoil ~~drilling,~~and ~~whichever~~gas isproperties. ~~later~~In addition, federal and ~~(ii)~~state ~~the~~conservation ~~imposition~~laws ofgenerally ~~additional~~limit ~~testing~~the onventing ~~wells~~or ~~less~~flaring ~~than~~of 1natural gas,~~000~~ ~~feet~~and ~~below~~state ~~usable~~conservation ~~groundwater.~~laws ~~The~~impose ~~well~~certain ~~integrity~~requirements ~~rule~~regarding ~~took~~the ~~effect~~ratable inpurchase ~~January~~of ~~2014~~production. ~~Local~~These ~~governments~~regulations ~~also~~limit ~~may~~the ~~seek~~amounts toof ~~adopt~~oil ~~ordinances~~and ~~within~~gas ~~their~~we ~~jurisdictions~~can ~~regulating~~produce ~~the~~from ~~time,~~our ~~place~~wells and ~~manner~~the number of ~~drilling~~wells ~~activities~~or inthe ~~general~~locations orat ~~hydraulic~~which ~~fracturing~~we ~~activities~~can ~~in particular~~drill.

In Regulatory ~~December~~proposals ~~2016,~~in ~~the~~some ~~EPA~~states ~~released~~and ~~its~~local ~~final~~communities ~~report~~have onbeen ~~the~~initiated ~~potential~~to ~~impacts~~require ofor ~~hydraulic~~make ~~fracturing~~more onstringent ~~drinking~~the ~~water~~permitting ~~resources.~~and ~~The~~compliance ~~EPA~~requirements ~~report~~for ~~concluded that “water cycle” activities associated with~~ hydraulic fracturing ~~may~~operations. Federal ~~impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities~~ and ~~local-~~state oragencies ~~regional-scale~~have ~~factors~~continued ~~are more likely than others~~ to ~~result~~assess inthe ~~more~~potential ~~frequent or more severe~~ impacts~~: water~~ ~~withdrawals for fracturing in times or areas~~ of ~~low~~hydraulic ~~water availability; surface spills during the management of~~ fracturing ~~fluids~~, ~~chemicals~~which orcould ~~produced~~spur ~~water;~~further ~~injection~~action oftoward ~~fracturing~~federal, ~~fluids~~state ~~into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters;~~ and ~~disposal~~ /or ~~storage~~local ~~of fracturing wastewater in unlined pits.~~

Compliance with existing laws has not had a material adverse effect on our operations or financial position, but if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells. 18

~~ESA~~ Table ~~and~~of ~~Migratory Birds~~Contents

~~The~~legislation ~~Endangered Species Act (“ESA”)~~ and ~~(in some cases) comparable state laws were established to protect endangered and threatened species~~regulation. Further ~~Pursuant to the ESA, if a species is listed as threatened or endangered,~~ restrictions ~~may~~of behydraulic ~~imposed~~fracturing oncould ~~activities~~reduce ~~adversely~~the ~~affecting~~amount ~~that~~of ~~species’ habitat. We may conduct operations on~~ oil, ~~and~~ natural gas ~~leases in areas where certain species that are or could be listed as threatened or endangered are known to exist. The U.S. Fish~~ and ~~Wildlife~~natural ~~Service~~gas ~~may~~liquids ~~designate~~(NGLs) ~~critical habitat and suitable habitat areas~~ that itwe ~~believes~~ are ~~necessary~~ultimately ~~for~~able ~~survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions~~ to ~~land~~produce ~~use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia~~ in ~~September~~commercial ~~2011,~~quantities the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The agency did not meet the deadline and continues to review additional species for listing under the ESA. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from ~~species protection measures or could result in limitations on~~ our ~~development activities that could have an adverse impact on our ability to develop and produce reserves~~properties. ~~If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.~~

~~OSHA~~ Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands are subject to frequent delays.

We Delays ~~are~~in ~~subject~~obtaining topermits ~~the~~or ~~requirements~~an ofinability ~~the~~to ~~Occupational~~obtain ~~Safety~~new ~~and~~permits ~~Health~~or ~~Act~~permit ~~(“OSHA”)~~renewals ~~and~~could ~~comparable~~inhibit ~~state~~our ~~statutes~~ability ~~whose purpose is~~ to ~~protect~~execute ~~the~~our ~~health~~drilling and ~~safety~~production ~~of workers~~plans. InFailure ~~addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-~~to~~-Know~~ ~~Act~~comply ~~and~~with ~~comparable~~applicable ~~state statutes and any implementing~~ regulations ~~require that we organize and/~~or ~~disclose~~permit ~~information~~requirements ~~about~~could ~~hazardous~~result ~~materials~~in ~~used~~revocation orof ~~produced in~~ our ~~operations~~permits, ~~and~~inability ~~that this information be provided~~ to ~~employees,~~obtain ~~state~~new permits and ~~local~~the ~~governmental~~imposition ~~authorities~~of fines and ~~citizens~~penalties.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

Employees

As of December 31, ~~2017~~2018, we had ~~137~~197 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition, cash flows or results of operations.

~~Due~~ In toJanuary 2019, putative class action lawsuits in U.S. District Courts for the ~~nature~~District of ~~our~~Delaware ~~business,~~and weSouthern ~~are,~~District ~~from~~of ~~time~~New toYork ~~time,~~were ~~involved~~filed inagainst ~~other~~us ~~routine~~and ~~litigation~~other ordefendants. ~~subject~~The tolawsuits ~~disputes~~generally orallege ~~claims~~various ~~related~~violations toof ~~our~~the ~~business~~Securities ~~activities,~~Exchange ~~including~~Act ~~workers’~~of ~~compensation~~1934 ~~claims~~in ~~and~~connection ~~employment~~with ~~related~~the ~~disputes.~~disclosure Incontained in the ~~opinion~~joint ofproxy ~~our~~statement/prospectus ~~management,~~filed ~~none~~in ofconnection ~~these~~with ~~other~~the ~~pending~~Merger. ~~litigation,~~The ~~disputes~~lawsuits orseek ~~claims~~rescission ~~against~~of ~~us,~~the ifMerger ~~decided~~or ~~adversely,~~rescissory ~~will~~damages ~~have~~and, ain ~~material~~each ~~adverse~~case, ~~effect~~attorney's onfees, ~~our~~costs ~~financial~~and ~~condition,~~interest. ~~cash~~We ~~flows~~intend orto ~~results~~vigorously ofdefend ~~operations~~these claims.

Due to the nature of our business, we are, from time to time, involved in other 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 these other 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.

Table of Contents

Offices

Our principal executive office is located at ~~9805~~6100 ~~Katy~~N. ~~Freeway~~Western Avenue, ~~Suite~~Oklahoma ~~400~~City, ~~Houston,~~OK ~~Texas 77024~~73118. Our main telephone number is (~~713~~405) ~~568~~848-~~4910~~8000.

Available Information

Our annual reports on Form 10-‑K, quarterly reports on Form 10-‑Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are ~~made~~ available ~~free of charge~~ on ~~our website at www.wildhorserd.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to,~~ the SEC~~. These documents are also available on the SEC’~~'s website at www.sec.gov ~~or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549~~. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our website also includes our Code of Business Conduct and Ethics and the charter of our audit committee. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

ITEM 1A. RISK FACTORS

There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, operating results, cash flows, reserves and/or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.

Risks Related to Our Business

Oil, natural gas and NGL prices ~~are~~fluctuate ~~volatile. A sustained decline in oil~~widely, ~~natural gas~~ and ~~NGL~~lower prices ~~could~~for ~~adversely~~an ~~affect~~extended ~~our~~period ~~business, financial condition and results~~ of ~~operations~~time ~~and~~are ~~our~~likely ~~ability~~ to ~~meet~~have ~~our~~a ~~capital~~material ~~expenditure~~adverse ~~obligations~~effect ~~and~~on ~~financial~~our ~~commitments~~business.

~~The~~ Our ~~prices we receive for our oil~~revenues, ~~natural~~operating ~~gas and NGL production heavily influence our revenue~~results, profitability, ~~access~~liquidity toand ~~capital,~~ability ~~future~~to ~~rate~~grow ofdepend ~~growth~~primarily ~~and~~upon the ~~carrying~~prices ~~value~~we ofreceive ~~our~~for ~~properties.~~the ~~Oil~~oil, natural gas and ~~NGLs~~NGL ~~are~~we ~~commodities,~~sell. ~~and~~We ~~their~~incur ~~prices~~substantial ~~may~~expenditures ~~fluctuate widely in response~~ to ~~market~~replace ~~uncertainty~~reserves, ~~and~~sustain toproduction ~~relatively minor changes in the supply of~~ and ~~demand~~fund ~~for~~our ~~oil,~~business ~~natural gas and NGLs~~plans. ~~Historically,~~Low oil, natural gas and NGL prices ~~have~~can ~~been~~negatively ~~volatile.~~affect ~~For~~the ~~example,~~amount ~~commodity~~of ~~prices~~cash ~~dropped~~available ~~significantly~~for ~~from~~capital ~~2014~~expenditures, ~~highs~~debt ofservice ~~$107.95~~and ~~per~~debt ~~barrel~~repayment ~~of oil~~ and ~~$8.15~~our ~~per~~ability ~~MMBtu for natural gas down~~ to ~~lows~~borrow ofmoney ~~$26.19 per barrel of oil in February 2016~~ and, ~~$1.49~~as ~~per~~a ~~MMBtu for natural gas in March 2016. Since 2016~~result, ~~prices~~could have ~~generally~~a ~~increased.~~material Onadverse ~~February~~effect ~~26,~~on ~~2018,~~our ~~the~~financial ~~WTI~~condition, ~~spot~~results ~~price~~of ~~for~~operations, ~~oil~~cash ~~was~~flows ~~$63.81 per barrel~~ and ~~the Henry Hub spot price for natural gas was $2~~reserves.60 ~~per~~In ~~MMBtu. Likewise~~addition, ~~NGLs,~~periods ~~which are made up~~ of ~~ethane,~~low ~~propane,~~oil ~~isobutane, normal butane~~ and natural ~~gasoline,~~gas ~~each~~prices ofmay ~~which~~result ~~have different uses and different pricing characteristics, have suffered significant recent declines~~ in ~~realized~~impairments ~~prices.~~of ~~The prices we receive for~~ our ~~production,~~oil and ~~the~~natural ~~levels~~gas ~~of our production, depend on numerous factors beyond our control, which include the following:~~properties.

• Historically, ~~worldwide~~the markets for oil, natural gas and ~~regional~~NGL ~~economic~~have ~~conditions~~been ~~impacting~~volatile, and they are likely to continue to be volatile. For example, during the ~~global~~period ~~supply~~from ~~and~~January ~~demand~~1, 2014 to December 31, 2018, NYMEX WTI oil prices ranged from a high of $107.26 per bbl to a low of $26.21 per bbl. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu during the same period. Wide fluctuations in oil, natural gas and ~~NGLs;~~NGL prices may result from factors that are beyond our control, including:

•· ~~the~~domestic ~~price~~ and ~~quantity~~worldwide ofsupplies ~~foreign imports~~ of oil, natural gas and ~~NGLs~~NGL, including U.S. inventories of oil and natural gas reserves;

•· ~~political~~weather ~~and economic~~ conditions ~~in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia~~;

•· ~~actions~~changes ofin the ~~Organization~~level of ~~the~~consumer ~~Petroleum Exporting Countries, its members~~ and ~~other~~industrial ~~state- controlled oil companies relating to oil price and production controls~~demand;

•· the ~~level~~price ofand ~~global~~availability ~~exploration,~~of ~~development~~alternative ~~and production~~fuels;

•· ~~the~~technological ~~level~~advances ofaffecting ~~global~~energy ~~inventories~~consumption;

•· ~~prevailing prices on local price indexes in~~ the ~~areas~~effectiveness inof ~~which~~worldwide weconservation ~~operate~~measures;

•· the ~~proximity~~availability, ~~capacity,~~proximity ~~cost~~ and ~~availability~~capacity of ~~gathering~~pipelines, ~~and~~other transportation facilities and processing facilities;

~~• localized and global supply and demand fundamentals and transportation availability;~~ 20

• Table ~~the cost~~ of ~~exploring for, developing, producing and transporting reserves;~~Contents

•· ~~weather~~the ~~conditions~~level and ~~natural~~effect ~~disasters~~of trading in commodity futures markets, including by commodity price speculators and others;

•· ~~technological~~U.S. ~~advances~~exports ~~affecting~~of ~~energy~~oil, ~~consumption~~natural gas, liquefied natural gas and NGL;

•· the price and ~~availability~~level of ~~alternative~~foreign ~~fuels~~imports;

•· ~~expectations~~the ~~about~~nature ~~future~~and ~~commodity~~extent ~~prices;~~of domestic and foreign governmental regulations and taxes;

•· ~~U.S.~~the ~~federal,~~ability ~~state~~of ~~and~~the ~~local~~members of the Organization of Petroleum Exporting Countries to agree to and ~~non-U.S.~~maintain ~~governmental~~oil ~~regulation~~price and ~~taxes.~~production controls;

In· ~~the~~political ~~second~~instability ~~half~~or ofarmed ~~2014,~~conflict ~~oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015, 2016 and~~ in ~~2017, the global~~ oil ~~supply has continued to outpace demand, resulting in persistently low realized prices for oil production. In general, this imbalance between supply~~ and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices will likely remain under pressure. The U.S. dollar has also strengthened relative to other leading currencies, which has caused oil prices to weaken, as they are U.S. dollar-denominated. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for domestic natural gas ~~began~~producing to decline during the third quarter of 2014 and remained weak throughout 2015 and 2016 and much of 2017. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The continued duration and magnitude of these commodity price declines cannot be accurately predicted. Compared to 2014, our realized oil price for 2015 fell 51% to $44.41 per barrel and our realized oil price for the year ended December 31, 2016 further decreased to $41.09 per barrel. For the year ended December 31, 2017, our realized oil price increased to $51.90 per barrel. Similarly, our realized natural gas price for 2015 decreased regions;

31· acts of terrorism; and

~~41%~~· todomestic ~~$2.60 per Mcf,~~ and ~~our~~global ~~realized~~economic ~~price for NGLs declined 49% to $12~~conditions.22 per barrel. For the year ended December 31, 2017, our realized price for natural gas increased to $2.93 per Mcf from $2.44 per Mcf in 2016, and our realized price for NGLs increased to $19.04 per barrel from $12.28 per barrel in 2016.

~~Lower~~ These ~~commodity~~factors ~~prices may reduce our cash flow~~ and ~~borrowing~~the ~~ability.~~volatility Ifof wethe ~~are~~energy ~~unable~~markets tomake ~~obtain~~it ~~needed~~extremely ~~capital~~difficult ~~or financing on satisfactory terms, our ability~~ to ~~develop~~predict future ~~reserves could be adversely affected. Also~~oil, ~~using~~natural ~~lower~~gas ~~prices~~and inNGL ~~estimating~~price ~~proved~~movements ~~reserves~~with ~~may~~any ~~result in a reduction in proved reserve volumes due to economic limits~~certainty. InEven ~~addition, sustained periods~~ with oil, ~~and~~ natural gas ~~prices at levels lower than current WTI or Henry Hub strip prices may adversely affect our drilling economics~~ and ~~our~~NGL ~~ability~~derivatives tocurrently ~~raise~~in ~~capital,~~place ~~which may require us~~ to ~~re-evaluate~~mitigate ~~and~~price ~~postpone~~risks orassociated ~~eliminate~~with ~~our~~a ~~development~~portion ~~program, and result in the reduction~~ of ~~some of~~ our ~~proved~~2019 ~~undeveloped~~cash ~~reserves and related standardized measure. If we are required to curtail our drilling program~~flows, we ~~may~~have besubstantial ~~unable~~exposure to ~~continue~~oil, tonatural ~~hold~~gas ~~leases~~and ~~that~~NGL ~~are~~prices ~~scheduled~~in to2020 ~~expire,~~and ~~which may further reduce our reserves~~beyond. AsIn ~~a result~~addition, a ~~substantial~~prolonged orextension ~~extended~~of ~~decline~~lower ~~in commodity~~ prices ~~may~~could ~~materially~~reduce ~~and~~the ~~adversely~~quantities ~~affect our future business, financial condition, results~~ of ~~operations,~~reserves ~~liquidity~~that ~~and~~we ~~ability~~may toeconomically ~~finance planned capital expenditures~~produce.

Our development projects ~~and acquisitions~~ require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.

The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to our development projects ~~and acquisitions~~. ~~Our 2018 drilling and completion capital budget is $700 million to $800 million, which assumes consummation of the NLA Divestiture.~~ We expect to fund our ~~2018~~2019 capital budget with cash generated by operations and borrowings under our revolving credit facility. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or ~~equity securities or~~ the sale of assets. The issuance of additional indebtedness would require that an additional portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby further reducing our ability to use cash flow from operations to fund working capital, capital expenditures ~~and acquisitions~~. The ~~issuance of additional equity securities would be dilutive to our existing stockholders. The~~ actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things: commodity prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital are subject to a number of variables, including:

•· the prices at which our production is sold;

•· our proved reserves;

•· the amount of hydrocarbons we are able to produce from existing wells;

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

•· the amount of our operating expenses;

•· ~~cash~~limits ~~settlements~~on ~~from~~Chesapeake's ~~our~~ability ~~derivative~~to ~~activities~~make investments in us contained in its credit agreement;

~~• our ability to borrow under our revolving credit facility; and~~ 21

• Table ~~our~~of ~~ability to access the capital markets.~~Contents

If· our revenues or the borrowing base under our revolving credit facility decrease as a result of lower oil, natural gas and NGL prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash ~~flow~~settlements ~~generated~~from by our ~~operations~~derivative oractivities; available borrowings under our revolving credit facility are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in our reserves and ~~production and could materially and adversely affect our business, financial condition and results of operations.~~

~~Part~~· of our ~~business~~ability ~~strategy~~to ~~involves~~borrow ~~using~~under ~~some~~our ofrevolving ~~the~~credit ~~latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application~~facility.

~~Our~~ If ~~operations~~our ~~involve~~revenues ~~utilizing~~or ~~some~~the ofborrowing ~~the~~base ~~latest~~under ~~drilling~~our ~~and~~revolving ~~completion~~credit ~~techniques~~facility decrease as ~~developed~~a byresult usof lower oil, natural gas and NGL prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our ~~service~~operations ~~providers~~at current levels. ~~The~~If ~~difficulties~~additional capital is needed, we ~~face~~may ~~drilling~~not ~~horizontal~~be ~~wells~~able ~~include:~~to obtain debt financing on terms acceptable to us, if at all. If cash flow generated by our operations, available borrowings under our revolving credit facility or investment in us by Chesapeake are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in our reserves and production and could materially and adversely affect our business, financial condition and results of operations.

• landing our wellbore 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 wellbore; and

• being able to run tools and other equipment consistently through the horizontal wellbore.

Difficulties that we face while completing our wells include the following:

• the ability to fracture stimulate the planned number of stages;

• the ability to run tools the entire length of the wellbore during completion operations; and

• the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of 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 and emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our development, production and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

Our decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, which are often inconclusive or subject to varying interpretations. ~~For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate.~~ Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including:

•· delays imposed by, or resulting from, compliance with regulatory requirements, including limitations on wastewater disposal, emission of greenhouse gasses (“GHGs”) and hydraulic fracturing;

•· pressure or irregularities in geological formations;

•· shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

•· equipment failures, accidents or other unexpected operational events;

•· lack of available gathering facilities or delays in construction of gathering facilities;

•· lack of available capacity on interconnecting transmission pipelines;

•· adverse weather conditions;

•· issues related to compliance with environmental regulations;

•· environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•· declines in oil and natural gas prices;

•· limited availability of financing on acceptable terms;

~~• title issues; and~~ 22

• Table ~~other~~of ~~market limitations in our industry.~~Contents

title issues; and

other market limitations in our industry.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our debt obligations that may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including the 2025 Senior Notes and our revolving credit facility, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on the 2025 Senior Notes and our other indebtedness. We are an unrestricted subsidiary of Chesapeake and as such, are limited in our ability to receive investments from, and transact with, Chesapeake. Additionally, if the 2025 Senior Notes are downgraded within 90 days after the consummation of the acquisition of WildHorse (which constitutes a "Change of Control" under the indenture governing the 2025 Senior Notes (the "WildHorse Indenture")), the WildHorse Indenture requires Brazos Valley Longhorn, L.L.C. (or a third party, in certain circumstances) to make an offer to repurchase the 2025 Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, within 30 days of such downgrade.

33 If our cash flow and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on our financial condition at such time. Any refinancing of indebtedness may be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis, including the 2025 Senior Notes, would likely result in a reduction of our credit rating. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The WildHorse Indenture restricts, and our revolving credit facility restricts, our ability to dispose of assets and imposes limitations on our use of proceeds from dispositions. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on the 2025 Senior Notes and our other indebtedness.

If our cash flow and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness may be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis, including the 2025 Senior Notes, would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The indenture governing the 2025 Senior Notes restricts, and our revolving credit facility restricts, our ability to dispose of assets and imposes limitations on our use of proceeds from dispositions. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

The terms and conditions governing our indebtedness:

•· require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;

•· increase our vulnerability to economic downturns and adverse developments in our business;

•· limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

•· place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

•· place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and

~~• limit management’s discretion in operating our business.~~ 23

~~Our~~ Table ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our existing debt, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. For example, our existing and future debt agreements will require that we satisfy certain conditions, including coverage and leverage ratios, to borrow money. Our existing and future debt agreements will also restrict the payment of dividends and distributions by certain of our subsidiaries to us, which could affect our access to cash. In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event of default could adversely affect our business, financial condition and results of operations.Contents

limit management's discretion in operating our business.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our existing debt, sell assets, or borrow more money. We may not be able to refinance our debt, sell assets, or borrow more money on terms acceptable to us, if at all. For example, our existing and future debt agreements will require that we satisfy certain conditions, including coverage and leverage ratios, to borrow money. Our existing and future debt agreements will also restrict the payment of dividends and distributions by certain of our subsidiaries to us, which could affect our access to cash. In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event of default could adversely affect our business, financial condition and results of operations.

Any significant reduction in our borrowing base under the Credit Agreement as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

The Credit Agreement limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, will unilaterally determine based upon projected revenues from our oil, natural gas and NGL properties and our commodity derivative contracts. Such determinations will be made on a regular basis semi-annually (each a “Scheduled Redetermination”), at our option in connection with a material acquisition, at our option no more than twice in any fiscal year and at the option of lenders with more than 66.6% of the loans and commitments under the facility (the “Required Lenders”) no more than twice in any fiscal year (each such redetermination other than a Scheduled Redetermination, an “Interim Redetermination” and any Scheduled Redetermination or Interim Redetermination, a “Redetermination”). In connection with a Redetermination, any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments, and maintaining or any decrease in the borrowing base requires the consent of the Required Lenders. The borrowing base will also automatically decrease upon the issuance of certain debt, the sale or other disposition of certain assets and the early termination of certain swap agreements. Our next Scheduled Redetermination is expected in April ~~2018~~ 2019.

34 In the future, we may not be able to access adequate funding under the Credit Agreement as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a Redetermination, or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a defaulting lender's portion. Declines in commodity prices could result in a determination to lower the borrowing base and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations.

In Increases ~~the future, we may not be able to access adequate funding under the Credit Agreement as a result of a decrease~~ in ~~our~~interest ~~borrowing~~rates base due to the issuance of new indebtedness, the outcome of a Redetermination, or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a defaulting lender’s portion. Declines in commodity prices could ~~result~~adversely inaffect ~~a determination to lower the borrowing base and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement~~ our ~~drilling and development plan, make acquisitions or otherwise carry out~~ business ~~plans, which would have a material adverse effect on our financial condition and results of operations~~.

We require continued access to capital and our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. We expect to use our revolving credit facility to finance a portion of our future growth, and these changes could cause our cost of doing business to increase, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Table of Contents

Our derivative activities could result in financial losses or could reduce our earnings.

We In order to manage our exposure to price volatility, we enter into ~~derivative~~oil, ~~instrument~~natural gas and NGL price derivative contracts. ~~for~~Our aoil, ~~portion~~natural gas and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our oil, ~~and~~ natural gas ~~production~~and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program. As of ~~February~~December 1231, 2018, we had entered into swaps, ~~collars~~ and deferred premium puts through December 2020 covering a total of 1912.09 MMBbls of our projected oil production and 2111.73 TBtu of our projected natural gas production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

•· production is less than the volume covered by the derivative instruments;

•· the counterparty to the derivative instrument defaults on its contractual obligations;

•· there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

•· there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, oil, natural gas and NGL prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs or from reductions in interest rates, which could have a material adverse effect on our financial condition. In addition, the Credit Agreement limits our ability to enter into commodity hedges covering greater than 100% of our reasonably anticipated projected proved production for the first two years of the facility and 75% of reasonably anticipated projected proved production for the following three years.

Our derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’'s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’'s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices or, to the extent we have interest rate derivative instrument contracts, increasing interest rates, our derivative contract receivable positions would generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our derivative contracts.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Table of Contents

development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected and production declines may be greater than we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates of proved reserves to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped reserves will be developed within the periods anticipated.

35 You should not assume that the present value of future net revenues from our reserves presented in this Annual Report is the current market value of our estimated reserves. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2018 and related standardized measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $65.56 per barrel of oil (WTI) and $3.10 per MMBtu of natural gas (Henry Hub spot), which, for certain periods in 2018, were substantially higher than the available spot prices. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

You should not assume that the present value of future net revenues from our reserves presented in this Annual Report is the current market value of our estimated reserves. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2017 and related standardized measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $51.34 per barrel of oil (WTI) and $2.98 per MMBtu of natural gas (Henry Hub spot), which, for certain periods in 2017, were substantially higher than the available spot prices. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated oil and natural gas reserves.

Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires historical twelve-month pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. In addition, WHR II and Esquisto were generally not subject to U.S. federal, state or local income taxes other than certain state franchise taxes and federal income tax on one of our predecessor’s subsidiaries. We are subject to U.S. federal, state and local income taxes. As a result, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the Standardized measure of our estimated reserves included in this Annual Report should not be construed as accurate estimates of the current fair value of our proved reserves.

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, future oil and gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future in connection with the acquisitions or otherwise may not produce as expected. In connection with the assessments, we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as groundwater contamination, when a review is performed. We may be unable 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.

We will not be the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non- operated assets and could be liable for certain financial obligations of the operators or any of our contractors to the extent such operator or contractor is unable to satisfy such obligations.

We have identified 6,069 potential drilling locations on our acreage. We do not expect to operate 1,480 of such locations, and there is no assurance that we will operate all of our other drilling locations. In addition, unless we are successful in increasing our working interest in our other drilling locations through acreage exchanges and consolidation efforts, we will not be the operator with respect to these other identified horizontal drilling locations. We have limited ability to exercise influence over the operations of the drilling locations operated by our partners, and there is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

• the timing and amount of capital expenditures;

• the operator’s expertise and financial resources;

• the approval of other participants in drilling wells;

• the selection of technology; and

• the rate of production of reserves, if any.

This limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities.

Further, we may be liable for certain financial obligations of the operator of a well in which we own a working interest to the extent such operator becomes insolvent and cannot satisfy such obligations. Similarly, we may be liable for certain obligations of our

contractors to the extent such contractor becomes insolvent and cannot satisfy their obligations. The satisfaction of such obligations could have a material adverse effect on our financial condition.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our management and technical teams have specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, the cooperation of other working interest owners and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

As of December 31, 2017, we had identified 4,675 gross horizontal drilling locations on our Eagle Ford Acreage and 1,394 gross horizontal drilling locations on our North Louisiana Acreage. As a result of the limitations described in this Annual Report, we may be unable to drill many of our identified locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “—Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.” Any drilling activities we are able to conduct on these locations may not be successful, may not result in production or additions to our estimated proved reserves and could result in a downward revision of our estimated proved reserves, which could have a material adverse effect on the borrowing base under our revolving credit facility or our future business and results of operations. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations and may be required to reduce our estimated proved reserves, which could reduce the borrowing base under our revolving credit facility. 26

Table of Contents

As a result of the limitations described in this Annual Report, we may be unable to drill many of our identified locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful, may not result in production or additions to our estimated proved reserves and could result in a downward revision of our estimated proved reserves, which could have a material adverse effect on the borrowing base under our revolving credit facility or our future business and results of operations. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations and may be required to reduce our estimated proved reserves, which could reduce the borrowing base under our revolving credit facility.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.

As Leases ofon ~~December~~oil ~~31,~~and ~~2017,~~natural ~~approximately~~gas ~~67%~~properties oftypically ~~our~~have ~~total~~a ~~net~~term ~~acreage~~of ~~was~~three ~~held~~to byfive ~~production.~~years, ~~The~~after ~~leases~~which ~~for~~they ~~our~~expire ~~net~~unless, ~~acreage~~prior ~~not~~to ~~held~~expiration, bya ~~production~~well ~~will~~is ~~expire~~drilled atand ~~the~~production ~~end~~ of ~~their~~hydrocarbons ~~primary term unless production is established~~ in paying quantities ~~under~~is ~~the~~established. ~~units~~If ~~containing~~our ~~these~~ leases oron ~~the leases are renewed. For example, as of December 31, 2017, approximately 14% and 11% of~~ our ~~net~~ undeveloped ~~acreage~~properties ~~was set to~~ expire ~~in 2018~~ and ~~2019, respectively. If our leases expire and~~ we are unable to renew the leases, we will lose our right to develop the related properties. Although we ~~intend~~seek to ~~extend~~actively ~~substantially~~manage ~~all of~~ our ~~net~~undeveloped ~~acreage associated with identified drilling locations through a combination of development drilling~~properties, ~~the payment of pre-agreed leasehold extension and renewal payments pursuant to an option to extend or the negotiation of lease extensions, we may not be successful in extending~~ our ~~leases.~~drilling Additionally, where we do not have options to extend a lease, we may not be successful in negotiating extensions or renewals or any payments related to such extensions or renewals may be more than anticipated. Please see “Item 1. Business—Development of Proved Undeveloped Reserves—Undeveloped Acreage Expirations” for more information regarding acreage expirations and our plans for ~~extending~~these ~~and~~areas ~~renewing~~are ~~our~~subject ~~acreage. Our ability~~ to ~~drill~~change ~~and~~based ~~develop~~upon ~~our~~various ~~acreage~~factors, ~~and~~including ~~establish~~drilling ~~production to maintain our leases depends on a number of uncertainties~~results, ~~including~~ oil, and natural gas ~~and NGL~~ prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, ~~drilling results, lease expirations,~~ gathering system and pipeline transportation constraints, ~~access~~and toregulatory ~~and~~approvals. ~~availability~~Low ofcommodity ~~water~~prices ~~sourcing~~may cause us to delay our drilling plans and, ~~distribution~~as ~~systems~~a result, ~~regulatory~~lose ~~approvals~~our ~~and~~right ~~other~~to ~~factors~~develop the related properties.

~~Adverse~~ Unless ~~weather~~we ~~conditions~~replace ~~may~~our ~~negatively~~reserves ~~affect~~with ~~our~~new ~~operating~~reserves ~~results~~and develop those new reserves, our reserves and production will decline, which would adversely affect our ~~ability~~future tocash ~~conduct~~flows ~~drilling~~and ~~activities~~results of operations.

~~Adverse~~ Producing ~~weather~~oil ~~conditions~~and ~~may~~natural ~~cause,~~gas ~~among~~reservoirs ~~other~~generally ~~things,~~are ~~increases~~characterized inby ~~the~~declining ~~costs~~production ~~of,~~rates that vary depending upon reservoir characteristics and ~~delays~~other ~~in,~~factors. ~~drilling~~Unless we conduct successful ongoing exploration and development activities or ~~completing~~continually ~~new~~acquire ~~wells,~~properties ~~power~~containing ~~failures~~proved reserves, ~~temporary~~our ~~shut-in~~proved ofreserves will decline as those reserves are produced. Our future reserves and production, and ~~difficulties~~therefore inour ~~the~~future ~~transportation~~cash flow and results of operations, are highly dependent on our ~~oil,~~success ~~natural~~in ~~gas~~efficiently developing our current reserves and ~~NGLs~~economically finding or acquiring additional recoverable reserves. ~~Any~~We ~~decreases~~may innot ~~production~~be ~~due~~able to ~~poor~~develop, ~~weather~~find ~~conditions~~or ~~will~~acquire ~~have~~sufficient anadditional ~~adverse~~reserves ~~effect~~to onreplace our ~~revenues~~current and future production. If we are unable to replace our current and future production, ~~which~~the ~~will~~value inof ~~turn~~our ~~negatively~~reserves ~~affect~~will decrease, and our ~~cash~~business, ~~flow~~financial ~~from~~condition and results of operations would be materially and adversely affected.

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 oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in our areas of operation in past years. These drought conditions have led governmental authorities to restrict the use of water, subject to their jurisdiction, for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

37 Our producing properties are located in the Eagle Ford Shale, making us vulnerable to risks associated with operating in a limited geographic area.

~~Following~~ All of our producing properties and estimated proved reserves are geographically concentrated in the ~~consummation~~Eagle ofFord Shale. As a result, we may be disproportionately exposed to the ~~NLA~~impact ~~Divestiture~~of regional supply and demand factors, ~~our~~delays ~~producing~~or ~~properties~~interruptions ~~will~~of beproduction ~~located~~from wells in the Eagle Ford Shale caused by governmental regulation, ~~making~~processing usor ~~vulnerable~~transportation tocapacity ~~risks~~constraints, ~~associated~~market ~~with~~limitations, ~~operating~~availability inof aequipment ~~limited~~and ~~geographic~~personnel, ~~area~~water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

Following the consummation of the NLA Divestiture, all of our producing properties will be geographically concentrated in the Eagle Ford. At December 31, 2017, all of our total estimated proved reserves were attributable to properties located in the Eagle Ford and in North Louisiana. However, the sale of our NLA Assets, which includes all of our assets in North Louisiana, is expected to close by the end of March 2018. As a result of, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in the Eagle Ford caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. 27

Table of Contents

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 systems. The oil is then transported by us or the purchaser by truck to a transportation facility. Our natural gas production is generally transported by our or third-party gathering lines from the wellhead to a gas processing facility or transmission pipeline. 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. 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. Any such shut-in or curtailment, or an inability to obtain favor able terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

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

The existence of a material title deficiency can render a lease worthless and adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.

As of December 31, ~~2017~~2018, approximately 7576.5% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Estimated future development costs relating to the development of our PUDs at December 31, ~~2017~~2018 are approximately $35.8505 billion over the next five years. We expect to fund these expenditures through cash generated by operations, borrowings under our revolving credit facility and other sources of capital. Our ability to fund these expenditures is subject to a number of risks. See “—Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.” Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Furthermore, there is no certainty that we will be able to convert our PUDs to developed reserves or that our undeveloped reserves will be economically viable or technically feasible to produce.

Further, SEC rules require that, subject to limited exceptions, PUDs 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 PUDs as we pursue our drilling program. As a result, we may be required to write down our PUDs if we do not drill those wells within the required five-year timeframe.

Certain factors could require us to write-down the carrying values of our properties, including commodity prices decreasing to a level such that our future undiscounted cash flows from our properties are less than their carrying value. 28

~~Accounting~~ Table ~~rules require that we periodically review the carrying value~~ of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash impairment charge to earnings. Commodity prices dropped significantly from 2014 highs of $107.95 per barrel of oil and $8.15 per MMBtu for natural gas down to lows of $26.19 per barrel of oil in February 2016 and $1.49 per MMBtu in March 2016. Since 2016, prices have generally increased. On February 26, 2018, the WTI spot price for crude oil was $63.81 per barrel and the Henry Hub spot price for natural gas was $2.60 per MMBtu.Contents

38 Certain factors could require us to write down the carrying values of our properties, including commodity prices decreasing to a level such that our future undiscounted cash flows from our properties are less than their carrying value.

~~Likewise,~~ We ~~NGLs~~periodically ~~have~~review ~~suffered~~the ~~significant~~carrying ~~recent~~value ~~declines~~of inour ~~realized~~properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash impairment charge to earnings. Lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. AsFor aexample, ~~result~~during ofthe ~~lower~~first ~~commodity~~quarter ~~prices~~of 2018, we ~~recorded~~impaired our North Louisiana properties for $9214.3 million, ofwhich ~~impairment~~we ~~expense~~divested ~~during~~at the ~~year~~end ~~ended~~of ~~December~~March ~~31, 2015~~2018. We could experience further material write- downs as a result of lower commodity prices or other factors, including low production results or high lease operating expenses, capital expenditures or transportation fees.

~~Unless~~ The weCompany's ~~replace~~sand ~~our~~mining ~~reserves~~operations ~~with~~are ~~new~~subject ~~reserves~~to ~~and~~the ~~develop~~Federal ~~those~~Mine ~~new~~Safety ~~reserves,~~and ~~our~~Health ~~reserves~~Act ~~and~~of ~~production~~1977 ~~will~~and ~~decline~~amending legislation, which ~~would~~impose ~~adversely~~stringent ~~affect~~health ~~our~~and ~~future~~safety ~~cash~~standards ~~flows~~on ~~and~~numerous ~~results~~aspects of the Company's sand mining operations.

~~Producing~~ The ~~oil~~Company's ~~and~~sand ~~natural~~mining ~~gas~~operations ~~reservoirs~~are ~~generally~~subject ~~are~~to ~~characterized~~the byFederal ~~declining~~Mine ~~production~~Safety ~~rates~~and ~~that~~Health ~~vary~~Act ~~depending~~of ~~upon~~1977, ~~reservoir~~as ~~characteristics~~amended by the Mine Improvement and ~~other~~New ~~factors.~~Emergency ~~Unless~~Response weAct ~~conduct~~of ~~successful~~2006, ~~ongoing~~which ~~exploration~~imposes ~~and~~stringent ~~development~~health ~~activities~~and orsafety ~~continually~~standards ~~acquire~~on ~~properties~~numerous ~~containing~~aspects ~~proved~~of ~~reserves,~~mineral ~~our~~extraction ~~proved~~and ~~reserves~~processing ~~will~~operations, ~~decline~~including asthe ~~those~~training ~~reserves~~of ~~are~~personnel, ~~produced.~~operating ~~Our~~procedures, ~~future~~operating ~~reserves~~equipment and ~~production~~other matters. This Act, ~~and~~as ~~therefore~~amended, ~~our~~is ~~future~~a ~~cash~~strict ~~flow~~liability statute and ~~results~~any offailure ~~operations,~~by ~~are~~the ~~highly~~Company ~~dependent~~to oncomply ~~our~~with ~~success~~such inexisting ~~efficiently~~or ~~developing~~any ~~our~~future ~~current~~standards, ~~reserves~~or ~~and~~any ~~economically~~more ~~finding~~stringent interpretation or ~~acquiring~~enforcement ~~additional~~thereof, ~~recoverable~~could ~~reserves.~~have Wea ~~may~~material ~~not~~adverse beeffect ~~able~~on tothe ~~develop,~~Company's ~~find~~sand mining operations or ~~acquire~~otherwise ~~sufficient~~impose ~~additional~~significant ~~reserves~~restrictions on the Company's ability to ~~replace~~conduct ~~our~~mineral ~~current~~extraction and ~~future~~processing ~~production~~operations. IfIn weaddition, ~~are~~the ~~unable~~Mine toSafety ~~replace~~and ~~our~~Health ~~current~~Administration ~~and~~("MSHA") ~~future~~may ~~production,~~propose ~~the~~changes ~~value~~in oftheir ~~our~~regulations ~~reserves~~regarding ~~will~~workplace ~~decrease,~~exposure ~~and~~to ~~our~~crystalline ~~business~~silica, ~~financial~~such ~~condition~~as permissible exposure limits and ~~results~~required ofcontrols ~~operations~~and ~~would~~personal beprotective ~~materially~~equipment. If any new rule issued by MSHA lowers the workplace exposure limit significantly, the Company could incur significant capital and ~~adversely~~operating ~~affected~~expenditures for equipment to reduce this exposure.

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

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

We depend upon a small number of significant purchasers for the sale of most of our oil, natural gas and NGL production.

We normally sell our production to a relatively small number of customers, as is customary in our business. For the year ended December 31, 2017, there were two purchasers who accounted for an aggregate 56% and 21%, respectively, of our total revenue. No other purchaser accounted for 10% or more of our revenues. The loss of any such greater than 10% purchaser as a purchaser could adversely affect our revenues in the short term. See “Item 1. Business—Our Operations—Marketing and Customers” for additional information.

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

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict liability (i.e., no showing of “fault” is required) as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly owned or 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 connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In certain instances, citizen groups also have the ability to bring legal proceedings against us if we are not in compliance with environmental laws, or to challenge our ability to receive environmental permits that we need to operate. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. 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.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

•· environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

•· abnormally pressured formations;

•· mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

•· fires, explosions and ruptures of pipelines;

•· personal injuries and death;

•· natural disasters; and

•· terrorist attacks targeting oil and natural gas related facilities and infrastructure.

Table of Contents

Any of these events could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

•· injury or loss of life;

•· damage to and destruction of property, natural resources and equipment;

•· pollution and other environmental damage;

•· regulatory investigations and penalties; and

•· repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Our business is difficult to evaluate because we have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion.

WHR II and Esquisto were formed in 2013 and 2014, respectively. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

In addition, we have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. Additionally, the following factors could present difficulties:

• increased responsibilities for our executive level personnel;

• increased administrative burden;

• increased capital requirements; and

• increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.

Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other 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 commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

•· unexpected drilling conditions;

•· title issues;

•· pressure or lost circulation in formations;

•· equipment failures or accidents;

•· adverse weather conditions;

•· compliance with environmental and other governmental or contractual requirements; and

•· increases in the cost of, and shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.

The success of completed acquisitions 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.

In addition, the agreements governing our indebtedness impose certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness, which could indirectly limit our ability to acquire assets and businesses.

Our pending NLA Divestiture may not be consummated.

Our pending NLA Divestiture is expected to close by the end of March 2018 and is subject to customary closing conditions. If these conditions are not satisfied or waived, the NLA Divestiture will not be consummated. If the closing of the NLA Divestiture is substantially delayed or does not occur at all, or if the terms of the NLA Divestiture are required to be modified substantially, we may not realize the anticipated benefits of the NLA Divestiture fully or at all. Certain of the conditions remaining to be satisfied include:

• the continued accuracy of the representations and warranties contained in the Purchase and Sale Agreement;

• the performance by each party of its obligations under the Purchase and Sale Agreement;

• the absence of any order from any governmental authority that enjoins, restrains or otherwise prohibits, or of any law being enacted that would enjoin or prohibit, the consummation of the transactions contemplated in the Purchase and Sale Agreement; and

• the absence of any material suit, action, litigation or other proceeding instituted by any governmental authority that seeks to restrain, prohibit, enjoin or declare illegal, or seeking substantial damages in connection with, the consummation of the transactions contemplated in the Purchase and Sale Agreement.

The parties may terminate the Purchase and Sale Agreement by mutual written consent or if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or approximately $43 million, or if the transaction has not closed on or before April 30, 2018.

Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.

Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from the drilling of wells.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis. 30

~~The~~ Table demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil, natural gas and NGL prices, causing periodic shortages of supplies and needed personnel. Our operations are concentrated in areas in which oilfield activity levels had increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, had increased, as did the costs for those items. However, beginning in the second half of 2014, commodity prices began to decline and the demand for goods and services subsided due to reduced activity. To the extent that commodity prices improve in the future, the demand for and prices of these goods and services are likely to increase and we could encounter delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to resume or increase our development activities, which could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.Contents

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and natural gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

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 NGA exempts natural gas gathering facilities from regulation by the FERC, as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services 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. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulation may have on our activities. Such regulations may have a material adverse effect on our financial condition, result of operations and cash flows.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

42 We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.

~~business~~ Our operations are subject to extensive federal, ~~operating~~state, ~~results~~tribal, local and ~~financial~~other ~~condition.~~laws, ~~Accruals~~rules ~~for~~and ~~such~~regulations, ~~liability~~including with respect to environmental matters, ~~penalties~~worker orhealth ~~sanctions~~and ~~may~~safety, bewildlife ~~insufficient~~conservation, the gathering and ~~judgments~~transportation of oil, gas and ~~estimates~~NGLs, toconservation ~~determine~~policies, ~~accruals~~reporting orobligations, ~~range~~royalty payments, unclaimed property and the imposition of ~~losses~~taxes. ~~related~~Such regulations include requirements for permits to ~~legal~~drill and to conduct other ~~proceedings~~operations ~~could~~and ~~change~~for ~~from~~provision ~~one~~of ~~period~~financial toassurances ~~the~~(such ~~next~~as bonds) covering drilling, completion and ~~such~~well ~~changes~~operations. ~~could~~If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be ~~material~~able to conduct our operations as planned. In addition, we may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.

~~Climate~~ In ~~change~~addition, ~~laws~~changes in public policy have affected, and ~~regulations~~in ~~restricting~~the ~~emissions~~future ofcould ~~GHGs~~further affect, our operations. Regulatory changes could, ~~result~~among inother ~~increased~~things, restrict production levels, impose price controls, alter environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and ~~reduced~~regulations ~~demand~~are ~~for~~revised ~~the~~or ~~oil~~reinterpreted or if new laws and ~~natural~~regulations ~~gas~~become applicable to our operations. We do not expect that weany ~~produce~~of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, ~~while~~size ~~potential~~and ~~physical~~financial ~~effects~~strength. Although ofwe ~~climate~~are ~~change~~unable to predict changes to existing laws and regulations, such changes could ~~disrupt~~significantly impact our ~~production~~profitability, financial condition and ~~cause~~liquidity. As usis todiscussed ~~incur~~below ~~significant~~this ~~costs~~is inparticularly ~~preparing~~true ~~for~~of orchanges ~~responding~~related to ~~those~~pipeline ~~effects~~safety, seismic activity, hydraulic fracturing, climate change and endangered species designations.

Pipeline Safety. The ~~EPA~~pipeline ~~has~~assets ~~determined~~in ~~that~~which ~~emissions~~we ofown ~~carbon~~interests ~~dioxide,~~are ~~methane~~subject ~~and~~to ~~other~~stringent ~~GHGs~~and ~~present~~complex anregulations ~~endangerment~~related to ~~public~~pipeline ~~health~~safety and ~~the~~integrity ~~environment~~management. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has ~~adopted~~established ~~regulations~~a ~~pursuant~~series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the ~~federal~~event ~~Clean~~of ~~Air~~a ~~Act~~failure, could affect “high consequence areas.” Additional action by PHMSA with respect to ~~reduce~~pipeline ~~GHG~~integrity ~~emissions~~management ~~from~~requirements ~~various~~may ~~sources~~occur in the future. For example, ~~the~~in ~~EPA~~2016 ~~requires~~PHMSA ~~certain~~proposed ~~large~~new ~~stationary~~rules ~~sources~~for gas pipelines that extend pipeline safety programs beyond high consequence areas to ~~obtain~~newly ~~preconstruction~~proposed “moderate consequence areas or rural areas” and ~~operating~~would ~~permits~~also impose more rigorous testing and reporting requirements on such pipelines. Elements of a final rulemaking, commonly referred to as the “Gas Mega Rule,” continues to be deliberated by PHMSA’s Gas Pipeline Advisory Committee (GPAC). To date, no final regulatory action has been taken. More recently, in January 2017, PHMSA finalized regulations for ~~pollutants~~hazardous ~~regulated~~liquid ~~under~~pipelines that significantly extend and expand the ~~Prevention~~reach of ~~Significant~~certain ~~Deterioration~~PHMSA ~~and~~integrity ~~Title~~management Vrequirements ~~programs~~(i.e., periodic assessments, leak detection and repairs), regardless of the ~~Clean~~pipeline’s ~~Air~~proximity ~~Act~~to a high consequence area. ~~Facilities~~The ~~required~~final torule ~~obtain~~also ~~preconstruction~~imposes ~~permits~~new reporting requirements for ~~such~~certain ~~pollutants~~unregulated ~~are~~pipelines, ~~also~~including ~~required~~all tohazardous ~~meet~~liquid ~~“best~~gathering ~~available~~lines. ~~control~~Per ~~technology~~direction provided via a “Regulatory Freeze” ~~standards~~Memo ~~that~~published ~~are~~on ~~being~~January ~~established~~20, 2017 by the ~~states.~~Trump ~~These~~Administration, this final regulatory action was withdrawn and continues to be evaluated by executive leadership. In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements ~~could~~for ~~adversely~~natural ~~affect~~gas ~~our~~transmission ~~operations~~pipelines, and ~~restrict~~particularly orthe ~~delay~~actions ~~our~~operators ~~ability~~must totake ~~obtain~~when ~~air~~class ~~permits~~locations ~~for~~change ~~new~~due to population growth or ~~modified~~building ~~sources~~construction near the pipeline. At this time, we cannot predict the cost of these requirements or other potential

The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. In June 2016, the EPA published performance standards that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas sector, including production, processing, transmission and storage activities. Compliance will require enhanced record-keeping practices, the purchase of new equipment and could result in the increased frequency of maintenance and repair activities to address emissions leakage at well sites and compressor stations, and also may require additional personnel time to support these activities or the engagement of third-party contractors to assist with and verify compliance. Several states and industry groups have filed suit before the D.C. Circuit challenging the EPA’s implementation of the methane rule and legal authority to issue the methane rule. However, over the past year the EPA has taken several steps to delay implementation of the June 2016 methane rule, and the agency proposed a separate rulemaking in June 2017 to stay the methane requirements for a period of two years and revisit implementation of the standards in their entirety. The EPA has not yet published a final rule but, even though the rule is currently in effect, future implementation and enforcement of the 2016 standards is uncertain at this time. 31

~~There~~ Table ~~has been no significant activity with respect to federal legislation to reduce GHG emissions in recent years. In the absence~~ of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes, or encouraging the use of renewable energy or alternative low-carbon fuels. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States signed the Paris Agreement, which requires member nations to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement, which entered into force in November 2016, includes non-binding pledges to limit or reduce future emissions. However, in June 2017, the President stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, resulting in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.Contents

~~Although~~new ~~it is not possible at this time to predict how legislation~~ or ~~new~~amended regulations ~~that may be adopted to address GHG emissions would impact our business~~, ~~any~~but ~~such~~they ~~future~~could ~~laws~~be ~~and~~significant. ~~regulations imposing reporting obligations on~~Moreover, orviolations ~~limiting emissions~~ of ~~GHGs~~pipeline ~~from,~~safety ~~our~~regulations ~~equipment~~can ~~and~~result ~~operations~~in could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as delay or restrict our ability to permit GHG emissions from new or modified sources. Substantial limitations on GHG emissions could adversely affect demand for the ~~oil~~imposition ~~and natural gas we produce and lower the value~~ of ~~our~~significant ~~reserves~~penalties.

~~Recently,~~ Seismic ~~activists~~Activity. ~~concerned~~Earthquakes ~~about the potential effects of climate change~~ have ~~directed~~prompted ~~their~~concerns ~~attention~~about atseismic ~~sources~~activity ~~of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds~~ and ~~other~~possible ~~sources~~relationships ofwith ~~capital~~the ~~restricting~~energy ~~or eliminating their investment in oil and natural gas activities~~industry. ~~Ultimately,~~Legislative ~~this could make it more difficult to secure funding for exploration~~ and ~~production~~regulatory ~~activities.~~initiatives ~~Notwithstanding~~intended ~~potential risks related~~ to ~~climate~~address ~~change,~~these ~~the~~concerns ~~International~~may ~~Energy~~result ~~Agency~~in ~~estimates~~additional ~~that~~levels ~~global~~of ~~energy~~regulation ~~demand~~or ~~will~~other ~~continue~~requirements ~~to rise and will not peak until after 2040 and~~ that ~~oil~~could ~~and~~lead ~~gas will continue~~ to ~~represent~~operational ~~a substantial percentage of global energy use over that time. Finally~~delays, ~~increasing~~increase ~~concentrations~~our ofoperating ~~GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency~~ and ~~severity~~compliance ofcosts ~~storms,~~or ~~floods~~otherwise ~~and~~adversely ~~other~~affect ~~climatic events; if any such effects were to occur, they could have a material adverse effect on~~ our operations.

43 Hydraulic Fracturing. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. Three states (New York, Maryland and Vermont) have banned the use of high volume hydraulic fracturing. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. There have also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. The government may continue to study hydraulic fracturing. We cannot predict the outcome of future studies, but based on the results of these studies, federal and state legislatures and agencies may seek to further regulate or even ban hydraulic fracturing activities. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected.

~~Federal~~ We cannot predict whether additional federal, state ~~and~~or local ~~legislative~~laws ~~and~~or ~~regulatory~~regulations ~~initiatives~~applicable ~~relating~~ to hydraulic fracturing aswill ~~well~~be asenacted ~~governmental~~in ~~reviews~~the offuture and, if so, what actions any such ~~activities~~laws ~~could~~or ~~result~~regulations inwould ~~increased~~require ~~costs~~or ~~and~~prohibit. If additional ~~operating~~levels ~~restrictions~~of regulation or ~~delays~~permitting inrequirements ~~the~~were ~~completion~~imposed ofon ~~oil~~hydraulic fracturing operations, our business and ~~natural~~operations ~~gas~~could ~~wells~~be subject to delays, increased operating and ~~adversely~~compliance ~~affect~~costs ~~our~~and ~~production~~potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.

~~Hydraulic~~ Climate ~~fracturing~~Change. isContinuing anpolitical ~~important~~ and ~~common~~social ~~practice~~attention ~~that~~to isthe ~~used~~issue toof ~~stimulate~~climate ~~production~~change ofhas ~~oil~~resulted in legislative, regulatory and~~/or~~ ~~natural~~other initiatives to reduce greenhouse gas ~~from~~emissions, ~~dense~~such ~~subsurface~~as ~~rock~~carbon ~~formations.~~dioxide ~~The~~and ~~hydraulic~~methane. ~~fracturing~~Policy ~~process~~makers ~~involves~~at both the ~~injection~~U.S. offederal ~~water,~~and ~~proppants~~state ~~and~~levels ~~chemicals~~have ~~under~~introduced ~~pressure~~legislation ~~into~~and ~~targeted~~proposed ~~subsurface~~new ~~formations~~regulations designed to ~~fracture~~quantify and limit the ~~surrounding~~emission ~~rock~~of greenhouse gases through inventories, limitations and/or ~~stimulate~~taxes ~~production~~on greenhouse gas emissions. WeEPA ~~regularly~~and ~~use~~the ~~hydraulic~~BLM ~~fracturing~~have asissued ~~part~~regulations for the control of ~~our~~methane ~~operations.~~emissions, ~~Hydraulic~~which ~~fracturing~~also isinclude ~~typically~~leak ~~regulated~~detection byand ~~state~~repair requirements, for the oil and ~~natural~~ gas ~~commissions~~industry; however, ~~but~~following ~~certain~~the ~~federal~~change in presidential administrations, both agencies ~~have~~took ~~asserted~~actions ~~regulatory~~to ~~authority~~rescind ~~over~~or revise the rules. In September 2018, BLM issued a final rule that rescinded certain ~~aspects~~requirements of ~~the~~its ~~process~~venting and flaring rule. Similarly, ~~For~~in ~~example~~October 2018, ~~the~~EPA published a proposed rule that amends certain requirements of its methane rule. The EPA ~~has~~rule ~~asserted~~remains ~~federal~~in ~~regulatory~~effect. Nevertheless, ~~authority~~several ~~pursuant~~states towhere ~~the~~we ~~federal~~operate ~~Safe~~have ~~Drinking~~imposed ~~Water~~venting ~~Act~~and ~~(“SDWA”)~~flaring ~~over~~limitations ~~certain~~designed ~~hydraulic~~to ~~fracturing~~reduce ~~activities~~methane ~~involving~~emissions ~~the~~from ~~use~~oil ofand ~~diesel~~gas ~~fuels~~exploration and ~~published~~production ~~permitting~~activities. ~~guidance~~Legislative inand ~~February~~state ~~2014~~initiatives ~~addressing~~to date have generally focused on the ~~performance~~development of ~~such~~cap-and-trade ~~activities~~and/or ~~using~~carbon ~~diesel~~tax ~~fuels~~programs. ~~The~~Cap ~~EPA~~and ~~has~~trade ~~also~~programs ~~issued~~offer ~~final~~greenhouse ~~regulations~~gas ~~under~~emission ~~the~~allowances ~~federal~~that ~~Clean~~are ~~Air~~gradually ~~Act~~reduced ~~establishing~~over ~~performance~~time. ~~standards,~~A ~~including~~cap ~~standards~~and ~~for~~trade program could impose direct costs on us through the ~~capture~~purchase of ~~air~~allowances ~~emissions~~and ~~released~~could ~~during~~impose ~~hydraulic~~indirect ~~fracturing,~~costs ~~and~~by ~~also~~incentivizing ~~finalized~~consumers ~~rules~~to inshift ~~June~~away ~~2016~~from ~~that~~fossil ~~prohibit~~fuels. A ~~the~~carbon ~~discharge~~tax could directly increase our costs of ~~wastewater~~operation ~~from~~and ~~hydraulic~~similarly ~~fracturing~~incentivize ~~operations~~consumers to ~~publicly~~shift ~~owned~~away ~~wastewater~~from ~~treatment~~fossil ~~plants~~fuels.

In ~~December 2016~~addition, ~~the~~activists ~~EPA~~concerned ~~released~~about ~~its final report on~~ the potential ~~impacts~~effects of ~~hydraulic~~climate ~~fracturing~~change onhave ~~drinking~~directed ~~water~~their ~~resources.~~attention ~~The~~at ~~EPA~~sources ~~report~~of ~~concluded~~funding ~~that~~for ~~“water~~fossil-fuel ~~cycle”~~energy ~~activities~~companies, ~~associated~~which ~~with~~has ~~hydraulic~~resulted ~~fracturing~~in ~~may~~certain ~~impact~~financial ~~drinking water resources “under some circumstances~~institutions,” ~~noting~~funds ~~that the following hydraulic fracturing water cycle activities~~ and ~~local-~~other orsources ~~regional-scale~~of ~~factors~~capital ~~are~~restricting ~~more likely than others to result in more frequent~~ or ~~more~~eliminating ~~severe~~their ~~impacts:~~investment ~~water withdrawals for fracturing~~ in ~~times~~oil orand ~~areas~~natural ofgas ~~low~~activities. ~~water availability; surface spills during the management of fracturing fluids~~Ultimately, ~~chemicals~~this orcould ~~produced~~make ~~water;~~it ~~injection~~more ofdifficult ~~fracturing~~to ~~fluids~~secure ~~into~~funding ~~wells~~for ~~with~~exploration ~~inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters;~~ and ~~disposal~~production ~~or storage of fracturing wastewater in unlined pits~~activities.

At These ~~the~~various ~~state level~~legislative, ~~several~~regulatory ~~states~~and ~~have~~other ~~adopted~~activities oraddressing ~~are~~greenhouse ~~considering~~gas ~~legal~~emissions ~~requirements that~~ could ~~impose~~adversely ~~more~~affect ~~stringent~~our ~~permitting~~business, ~~disclosure~~including ~~and~~by ~~well~~imposing ~~construction~~reporting ~~requirements~~obligations on, ~~hydraulic~~or ~~fracturing~~limiting ~~activities.~~emissions ~~For~~of ~~example~~greenhouse gases from, inour ~~May~~equipment ~~2013~~and operations, ~~the~~which ~~Railroad~~could ~~Commission~~require ~~issued~~us ato ~~“well~~incur ~~integrity~~costs ~~rule,”~~to ~~which~~reduce ~~updates~~emissions ~~the~~of ~~requirements~~greenhouse ~~for~~gases ~~drilling,~~associated ~~putting~~with ~~pipe~~our ~~down~~operations. ~~and~~Limitations ~~cementing~~on ~~wells.~~greenhouse ~~The~~gas ~~rule~~emissions could also ~~includes~~adversely ~~new~~affect ~~testing~~demand ~~and~~for ~~reporting~~oil ~~requirements~~and gas, ~~such~~which ascould ~~(i)~~lower the ~~requirement~~value toof ~~submit~~our ~~cementing~~reserves ~~reports~~and ~~after~~have ~~well~~a ~~completion~~material oradverse ~~after~~effect ~~cessation~~on ofour ~~drilling~~profitability, ~~whichever~~financial iscondition ~~later~~and liquidity. Furthermore, ~~and~~increasing ~~(ii)~~attention ~~the~~to ~~imposition~~climate ofchange ~~additional~~risks ~~testing~~has onresulted ~~wells~~in ~~less~~increased ~~than~~likelihood ~~1,000~~of ~~feet~~governmental ~~below~~investigations ~~usable~~and ~~groundwater.~~private ~~The~~litigation, ~~well~~which ~~integrity~~could ~~rule~~increase ~~took~~our ~~effect~~costs inor ~~January~~otherwise ~~2014~~adversely affect our business.

Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells. 32

~~Legislation~~ Table ~~or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose~~ of ~~produced water gathered from such activities, which could have a material adverse effect on our business.~~Contents

~~State~~ Endangered ~~and~~Species. ~~federal~~The ~~regulatory~~Endangered ~~agencies~~Species ~~have~~Act ~~recently~~(ESA) ~~focused~~prohibits onthe ataking ~~possible~~of ~~connection~~endangered ~~between~~or ~~the~~threatened ~~hydraulic~~species ~~fracturing~~or ~~related~~their ~~activities,~~habitats. ~~particularly~~While ~~the~~some ~~underground~~of ~~injection~~our ofassets ~~wastewater~~and ~~into~~lease ~~disposal~~acreage ~~wells,~~may ~~and~~be ~~the~~located ~~increased~~in ~~occurrence~~areas ofthat ~~seismic~~are ~~activity,~~designated ~~and~~as ~~regulatory~~habitats ~~agencies~~for atendangered ~~all~~or ~~levels~~threatened ~~are~~species, ~~continuing~~we tobelieve ~~study~~that ~~the~~we ~~possible~~are ~~linkage~~in ~~between~~material ~~oil~~compliance ~~and~~with ~~gas~~the ~~activity~~ESA. ~~and~~However, ~~induced~~the ~~seismicity.~~designation ~~For~~of ~~example,~~previously inunidentified ~~2015,~~endangered ~~the~~or ~~United~~threatened ~~States~~species ~~Geological~~in ~~Study~~areas ~~identified~~where ~~eight~~we ~~states,~~intend ~~including~~to ~~Texas,~~conduct ~~with~~construction ~~areas~~activity ofor ~~increased~~the ~~rates~~imposition of ~~induced~~seasonal ~~seismicity~~restrictions ~~that~~on ~~could~~our beconstruction ~~attributed~~or tooperational ~~fluid~~activities ~~injection~~could ormaterially ~~oil~~limit ~~and~~or ~~gas~~delay ~~extraction~~our plans.

In The ~~addition,~~taxation ~~a number~~ of ~~lawsuits~~independent ~~have~~producers ~~been~~is ~~filed~~subject ~~in other states, most recently in Oklahoma, alleging that disposal well operations have caused damage~~ to ~~neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns~~change, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and ~~the~~changes ~~use of such wells. For example,~~ in ~~October~~tax ~~2014,~~law ~~the~~could ~~Railroad~~increase ~~Commission~~our ~~published~~cost ~~a new rule governing permitting or re-permitting~~ of ~~disposal~~doing wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in questionbusiness. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Railroad Commission has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in. For example, in September 2016 the Oklahoma Corporations Commission ordered that all disposal wells with a certain proximity to a particular earthquake in central Oklahoma be shut in.

We ~~dispose~~are ofsubject ~~large~~to ~~volumes~~taxation ~~of produced water gathered from our drilling and production operations~~ by ~~injecting~~various ittaxing ~~into~~authorities ~~wells~~at ~~pursuant~~the tofederal, ~~permits~~state ~~issued~~and tolocal uslevels bywhere ~~governmental~~we ~~authorities~~do ~~overseeing such disposal activities~~business. ~~While~~New ~~these~~legislation ~~permits~~increasing ~~are~~our ~~issued~~tax ~~pursuant~~burden ~~to existing laws and regulations, these legal requirements are subject to change, which~~ could ~~result~~be inenacted ~~the~~by ~~imposition~~any of ~~more~~these ~~stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or~~ governmental authorities ~~regarding~~making ~~such~~it ~~gathering~~more orcostly ~~disposal~~for ~~activities.~~us ~~The adoption and implementation of any new laws or regulations that restrict our ability~~ to ~~use~~explore ~~hydraulic~~for ~~fracturing~~oil ~~or dispose of produced water gathered from our drilling~~ and ~~production~~natural gas resources.

activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties for acquisitions and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ greater financial, technical and personnel resources than we do. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has historically continually increased due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

~~NGP,~~ Our ~~Carlyle~~business ~~and~~could ~~their~~be ~~respective~~adversely ~~affiliates~~affected ~~are~~by ~~not~~cyber-security ~~limited~~threats ~~in their ability to compete with us, which could cause conflicts of interest~~ and ~~limit~~related ~~our ability to acquire additional assets or businesses~~disruptions.

Our ~~governing~~business ~~documents~~has ~~provide~~become ~~that~~increasingly ~~NGP~~dependent ~~and~~on ~~its~~digital ~~affiliates~~technologies ~~(including~~to ~~NGP~~conduct certain exploration, development and ~~its~~production ~~affiliates’~~activities. ~~portfolio~~We ~~investments)~~depend ~~are~~on ~~not~~digital ~~restricted~~technology ~~from~~to ~~owning~~estimate ~~assets~~quantities orof ~~engaging~~oil, innatural ~~businesses~~gas ~~that~~and ~~compete~~NGL ~~directly~~reserves, orprocess ~~indirectly~~and ~~with~~record ~~us.~~financial Inand ~~addition~~operating data, ~~NGP~~analyze seismic and drilling information, ~~Carlyle~~and communicate with our customers, employees and ~~their~~third-party ~~respective~~partners. ~~affiliates~~We ~~may~~have ~~acquire~~been the subject of cyber-attacks on our internal systems and through those of third parties, ~~develop~~but orthese ~~dispose~~incidents did not have a material adverse impact on our results of ~~additional~~operations. ~~oil~~Nevertheless, ~~and~~unauthorized ~~natural~~access ~~gas~~to ~~properties~~our seismic data, reserves information, customer or employee data or other ~~assets~~proprietary inor ~~the~~commercially ~~future,~~sensitive ~~without~~information ~~any~~could ~~obligation~~lead to ~~offer~~data uscorruption, ~~the~~communication ~~opportunity~~interruption, toor ~~purchase~~other disruptions in our exploration or ~~develop~~production operations or planned business transactions, any of ~~those~~which ~~assets~~could have a material adverse impact on our results of operations. ~~NGP~~If ~~and~~our ~~Carlyle~~information ~~are~~technology ~~established~~systems ~~participants~~cease into ~~the~~function ~~oil~~properly ~~and~~or ~~natural~~our ~~gas~~cybersecurity ~~industry~~is breached, ~~and~~we ~~each~~could ~~has~~suffer ~~resources~~disruptions ~~greater~~to ~~than~~our ~~ours~~normal operations, which ~~factors~~ may ~~make~~include itdrilling, ~~more~~completion, ~~difficult~~production ~~for~~and corporate functions. A cyber-attack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent us from transporting and marketing our production, non-compliance leading to ~~compete~~regulatory ~~with~~fines ~~them~~or ~~with~~penalties, ~~respect~~loss or disclosure of, or damage to, ~~commercial~~our ~~activities~~or asany ~~well~~of asour ~~for~~customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential ~~acquisitions.~~financial Asor alegal ~~result~~liability, ~~competition~~and ~~from~~requiring ~~these~~us ~~affiliates~~to ~~could~~incur ~~adversely~~significant ~~impact~~costs, including costs to repair or restore our ~~results~~systems ofand ~~operations~~data or to take other remedial steps.

~~The~~ Further, ~~loss~~as ofcyber-attacks ~~senior~~continue ~~management~~to evolve, we may be required to expend significant additional resources to continue to modify or ~~technical~~enhance ~~personnel~~our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could ~~adversely~~result ~~affect~~in ~~operations~~significant penalties and legal liability.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations. 33

~~Increases~~ Table inof ~~interest rates could adversely affect our business.~~Contents

We Risks ~~require~~Associated ~~continued~~with ~~access to capital and our business and operating results can be harmed by factors such as~~ the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. We expect to use our revolving credit facility to finance a portion of our future growth, and these changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.Merger

~~Our~~ We ~~use~~have ofincurred ~~seismic~~substantial ~~data~~transaction isfees ~~subject to interpretation~~ and ~~may~~costs ~~not~~in ~~accurately~~connection ~~identify~~with the ~~presence of oil and natural gas, which could adversely affect the results of our drilling operations~~Merger.

~~Even~~ We ~~when~~expect ~~properly used and interpreted, seismic data and visualization techniques are only tools used~~ to ~~assist~~incur ~~geoscientists~~a innumber ~~identifying~~of ~~subsurface~~non-recurring ~~structures~~transaction-related ~~and~~costs ~~hydrocarbon~~associated ~~indicators~~with ~~and~~completing ~~do not enable~~ the ~~interpreter~~Merger, tocombining ~~know~~our ~~whether~~operations ~~hydrocarbons~~with ~~are,~~Chesapeake’s inand ~~fact,~~achieving ~~present~~desired ~~in those structures~~synergies. AsThese afees ~~result,~~and ~~our~~costs ~~drilling activities~~ may ~~not~~ be ~~successful~~substantial. orNon-recurring ~~economical.~~transaction Incosts ~~addition~~include, ~~the~~but ~~use~~are ofnot ~~advanced~~limited ~~technologies~~to, ~~such~~fees aspaid ~~3-D~~to ~~seismic data~~legal, ~~requires~~financial ~~greater~~and ~~pre-drilling~~accounting ~~expenditures~~advisors, ~~than~~filing ~~traditional~~fees ~~drilling strategies,~~ and weprinting ~~could incur losses as a result of such expenditures~~costs.

~~Restrictions~~ We onmay ~~drilling~~fail ~~activities intended~~ to ~~protect~~realize ~~certain~~all ~~species~~ of ~~wildlife~~the ~~may~~anticipated ~~adversely~~benefits ~~affect~~of ~~our~~the ~~ability to conduct drilling activities in areas where we operate~~Merger.

~~Oil~~ The ~~and~~success ~~natural~~of ~~gas~~the ~~operations~~Merger will depend, in part, on our ~~operating~~ability ~~areas~~to ~~may~~realize bethe ~~adversely~~anticipated ~~affected~~benefits byand ~~seasonal~~cost orsavings ~~permanent~~from ~~restrictions~~combining onChesapeake’s ~~drilling~~and ~~activities~~WildHorse’s ~~designed~~businesses, toincluding ~~protect~~operational ~~various~~and ~~wildlife.~~other ~~Such~~synergies ~~restrictions~~that ~~may~~we ~~limit~~believe ~~our~~the ~~ability~~combined tocompany ~~operate~~will inachieve. ~~protected~~We ~~areas~~expect ~~and~~that ~~can~~the ~~intensify~~Merger ~~competition~~will ~~for~~provide ~~drilling~~substantial ~~rigs,~~cost ~~oilfield~~savings ~~equipment,~~due ~~services,~~to ~~supplies~~operational and ~~qualified~~capital ~~personnel,~~efficiencies ~~which~~as ~~may~~a ~~lead~~result toof ~~periodic~~Chesapeake’s ~~shortages~~significant ~~when~~expertise ~~drilling~~with isunconventional ~~allowed.~~assets ~~These~~and ~~constraints~~technical and ~~the~~operational. ~~resulting~~The ~~shortages~~anticipated orbenefits ~~high~~and ~~costs~~cost ~~could~~savings ~~delay~~of ~~our~~the ~~operations~~Merger ormay ~~materially~~not ~~increase~~be ~~our~~realized ~~operating~~fully ~~and~~or ~~capital~~at ~~costs.~~all, ~~Permanent~~may ~~restrictions~~take ~~imposed~~longer to ~~protect~~realize ~~threatened~~than expected or ~~endangered~~could ~~species~~have orother ~~their~~adverse ~~habitat~~effects ~~could~~that ~~prohibit~~we ~~drilling~~do innot ~~certain~~currently ~~areas~~foresee. orSome ~~require~~of the ~~implementation~~assumptions that we have made, such as the achievement of ~~expensive~~operating ~~mitigation~~synergies, ~~measures~~may not be realized. The ~~designation~~integration ofprocess ~~previously~~may, ~~unprotected~~for ~~species~~us and Chesapeake, result in ~~areas~~the ~~where~~loss weof ~~operate~~key asemployees, ~~threatened~~the disruption of ongoing businesses or ~~endangered~~inconsistencies in standards, controls, procedures and policies. There could ~~cause~~be uspotential tounknown ~~incur~~liabilities ~~increased~~and ~~costs~~unforeseen ~~arising~~expenses associated with the Merger that were not discovered in the course of performing due diligence. The integration will require significant time and focus from ~~species~~management ~~protection~~following the acquisition.

measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.

The enactment of derivatives legislation 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 Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd- Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd- Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC has proposed rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we currently qualify for the end-user exception to the mandatory clearing, trade-execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow.

It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, 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 Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations.

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 advancement and the introduction 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.

Our business could be adversely affected by security threats, including cyber-security threats, and related disruptions.

We rely heavily on our information systems, and the availability and integrity of these systems are essential for us to conduct our business and operations. As a producer of natural gas and oil, we face various security threats, including cyber-security threats, to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing and other facilities, refineries and pipelines. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position, results of operations and cash flows.

Future regulations relating to and interpretations of recently enacted U.S. federal income tax legislation may vary from our current interpretation of such legislation.

The U.S. federal income tax legislation recently enacted in Public Law No. 115-97, commonly referred to as the Tax Act, is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Act. In the future, the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.

Risks Related To Our Capital Stock

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

We expect that 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 downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

Certain holders have the ability to direct the voting of a majority of our common stock, and their interests may conflict with those of our other stockholders.

NGP and its affiliates, through WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and NGP XI, beneficially own approximately 70.7% of our outstanding common stock. As a result, NGP is currently able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of such holders 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. Given NGP’s concentrated ownership, it would have to approve any potential acquisition of us. In addition, certain of our directors are currently employees of NGP or Carlyle. These directors’ duties as employees of NGP or Carlyle, as applicable, may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest. Furthermore, we are party to a stockholders’ agreement with WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings that provides WildHorse Holdings and Esquisto Holdings with the right to designate a certain number of nominees to our board of directors so long as they, Acquisition Co. Holdings, NGP XI and their affiliates collectively beneficially own more than 5% of the outstanding shares of our common stock. Additionally, the Carlyle Investor, as a holder of Preferred Stock is entitled to elect (i) two directors to our board of directors for so long as the Carlyle Investor or its affiliates hold Preferred Stock and shares of our common stock, including shares of common stock issuable upon the conversion of Preferred Stock, representing at least 10% of our outstanding common stock on an as-converted basis and (ii) one board seat for so long as the Carlyle Investor or its affiliates hold Preferred Stock and shares of our common stock, including shares of common stock issuable upon the conversion of Preferred Stock, representing 5% or more of our outstanding common stock on an as-converted basis. The existence of these significant stockholders, the stockholders’ agreement and Carlyle’s board appointment rights may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, NGP’s and Carlyle’s concentration of stock ownership may adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.

Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including NGP-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, three of our directors (Messrs. Gieselman, Hayes and Weber) are Partners or Managing Partners of NGP, which is in the business of investing in oil and natural gas companies with independent management teams that seek to acquire oil and natural gas properties, and Mr. Brannon is President of certain NGP portfolio companies. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more

appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor.

NGP and its affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable NGP to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents provide that NGP and its affiliates (including portfolio investments of NGP and its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation, among other things:

• permits NGP and its affiliates 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 NGP or any of its affiliates, or any employee, partner, member, manager, officer or director of NGP or its affiliates who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Currently, NGP has multiple portfolio companies operating in the oil and natural gas industry, some of which may compete with us directly, including one company which operates in the broader Eagle Ford. Further, NGP or its affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability or option to pursue such opportunity. Such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to be unavailable to, or more expensive for, us to pursue. In this regard, we do not expect to enter into any agreement or arrangement with NGP and its affiliates to apportion opportunities between us, on the one hand, and NGP and its affiliates, on the other hand. In addition, NGP and its affiliates may dispose of oil and natural gas properties or other assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be, from time to time, presented to NGP or its affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours.

NGP is an established participant in the oil and natural gas industry and has access to resources greater than ours, which may make it more difficult for us to compete with NGP and its affiliates for commercial activities and potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and NGP or its affiliates, on the other hand, will be resolved in our favor. As a result, competition from NGP and its affiliates could adversely impact our results of operations.

We are a “controlled company” and, as a result, qualify for, and intend to rely on, exemptions from certain corporate governance requirements.

A group of stockholders that includes WildHorse Investment Holdings, Esquisto Investment Holdings, WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP XI, NGP and certain of NGP’s affiliates (collectively, the “Sponsor Group”) beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. As a result, we qualify as a “controlled company” within the meaning of the NYSE corporate governance standards. Under these rules, a company of which more than 50% of the voting power for the election of directors is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain applicable corporate governance requirements, including the requirements that:

• a majority of the board of directors consist of independent directors;

• the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;

• the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

• an annual performance evaluation of the nominating and corporate governance and compensation committees be completed.

We utilize the foregoing exemptions from the applicable corporate governance requirements. As a result, we do not have a majority of independent directors and do not have a compensation committee. Accordingly, you will not have the same protections afforded to stockholders of companies that are subject to such corporate governance requirements.

The price of our common stock may fluctuate significantly and you could lose all or part of your investment.

Volatility in the market price of our common stock may prevent you from being able to sell your common stock at or above the price you paid for your common stock. The market price for our common stock could fluctuate significantly for various reasons, including:

• our operating and financial performance and prospects;

• changes in earnings estimates or recommendations by securities analysts who track our common stock or industry;

• market and industry perception of our success, or lack thereof, in pursuing our growth strategy; and

• sales of common stock by us, our stockholders (including the Sponsor Group), or members of our management team.

In addition, the stock market has experienced significant price and volume fluctuations in recent years. This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industries. The changes frequently appear to occur without regard to the operating performance of the affected companies. Hence, the price of our common stock could fluctuate based upon factors that have little or nothing to do with us, and these fluctuations could materially reduce our share price.

We currently have no plans to pay regular dividends on our common stock, so you may not receive funds without selling your common stock.

We currently have no plans to pay regular dividends on our common stock. Any payment of dividends in the future will be at the discretion of our Board and will depend on, among other things, our earnings, financial condition and business opportunities, the restrictions in our debt agreements, and other considerations that our Board deems relevant. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment.

Future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings or otherwise, including to finance acquisitions. We may also issue convertible securities. For example, we issued and sold the Preferred Stock in connection with the Acquisition. We cannot predict the size of future issuances of our common stock or securities convertible into common stock, or the effect, if any, that future issuances and sales of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including any shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.

Each of WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP XI, Jay Graham, Anthony Bahr, the Carlyle Investor and KKR are party to an amended and restated registration rights agreement, which requires us to effect the registration of their shares of our common stock in certain circumstances.

We filed a registration statement with the SEC on Form S-8 providing for the registration of 9,512,500 shares of our common stock issued or reserved for issuance under our WildHorse Resource Development Corporation 2016 Long Term Incentive Plan (“2016 LTIP”). Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under our registration statement on Form S-8 are available for resale immediately in the public market without restriction. As of December 31, 2017, we have 7,517,555 shares of our common stock available for issuance under the 2016 LTIP.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock and could deprive our investors of the opportunity to receive a premium for their shares.

Our amended and restated certificate of incorporation authorizes our board of directors, without stockholder approval, to issue preferred stock in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. For example, on June 30, 2017, in connection with the Acquisition, we issued the Preferred Stock that include various rights, preferences, privileges and restrictions. Please see Note 10 under “Item 8. Financial Statements and Supplementary Data.” If our board of directors elects to issue preferred stock, the terms of such stock could cause it to be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. These provisions include:

• if at any time after the Sponsor Group no longer collectively own or control the voting of more than 50% of our outstanding common stock:

o dividing our board of directors into three classes of directors, with each class serving a staggered three-year term;

o providing that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, subject to the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by stockholders holding a majority of the outstanding shares);

o permitting any action by stockholders to be taken only at an annual meeting or special meeting rather than by a written consent of the stockholders, subject to the rights of any series of preferred stock with respect to such rights;

o permitting special meetings of our stockholders to be called only by our board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the total number of authorized directors, whether or not there exist any vacancies in previously authorized directorships (prior to such time, a special meeting may also be called at the request of stockholders holding a majority of the outstanding shares entitled to vote); and

o requiring the affirmative vote of the holders of at least 75% in voting power of all then outstanding common stock entitled to vote generally in the election of directors, voting together as a single class, to remove any or all of the directors from office at any time, and directors will be removable only for “cause;”

• prohibiting cumulative voting in the election of directors;

• establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and

• providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws.

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. The resolution of any conflicts that may arise in connection with any related party transactions that we have entered into with NGP, WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings or their affiliates, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests because NGP may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, please read “—Certain holders have the ability to direct the voting of a majority of our common stock, and their interests may conflict with those of our other stockholders.”

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

Our amended and restated 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.

For example, on June 30, 2017, we issued and sold the Preferred Stock to the Carlyle Investor in exchange for $435.0 million. As of December 31, 2017, these shares represented approximately 24.3% of our outstanding common stock, on an as-converted basis. Among other rights, preferences, privileges and restrictions, the holders of the Preferred Stock are entitled to vote, on an as-converted basis, together with holders of our common stock on all matters submitted to a vote of the holders of our common stock. As such, the initial issuance of the Preferred Stock to the Carlyle Investor and each subsequent increase in the Accreted Value of the Preferred Stock following an election by our board of directors to forego paying cash dividends on the Preferred Stock with respect to a given quarter, effectively reduce the relative voting power of the holders of our common stock.

In addition, the conversion of the Preferred Stock to common stock would dilute the ownership interest of existing holders of our common stock, and any sales in the public market of the common stock issuable upon conversion of the Preferred Stock could adversely affect prevailing market prices of our common stock.

Furthermore, the Carlyle Investor, as a holder of the Preferred Stock is entitled to elect (i) two directors to our board of directors for so long as the Carlyle Investor or its affiliates hold Preferred Stock and shares of our common stock, including shares of common stock issuable upon the conversion of Preferred Stock, representing at least 10% of our outstanding common stock on an as-converted basis and (ii) one board seat for so long as the Carlyle Investor or its affiliates hold Preferred Stock and shares of our common stock, including shares of common stock issuable upon the conversion of Preferred Stock, representing 5% or more of our outstanding common stock on an as-converted basis.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and require management’s time, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we are required to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE, which we were not required to comply with as a private company. We expect efforts to comply with these statutes, regulations and requirements may occupy a significant amount of time of our board of directors and management and may significantly increase our costs and expenses. As a public company, we are required to:

• institute a more comprehensive compliance function;

• comply with stock exchange rules;

• continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

• establish new internal policies, such as those relating to insider trading; and

• involve and retain to a greater degree outside counsel and accountants in the above activities.

Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act for our fiscal year ending December 31, 2017, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2022. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, being a public company subject to these rules and regulations makes 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. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to

any provision of the Delaware General Corporation Law, our amended and restated certificate of incorporation or our amended and restated bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which may have a negative effect on the trading price of our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Information regarding our properties is contained in Item 1. “Business” ~~and Item 7~~. ~~“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” contained herein.~~

ITEM 3. LEGAL PROCEEDINGS

As In ~~part~~January ~~of our normal business activities~~2019, weputative ~~may~~class beaction ~~named~~lawsuits ~~as defendants~~ in ~~litigation~~U.S. ~~and~~District ~~legal~~Courts ~~proceedings,~~for ~~including~~the ~~those~~District ~~arising~~of ~~from~~Delaware ~~regulatory~~ and ~~environmental~~Southern ~~matters.~~District Ifof weNew ~~determine~~York ~~that~~were afiled ~~negative~~against ~~outcome~~us is and ~~the~~other ~~amount~~defendants. ofThe ~~loss~~lawsuits isgenerally ~~reasonably~~allege ~~estimable,~~various weviolations ~~accrue~~of the ~~estimated~~Securities ~~amount.~~Exchange WeAct ~~are~~of ~~not~~1934 ~~aware~~in ofconnection ~~any~~with ~~litigation,~~the ~~pending~~disclosure orcontained ~~threatened,~~in ~~that~~the wejoint ~~believe~~proxy ~~will~~statement/prospectus ~~have~~filed ain ~~material~~connection ~~adverse~~with ~~effect~~the onMerger. ~~our~~The ~~financial~~lawsuits ~~position,~~seek ~~results~~rescission of ~~operations~~the Merger or ~~cash~~rescissory ~~flows.~~damages ~~See~~and, ~~Note~~in 21each ~~under~~case, ~~“Item~~attorney’s 8.fees, ~~Financial~~costs ~~Statements~~ and ~~Supplementary~~interest. ~~Data”~~We ~~for~~intend ~~additional information regarding a settlement related~~ to ~~our~~vigorously ~~North~~defend ~~Louisiana~~these ~~assets~~claims.

As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We are not aware of any litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows. See Note 18 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding current legal proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

~~Not~~ The ~~applicable~~information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Annual Report on Form 10-K.

52 34

Table of Contents

PART II

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

~~Market~~ We ~~Information~~are a wholly owned subsidiary of Chesapeake Energy Corporation and do not have any publicly traded common stock. In accordance with the Credit Agreement, we may not declare or pay dividends to Chesapeake subject to certain exceptions that are described in the Credit Agreement.

Our common stock began trading on the NYSE under the symbol “WRD” on December 14, 2016. Prior to that, there was no public market for our common stock. As of February 28, 2018, we had approximately 101,304,079 shares of common stock outstanding and 4 stockholders of record. The following table sets forth, for the periods indicated, the reported high and low sale prices for our common stock on the NYSE.

	Common Share Price Range
	High		Low
2017
4th Quarter	$	18.84	$	11.95
3rd Quarter		13.84		10.36
2nd Quarter		14.10		10.36
1st Quarter		15.35		10.65
2016
4th Quarter (beginning December 14, 2016)	$	15.06	$	14.40
3rd Quarter	n/a		n/a
2nd Quarter	n/a		n/a
1st Quarter	n/a		n/a

Dividend Policy

Since our initial public offering, we have not declared any dividends and we do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in the Credit Agreement and the indenture governing our 2025 Senior Notes, and other contracts and other factors our Board deems relevant.

Securities Authorized for Issuance Under Equity Compensation Plans

See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

Issuer Purchases of Equity Securities

The following table summarizes our repurchase activity during the quarterly period ended December 31, 2017:

Period

Total Number of Shares Purchased

Average Price Paid per Share

Total Number of Shares Purchased as Part of Publicly Announced Plans

Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans

(in thousands)

Common Share Repurchases (1):

October 1, 2017 - October 31, 2017

—

n/a

November 1, 2017 - November 30, 2017

—

n/a

December 1, 2017 - December 31, 2017

33,956

16.61

n/a

(1) Common shares are generally net-settled by employees to cover the required withholding tax upon vesting of restricted stock awards under the 2016 LTIP.

Comparative Stock Performance

The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for

historical comparative purposes only and should not be considered indicative of future stock performance. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.

The performance graph shown below compares the total return to stockholders on WRD’s common stock as compared to the total returns on the Standard and Poor’s 500 Index (“S&P 500 Index”) and the Standard and Poor’s 500 Oil and Gas Exploration and Production Select Index (“S&P Oil and Gas E&P Select Index”) from December 14, 2016 through December 31, 2017. The comparison was prepared based upon the following assumptions:

1. $100 was invested on December 14, 2016, our initial public offering date, in each of the following: common stock of WRD, the S&P 500 Index and the S&P Oil and Gas E&P Select Index.

2. Dividends are reinvested.

	December 14,		December 31,
Investment	2016		2016		2017
WRD	$	100.00	$	96.95	$	122.24
S&P 500 Index	$	100.00	$	99.36	$	118.65
S&P Oil and Gas E&P Select Index	$	100.00	$	99.36	$	89.36

ITEM 6. SELECTED FINANCIAL DATA

The ~~following~~information ~~selected~~called ~~financial~~for ~~data~~by ~~should~~Item be6 ~~read~~is inomitted ~~conjunction~~pursuant ~~with~~to ~~“Item~~Instruction 7.I(2) ~~Management’s~~to ~~Discussion~~Form ~~and~~10-K ~~Analysis~~(Omission of ~~Financial~~Information ~~Condition~~by ~~and~~Certain ~~Results~~Wholly-Owned ~~of Operations” and “Item 8~~Subsidiaries). ~~Financial Statements and Supplementary Data,” both contained herein.~~

Basis of Presentation. The selected financial data of our predecessor was retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the selected financial data presented below (i) (a) as of, and for the year ended, December 31, 2016, and (b) as of December 31, 2015, and for the period from February 17, 2015 (the inception of common control) to December 31, 2015, have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public offering and (ii) (a) for the period from January 1, 2015 to February 16, 2015, and (b) as of, and for the year ended December 31, 2014, have been derived from the combined financial position and results attributable to our predecessor. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries. 35

~~Comparability~~ Table of ~~the information reflected in selected financial data. The comparability of the results of operations among the periods presented is impacted by the following:~~Contents

• ITEM 7. MANAGEMENT'S ~~the~~DISCUSSION ~~North~~AND ~~Louisiana~~ANALYSIS ~~Settlement~~OF ~~(as~~FINANCIAL ~~previously~~CONDITION ~~defined~~AND inRESULTS ~~Item~~OF ~~1. “Business—Recent Developments—North Louisiana Settlement:);~~OPERATIONS

• Management's aDiscussion ~~deferred~~and ~~tax~~Analysis ~~benefit~~of Financial Condition and Results of ~~$43~~Operations should be read in conjunction with the financial statements and related notes in “Item 8.4 ~~million~~Financial ~~primarily~~Statements ~~due~~and Supplementary Data” contained herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to ~~the~~such ~~remeasurement~~differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of ~~our~~proved ~~deferred~~reserves, ~~tax~~capital ~~assets~~expenditures, economic and ~~liabilities~~competitive conditions, drilling results, regulatory changes and other uncertainties, as awell ~~result~~as those factors discussed in “Risk Factors” contained in Part I—Item 1A of this Annual Report and “Forward-Looking Statements”. In light of these risks, uncertainties and assumptions, the ~~Tax~~forward-looking ~~Act;~~events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

• the Acquisition, which was completed on June 30, 2017;

• the $435.0 million issuance of Preferred Stock to an affiliate of Carlyle;

• the acquisition of approximately 158,000 net acres of oil and natural gas properties adjacent to our existing Eagle Ford acreage on December 19, 2016 in connection with our initial public offering (the “Burleson North Acquisition”) for a final purchase price of $385.9 million, net of customary post-closing adjustments;

• incremental G&A expenses as a result of being a publicly traded company including, but not limited to, Exchange Act reporting expenses; expenses associated with Sarbanes Oxley compliance; expenses associated with shares of our common stock being listed on a national securities exchange; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and independent director compensation;

• a more active drilling program;

• the private placement of $350.0 million and $150.0 million in February 2017 and September 2017, respectively, of aggregate principal amount of our 2025 Senior Notes;

• combining the financial position and results of operations of Esquisto with the predecessor beginning February 17, 2015; and

• Esquisto’s third-party acquisition of certain oil and natural gas producing properties, undeveloped acreage and water assets located in the Eagle Ford in July 2015 for a purchase price of $103.0 million, net of customary post-closing adjustments.

As a result of the factors listed above, as well as the acquisitions and dispositions discussed above in “Business—Recent Developments,” the consolidated and combined historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

	For the Year Ended December 31,
	2017			2016			2015			2014
	(In thousands, except per share data)
Revenues and other income:
Oil sales	$	342,868		$	75,938		$	42,971		$	2,780
Natural gas sales		59,924			43,487			38,665			41,694
NGL sales		22,964			5,786			4,295			989
Other income		1,431			2,131			404			—
Total revenues and other income		427,187			127,342			86,335			45,463
Operating expenses:
Lease operating expenses		39,770			12,320			14,053			9,428
Gathering, processing and transportation		11,897			6,581			5,300			3,953
Taxes other than income tax		24,158			6,814			5,510			2,584
Cost of oil sales		—			—			—			687
Depreciation, depletion and amortization		168,250			81,757			56,244			15,297
Impairment of proved oil and gas properties		—			—			9,312			24,721
General and administrative expenses		40,663			23,973			15,903			5,838
Exploration expense		36,911			12,026			18,299			1,597
Other operating (income) expense		73			99			914			—
Total operating expenses		321,722			143,570			125,535			64,105
Income (loss) from operations		105,465			(16,228	)		(39,200	)		(18,642	)
Other income (expense):
Interest expense		(31,934	)		(7,834	)		(6,943	)		(2,680	)
Debt extinguishment costs		11			(1,667	)		—			—
Gain (loss) on derivative instruments		(55,483	)		(26,771	)		13,854			6,514
North Louisiana settlement		(7,000	)		—			—			—
Other income (expense)		(3	)		(151	)		(147	)		213
Total other income (expense)		(94,409	)		(36,423	)		6,764			4,047
Income (loss) before income taxes		11,056			(52,651	)		(32,436	)		(14,595	)
Income tax benefit (expense)		38,824			5,575			(604	)		158
Net income (loss)		49,880			(47,076	)		(33,040	)		(14,437	)
Net income (loss) allocated to previous owners		—			(2,681	)		(3,085	)		—
Net income (loss) allocated to predecessor		—			(33,998	)		(29,955	)		(14,437	)
Net income (loss) available to WRD	$	49,880		$	(10,397	)	$	—		$	—
Net income (loss) per common share:
Basic and diluted	$	0.32		$	(0.11	)	n/a			n/a
Weighted-average common shares outstanding:
Basic and diluted		96,324			91,327		n/a			n/a
Cash Flow Data:
Net cash provided by operating activities	$	277,372		$	22,262		$	50,096		$	25,660
Net cash used in investing activities	$	(1,266,861	)	$	(567,545	)	$	(443,639	)	$	(128,967	)
Net cash provided by financing activities	$	986,600		$	505,272		$	424,481		$	114,589
Other Financial Data:
Adjusted EBITDAX (1)	$	323,314		$	84,317		$	55,858		$	21,277
Balance Sheet Data (at period end):
Cash and cash equivalents	$	226		$	3,115		$	43,126		$	12,188
Total assets	$	2,778,100		$	1,442,281		$	966,365		$	335,722
Total liabilities	$	1,187,325		$	434,393		$	317,676		$	156,731
Series A perpetual convertible preferred stock	$	445,483		$	—		$	—		$	—
Predecessor and Previous owner equity	$	—		$	—		$	648,689		$	178,992
Stockholders' equity	$	1,145,292		$	1,007,888		n/a			n/a
Total liabilities and equity	$	2,778,100		$	1,442,281		$	966,365		$	335,722

(1) Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net (loss) income, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Adjusted EBITDAX.”

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” contained herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, drilling results, regulatory changes and other uncertainties, as well as those factors discussed in “Risk Factors” contained in Part I—Item 1A of this Annual Report and “Cautionary Statement Regarding Forward-Looking Statements”. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

We In February 2019, we were ~~incorporated~~acquired ~~under~~by ~~the~~Chesapeake ~~laws~~for approximately 717.3 million shares of Chesapeake common stock and $381.1 million in cash. Immediately following the ~~State~~completion of ~~Delaware~~the inacquisition, ~~August~~WildHorse ~~2016~~Development tomerged ~~become~~with and into Brazos Valley Longhorn, L.L.C., a ~~holding~~newly ~~company~~formed ~~for~~Delaware ~~the~~limited ~~assets~~liability company and ~~operations~~wholly owned subsidiary of ~~WHR~~Chesapeake. IIFollowing ~~and~~the ~~Esquisto~~completion of the Merger on February 1, 2019, Brazos Valley Longhorn, L. ~~With~~L.C., ~~equity~~as ~~commitments~~successor ~~from~~to ~~affiliates~~WildHorse Development, was a wholly owned subsidiary of ~~NGP~~Chesapeake. As ~~and~~a ~~its~~result ~~Management~~of ~~Members~~no longer being a publicly traded company, ~~WHR~~we IIexpect ~~was~~to ~~founded~~realize incertain ~~June~~cost ~~2013~~savings including, but not limited to, expenses associated with Exchange Act reporting; expenses associated with being listed on a national securities exchange; expenses related to investor relations; expenses related to director and ~~Esquisto~~officer ~~was~~liability ~~founded~~insurance; inand ~~June~~expenses ~~2014~~related to independent director compensation.

~~Contemporaneously~~ Business ~~with our initial public offering, (i) the owners of WHR II exchanged all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings~~ and ~~the~~Industry owners of Esquisto exchanged all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings contributed all of the interests in WHR II to WildHorse Holdings, Esquisto Investment Holdings contributed all of the interests in Esquisto to Esquisto Holdings and the owner of Acquisition Co. contributed all of its interests in Acquisition Co. to Acquisition Co. Holdings and (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings contributed all of the interests in WHR II, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation. In May 2017, in connection with the Acquisition, WRD formed WHR EF as a wholly owned subsidiary. In November 2017, in anticipation of an acquisition of land to develop a sand mine, WRD formed Burleson Sand LLC (“Burleson Sand”). WHR II has two wholly owned subsidiaries – WildHorse Resources Management Company, LLC (“WHRM”) and Oakfield. Esquisto has two wholly owned subsidiaries – Petromax E&P Burleson, LLC, and Burleson Water. WHRM is the named operator for all oil and natural gas properties owned by us.Outlook

~~Outlook~~ Our financial position and future prospects, including our revenues, operating results, profitability, liquidity, future growth and the value of our assets, depend primarily on prevailing commodity prices. Over the past decade, the landscape of energy production has changed dramatically in the United States. Domestic energy production capabilities have increased the nation’s supply of both crude oil and natural gas, primarily driven by advances in technology, horizontal drilling and hydraulic fracture stimulation techniques. As a result of this increase in domestic supply of crude oil and natural gas, commodity prices for these products are meaningfully lower than they were a decade ago and may remain volatile for the foreseeable future.

Our financial position and future prospects, including our revenues, operating results, profitability, liquidity, future growth and the value of our assets, depend primarily on prevailing commodity prices. The oil and natural gas industry is cyclical and commodity prices are highly volatile. During 2015 and the first half of 2016, the global oil supply continued to outpace demand, resulting in a decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Starting in 2014 and continuing into 2016, commodity prices dropped significantly, with the West Texas Intermediate posted price declining from approximately $108 per Bbl in June 2014 to approximately $26 per Bbl in February 2016. Since the 2016 lows, West Texas Intermediate prices have increased to approximately $60 per Bbl in December 2017. The Henry Hub spot market price declined from over $8 per MMBtu in February 2014 to less than $2 per MMBtu in March 2016 and has increased to over $3.60 per MMBtu in December 2017. NGL prices have also suffered significant declines. A combination of oversupply from production growth and weaker demand due to weak economic activity and increased efficiency has contributed to the falling prices.

The U.S. Energy Information Administration’s, or EIA’s, January 2018 Short-Term Energy Outlook forecasts that Brent crude oil prices will average $60 per Bbl in 2018 and $61 per Bbl in 2019. North Sea Brent crude oil spot prices averaged $64 per Bbl in December 2017; an increase of $2 per Bbl from the November 2017 average and the highest monthly average since November 2014. World crude oil supply decreased an estimated 0.4 MMbbl/d in 2017. The EIA expects that global oil inventory draws will average 0.2 MMbbl/d and 0.3 MMbbl/d in 2018 and 2019, respectively. Like Brent crude oil prices, WTI prices have increased over the past year. The EIA expects WTI crude oil prices to average $4 per Bbl lower than Brent in 2018 and 2019.

The EIA expects that natural gas production will increase by 6.9 Bcf/d in 2018 compared to 2017. Production is expected to increase by an additional 2.6 Bcf/d in 2019. The EIA expects that strong domestic production levels, which will meet growing domestic natural gas consumption and export capabilities, will cause the Henry Hub natural gas spot price to decline to a projected average of

$2.88 per MMBtu in 2018. In 2019, inventories are expected to be lower than average in comparison to 2018 and prices are expected to rise to $2.92 per MMBtu in 2019.

In February 2018, we established a full year 2018 drilling and completion capital expenditure budget that is $700 million to $800 million compared to $550 million to $675 million for our 2017 capital expenditure budget. We expect our 2018 development program and capital budget will be focused on the Eagle Ford and Austin Chalk, where we plan to allocate approximately 100% of our drilling and completion capital budget. On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos for the sale of the NLA Assets for a total sales price of approximately $217.0 million before customary adjustments. The transaction is expected to close by the end of March 2018. Due to asset held-for-sale guidance, we anticipate recording an impairment loss on the NLA Assets during the first quarter of 2018. The net book value of the NLA assets was $415.0 million at December 31, 2017.

We expect to fund our 2018 development from cash flows from operations and borrowings under our revolving credit facility. However, there can be no assurance that our operations or other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures. We believe we have built significant flexibility into our 2018 capital budget, not only in the timing of completions, but also in our operated rig count. We will have the option to increase or decrease our capital activity as commodity prices dictate, which will allow us to preserve liquidity while maintaining flexibility in our completions schedule. In our Eagle Ford Acreage, we are currently running a six-rig program and intend to average 4.8 rigs during 2018.

Commodity hedging remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information.

For a discussion of the potential impact of commodity price changes on our estimated proved reserves, including quantification of such potential impact, please read “Item 1. Business—Our Oil and Natural Gas Data—Reserves Sensitivity.”

Commodity prices have historically been volatile, and we expect this volatility to continue for the foreseeable future. We will continue to monitor our liquidity, including opportunities for liquidity enhancement through possible joint-venture arrangements, coordinate our capital expenditure program with our expected cash flows and projected debt-repayment schedule, and evaluate available funding and other strategic alternatives in light of the current and expected commodity price environment and market conditions.

Lower oil, natural gas and NGL prices not only reduce our revenues and cash flows, but also may limit the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially lower our reserves. Lower commodity prices in the future could also result in impairments of our oil and natural gas properties and may also reduce the borrowing base under our revolving credit facility, which will be determined by the lenders, in their sole discretion, based upon projected revenues from our oil, natural gas and NGL properties and our commodity derivative contracts. The occurrence of any of the foregoing could materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned capital expenditures. Alternatively, higher oil, natural gas and NGL prices may result in significant non-cash fair value losses being incurred on our derivatives, which could cause us to experience net losses when oil and natural gas prices rise.

Sources of Our Revenues

Our revenues ~~and other income~~ are primarily derived from the sale of our oil ~~and natural gas production~~, ~~the sale of NGLs that are extracted from our~~ natural gas ~~during processing~~, ~~the gathering charge paid by certain third-party working interest owners for their share of volumes that run through our gathering system~~ and ~~the~~NGL ~~sale~~production ~~of our water supply to third parties. Production revenues are derived~~ entirely from the continental United States. For the year ended December 31, ~~2017~~2018, ~~we derived~~ approximately 8089% of our revenues ~~and~~was ~~other income~~ from oil sales, 146% from natural gas sales, 54% from NGL sales and less than 1% from ~~gathering~~other ~~charges~~revenues. ~~See Note 2 under “Item 8. Financial Statements and Supplementary Data” for information regarding our adoption of the new revenue recognition standard.~~

Oil, natural gas and NGL prices are inherently volatile and are influenced by many factors outside our control. In order to reduce the impact of fluctuations in natural gas and oil prices on revenues, or to protect the economics of property acquisitions, we intend to periodically enter into derivative contracts with respect to a significant portion of estimated natural gas and oil production through various transactions that fix the future prices received. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

Principal Components of Cost Structure

Costs associated with producing oil, natural gas and NGLs are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells we own. The sections below summarize the primary operating costs we typically incur.

• Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, workover rigs and workover expenses, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface

facilities result in increased LOE in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production-related activities, such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production.

We monitor our operations to ensure that we are incurring LOE at an acceptable level. For example, we monitor our LOE per Boe to determine if any wells or properties should be shut in, recompleted or sold. This unit rate also allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers. Although we strive to reduce our LOE, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of properties. For example, we may increase field-level expenditures to optimize our operations, incurring higher expenses in one quarter relative to another, or we may acquire or dispose of properties that have different LOE per Boe. These initiatives would influence our overall operating cost and could cause fluctuations when comparing LOE on a period to period basis.

• Gathering, processing and transportation (“GP&T”). These are costs incurred to deliver production of our natural gas, NGLs and oil to the market. Cost levels of these expenses can vary based on the volume of natural gas, NGLs and oil produced as well as the cost of commodity processing. See Note 2 under “Item 8. Financial Statements and Supplementary Data” for information regarding our adoption of the new revenue recognition standard.

• Taxes other than Income Taxes. Production taxes are paid on produced oil and natural gas based on rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil, natural gas and NGLs revenues. Production taxes for our Texas properties are based on the market value of our production at the wellhead. Production taxes for our Louisiana properties are based on our gross production at the wellhead. We are also subject to ad valorem taxes in the counties and parishes where our production is located. Ad valorem taxes for our Texas properties are based on the fair market value of our mineral interests for producing wells. Ad valorem taxes for our Louisiana properties are assessed based on the cost of our oil and gas properties. Louisiana imposes a capital based franchise tax on corporations based on capital employed within the state.

• Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with our development and acquisition efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method. Please read “—Critical Accounting Policies and Estimates—Successful Efforts Method of Accounting for Oil and Natural Gas Activities” for further discussion. Our DD&A rate can fluctuate as a result of impairments, dispositions, finding and development costs and proved reserve volumes, which are all impacted by oil, natural gas and NGL prices.

• Impairment Expense. We review our proved properties and unproved leasehold costs for impairment whenever events and changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Please read “—Critical Accounting Policies and Estimates—Impairment of Oil and Natural Gas Properties” for further discussion. Impairment of unproved leasehold costs are recorded within exploration expense.

• General and Administrative Expenses. General and administrative (“G&A”) expenses 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, stock based compensation, public company expenses, IT expenses, audit and other fees for professional services, including legal compliance and acquisition-related expenses.

• Exploration Expense. Exploration expense is geological and geophysical costs that include seismic surveying costs, costs of unsuccessful exploratory dry holes and lease abandonment and delay rentals. Exploration expense also includes rig standby and rig contract termination fees.

• Interest expense. We finance a portion of our working capital requirements and acquisitions with borrowings under revolving credit facilities and senior note issuances. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and financing decisions. We expect to continue to incur significant interest expense as we continue to grow. Interest expense includes the amortization of debt issuance costs as well as the write-off of unamortized debt issuance costs and is offset by capitalized interest.

• Gain (loss) on derivative instruments. Net realized and unrealized gains on our derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments. Given the volatility of commodity prices, it is not possible to predict future reported unrealized mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge

positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.

• Income tax expense. We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, we were primarily organized as pass-through entities for federal income tax purposes and were not subject to federal income taxes; however, one of our predecessor subsidiaries previously elected to be taxed as a corporation and was subject to federal and state income taxes.

Critical Accounting Policies and Estimates

Use of Estimates in the Preparation of Financial Statements

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources.

We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil, gas and NGL reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (6) deferred taxes; (7) environmental remediation costs; (8) valuation of derivative instruments; (9) contingent liabilities; and (10) impairment expense. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and such revisions could be material. 36

Table of Contents

our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources.

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

We use the successful efforts method of accounting for natural gas and crude oil producing activities. Costs to acquire mineral interests in crude oil and natural gas properties are capitalized. Costs to drill and develop development wells and costs to drill and develop exploratory wells that find proved reserves are also capitalized. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed.

Impairment of Oil and Natural Gas Properties

We acquire leases on acreage not associated with proved reserves or held by production with the expectation of ultimately assigning proved reserves and holding the leases with production. The costs of acquiring these leases, including primarily brokerage costs and amounts paid to lessors, are capitalized and excluded from current amortization pending evaluation. When proved reserves are assigned, the leasehold costs associated with those leases are depleted as producing oil and gas properties. Costs associated with leases not held by production are impaired when events and circumstances indicate that carrying value of the properties is not recoverable.

Capitalized costs of producing crude oil and natural gas properties and support equipment, net of estimated salvage values, are depleted by field using the units-of-production method. Well and well equipment and tangible property additions are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.

Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the undiscounted future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Oil and Natural Gas Reserve Quantities

The estimates of proved crude oil, natural gas and NGL reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements.

Our estimates of proved reserves are based on the quantities of oil, natural gas and NGLs, 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 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. Reserves and economic evaluation of all of our properties are prepared on a well-by-well basis. The accuracy of reserve estimates is a function of the:

• quality and quantity of available data;

• interpretation of that data;

• accuracy of various mandated economic assumptions; and

• judgment of the independent reserve engineer.

One of the most significant estimates we make is the estimate of oil, natural gas and NGL reserves. Oil, natural gas and NGL reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, projected future production, economic assumptions relating to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation costs and these estimates are inherently uncertain. If estimates of proved reserves decline, our DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of oil and natural gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. We cannot predict what reserve revisions may be required in future periods.

We The ~~intend~~estimates toof ~~have~~proved ~~our~~crude ~~independent~~oil, ~~reserve~~natural ~~engineer~~gas ~~audit~~and ~~our~~NGL ~~internally~~reserves ~~prepared~~utilized ~~reserve~~in ~~report~~the aspreparation of ~~December~~the 31consolidated financial statements are estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions using a 12‑month average price with no provision for ~~each~~price ~~year~~and cost escalations in future years except by contractual arrangements.

~~Depreciation~~ Our estimates of proved reserves are based on the quantities of oil, ~~Depletion~~natural gas and ~~Amortization~~NGLs, 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 under existing economic conditions, operating methods and government regulations

Our DD&A rate is dependent upon our estimates of total proved developed and proved undeveloped reserves, which incorporate various assumptions and future projections. If our estimates of total proved developed or proved undeveloped reserves decline, the rate at which we record DD&A expense increases, which in turn reduces our net income. Such a decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploration and development program, as well as future economic conditions. 37

Table of Contents

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. Reserves and economic evaluation of all of our properties are prepared on a well-by-well basis. The accuracy of reserve estimates is a function of the:

quality and quantity of available data;

interpretation of that data;

accuracy of various mandated economic assumptions; and

judgment of the independent reserve engineer. See Note 20. “Supplemental Oil and Gas Information (Unaudited)” under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our reserves.

Derivative Instruments

We ~~utilize~~have, ~~commodity~~historically, ~~derivative~~used ~~instruments~~fixed price commodity swaps, ~~including~~basis swaps, collars and ~~collars,~~deferred purchased puts to manage the price risk associated with the forecasted sale of our oil and natural gas production. A swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price. A collar requires us to pay the counterparty if the settlement price is above the ceiling price and requires the counterparty to pay us if the settlement price is below the floor price. The objective of our use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil, gas and NGL prices and to manage our exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit our ability to benefit from favorable price movements. We may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. We do not enter into derivative contracts for speculative purposes.

Our derivative instruments are not designated as hedges for accounting purposes. Accordingly, changes in fair value are recognized in our consolidated and combined statements of operations in the period of change. Gains and losses on derivatives and premiums paid for put options are included in cash flows from operating activities. We may also enter into contracts that qualify for the normal purchase/normal sale (“NPNS”) exception. When a contract meets the criteria to qualify as NPNS, we apply such exception.

Our valuation estimate takes into consideration the counterparties’' credit worthiness, our credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’'s view. We believe that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

Accounting for Business Combinations

We account for all of our business combinations using the purchase method, which involves the use of significant judgment. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, we must prepare estimates. To estimate the fair values of these properties, we prepare estimates of oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For

estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future net cash flows of probable and possible reserves are reduced by additional risk factors. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.

Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.

Asset Retirement Obligations

Our asset retirement obligations (“ARO”) consist of estimated future costs associated with the plugging and abandonment of oil, natural gas and NGL wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free discount rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time, are recorded as accretion expense, which is a component of DD&A. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property.

Revenue Recognition

Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We recognize revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. These differences result in gas imbalances. We record a liability to the extent there are not sufficient reserves to cover an over delivered gas imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. We receive payment approximately one month after delivery for operated crude oil wells, approximately two months after delivery for operated natural gas wells and up to three months after delivery for non-operated wells. Regarding hedge revenue, hedge settlements occur in the same month for natural gas and in the month following for crude oil. Hedge revenue is recorded as a component of “Other income (expense)” in our Results of Operations. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A 10% change in our December 31, 2017, 2016 and 2015 revenue accrual would have impacted total operating revenues by approximately $7.6 million, $1.7 million and $1.2 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Incentive Units

The governing documents of WHR II provided for the issuance of incentive units. WHR II granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units would have been entitled to distributions ranging from 20% to 40% when declared, but only after cumulative distribution thresholds (payouts) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. The incentive units were being accounted for as liability-classified awards as achievement of the payout conditions required settlement of such awards by transferring cash to the incentive unit holder. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. The payment likelihood related to the WHR II incentive units was not deemed probable for the years ended December 31, 2016 and 2015, respectively. As such, no compensation expense was recognized by our predecessor.

In connection with the Corporate Reorganization, the WHR II incentive units were transferred to WildHorse Investment Holdings in exchange for substantially similar incentive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings granted certain officers and employees awards of incentive units in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The fair value of the incentive units will be remeasured on a quarterly basis until all payments have been made. Any future compensation expense recognized will be a non-cash charge, with the settlement obligation resting with WildHorse Investment Holdings, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by deemed capital contributions (distributions). As such, these awards are not dilutive to our stockholders. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date. The payment

likelihood related to these incentive units was not deemed probable at December 31, 2017. As such, no compensation expense was recognized by us. Unrecognized compensation cost associated with these incentive units was $39.5 million at December 31, 2017.

The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following key assumptions:

	Incentive Unit Valuation As Of December 31, 2017
Expected life (years)	0.54 - 4.79
Expected volatility (range)	42.0% - 59.0%
Dividend yield		0.00	%
Risk-free rate (range)	1.54% - 2.15%

Vesting of all incentive units is generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested are forfeited if an employee is no longer employed. All incentive units will be forfeited if a holder resigns whether the incentive units are vested or not. If the payouts have not yet occurred, then all incentive units, whether or not vested, will be forfeited automatically (unless extended).

Income Tax

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 tax basis in assets and liabilities and their reported amounts in the financial statements 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. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our consolidated statement of operations.

We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority.

~~Contingent Liabilities~~ 38

We Table ~~are subject to various legal proceedings, claims, and liabilities that arise in the ordinary course~~ of business. We accrue losses when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss, but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Our in-house legal counsel regularly assess contingent liabilities and, in certain circumstances, consult with external legal counsel or consultants to assist in the evaluation of our liability for these contingencies.Contents

Management makes judgments and estimates when it establishes liabilities for litigation and other contingent matters. Estimates of litigation-related liabilities are based on the facts and circumstances of the individual case and on information currently available to us. The extent of information available varies based on the status of the litigation and our evaluation of the claim. In future periods, a number of factors could significantly change our estimate of litigation-related liabilities, including discovery activities; briefings filed with the relevant court; rulings from the court made pre-trial, during trial, or at the conclusion of any trial; and similar cases involving other plaintiffs and defendants that may set or change legal precedent. As events unfold throughout the litigation process, we evaluate the available information and may consult our external legal counsel to determine whether liability accruals should be established or adjusted.

Results of Operations

The selected financial data of our predecessor was retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the results of operations presented below (i) (a) for the year ended December 31, 2016 and (b) for the period from February 17, 2015 (the inception of common control) to December 31, 2015 have been derived from the combined results attributable to our predecessor and Esquisto for periods prior to our initial public offering and (ii) for the period from January 1, 2015 to February 16, 2015 have been derived from the results attributable to our predecessor. Furthermore, the results of operations attributable to Acquisition Co. are reflected in the financial data presented herein beginning on December 19, 2016. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest.


	For the Year Ended December 31,
	2018		2017		2016
Revenues and other income (in thousands):
Oil sales	$	843,244	$	342,868	$	75,938
Natural gas sales		60,129		59,924		43,487
NGL sales		41,961		22,964		5,786
Other income		2,052		1,431		2,131
Total revenues and other income		947,386		427,187		127,342
Operating expenses (in thousands):
Lease operating expenses		61,620		39,770		12,320
Gathering, processing and transportation		9,856		11,897		6,581
Taxes other than income tax		52,410		24,158		6,814
Depreciation, depletion and amortization		296,685		168,250		81,757
Impairment of NLA Disposal Group		214,274		—		—
Gain on sale of properties		(2,781)		—		—
General and administrative expenses		65,710		40,663		23,973
Incentive unit compensation expense		13,776		—		—
Exploration expense		22,483		36,911		12,026
Other operating expense		1,064		73		99
Total operating expenses		735,097		321,722		143,570
Income (loss) from operations		212,289		105,465		(16,228)
Other income (expense) (in thousands):
Interest expense, net		(60,119)		(31,934)		(7,834)
Gain (loss) on derivative instruments		35,393		(55,483)		(26,771)
North Louisiana settlement		—		(7,000)		—
Other expense		(859)		8		(1,818)
Total other expense		(25,585)		(94,409)		(36,423)
Income (loss) before income taxes		186,704		11,056		(52,651)
Income tax benefit (expense)		(40,196)		38,824		5,575
Net income (loss)		146,508		49,880		(47,076)
Net loss attributable to previous owners		—		—		(2,681)
Net loss attributable to predecessor		—		—		(33,998)
Net income (loss) available to WRD	$	146,508	$	49,880	$	(10,397)

Net income (loss) per common share:
Basic and diluted	$	0.88	$	0.32	$	(0.11)
Weighted-average common shares outstanding:
Basic and diluted		99,498		96,324		91,327
Oil and natural gas revenue (in thousands):
Crude oil	$	843,244	$	342,868	$	75,938
Natural gas		60,129		59,924		43,487
NGLs		41,961		22,964		5,786
Total oil, natural gas and NGL revenue	$	945,334	$	425,756	$	125,211
Production volumes:
Oil (MBbls)		12,585		6,606		1,848
Natural gas (MMcf)		21,531		20,463		17,820
NGLs (MBbls)		2,143		1,206		471
Total (MBoe)		18,316		11,222		5,289
Average sales price:
Oil (per Bbl)	$	67.00	$	51.90	$	41.09
Natural gas (per Mcf)	$	2.79	$	2.93	$	2.44
NGLs (per Bbl)	$	19.58	$	19.04	$	12.28
Total (per Boe)	$	51.61	$	37.94	$	23.67
Average production volumes:
Oil (MBbls/d)		34.5		18.1		5.0
Natural gas (MMcf/d)		59.0		56.1		48.7
NGLs (MBbls/d)		5.9		3.3		1.3
Average net production (MBoe/d)		50.2		30.7		14.5
Average unit costs per Boe:
Lease operating expenses	$	3.36	$	3.54	$	2.33
Gathering, processing and transportation	$	0.54	$	1.06	$	1.24
Taxes other than income tax	$	2.86	$	2.15	$	1.29
General and administrative expenses	$	3.59	$	3.62	$	4.53
Depletion, depreciation and amortization	$	16.20	$	14.99	$	15.46

~~Factors Affecting the Comparability of the Combined Historical Financial Results~~ 39

~~The~~ Table ~~comparability~~ of ~~the results of operations among the periods presented is impacted by the following significant transactions:~~Contents

• Year ~~the~~Ended ~~North~~December ~~Louisiana~~31, ~~Settlement~~2018 ~~(as~~Compared ~~previously~~to ~~defined~~the Year inEnded ~~Item~~December 31, ~~1. “Business—Recent Developments—North Louisiana Settlement”);~~2017

• For apurposes ~~deferred tax benefit~~ of ~~$43.4~~the ~~million~~following ~~primarily~~discussion, ~~due~~references to ~~the~~2018 ~~remeasurement~~and of2017 ~~our~~refer ~~deferred~~to ~~tax~~the ~~assets~~years ~~and~~ended ~~liabilities~~December as31, a2018 ~~result~~and of2017, ~~the~~respectively, ~~Tax~~unless ~~Act;~~otherwise indicated.

•· ~~the~~Oil, ~~Acquisition~~natural gas and NGL revenues were $945.3 million for 2018 compared to $425.8 million for 2017, ~~which~~an increase of $519.5 million (approximately 122%). Revenue increased because production increased by 7.1 MMBoe and because the average realized sales price was ~~completed~~higher onby ~~June~~$13.67 ~~30,~~per ~~2017;~~Boe (approximately 36%) due to higher overall commodity prices and a higher percentage of oil in the production mix.

•· LOE was $61.6 million and $39.8 million for 2018 and 2017, respectively. On a per Boe basis, total LOE was $3.36 and $3.54 for 2018 and 2017, respectively. The decrease in LOE on a per unit basis is largely attributable to the increased production due to the drilling of successful wells in the Eagle Ford Shale along with increased efficiencies in 2018 compared to 2017. We recorded $~~435~~10.02 million ~~issuance~~of workover expenses in 2018 in comparison to $7.7 million in 2017 to increase efficiency on legacy wells. Net production in 2018 consisted of ~~Preferred~~69% ~~Stock~~oil compared to 59% oil in 2017, an ~~affiliate~~increase of ~~Carlyle;~~approximately 17%.

•· ~~the~~GP&T ~~acquisition~~expenses ofwere ~~approximately~~$9.9 ~~158,000~~million ~~net~~and ~~acres~~$11.9 ofmillion ~~oil~~for 2018 and ~~natural~~2017, ~~gas~~respectively. ~~properties~~On ~~adjacent~~a toper ~~our~~Boe ~~existing~~basis, ~~Eagle~~GP&T ~~Ford~~expenses ~~acreage~~were on$0.54 ~~December~~and 19$1.06 for 2018 and 2017, ~~2016~~respectively. The 49% decrease in ~~connection~~GP&T ~~with~~expenses ~~our~~on ~~initial~~a ~~public~~per ~~offering~~Boe ~~(the~~basis ~~“Burleson~~was ~~North~~primarily ~~Acquisition”)~~attributable ~~for~~to athe ~~final~~impact ~~purchase~~from ~~price~~the ofnew ~~$385.9~~revenue ~~million~~recognition standard, ~~net~~the sale of ~~customary~~the ~~post-closing~~NLA ~~adjustments;~~properties and an increase in production from our drilling activities in the Eagle Ford Shale.

•· ~~incremental~~Taxes ~~G&A~~other ~~expenses~~than asincome atax ~~result~~were of$52.4 ~~being~~million aand ~~publicly~~$24.2 ~~traded~~million ~~company~~for ~~including~~2018 and 2017, ~~but~~respectively, ~~not~~an ~~limited~~increase ~~to,~~of ~~Exchange~~$28.2 ~~Act~~million ~~reporting~~(approximately ~~expenses;~~117%). ~~expenses~~On ~~associated~~a ~~with~~per ~~Sarbanes~~Boe ~~Oxley~~basis, ~~compliance;~~taxes ~~expenses~~other ~~associated~~than ~~with~~income ~~shares~~tax ofwere ~~our~~$2.86 ~~common~~and ~~stock~~$2.15 ~~being~~for ~~listed~~2018 onand a2017, ~~national~~respectively. ~~securities~~The ~~exchange;~~$28.2 ~~incremental~~million ~~independent~~increase ~~auditor~~was ~~fees;~~primarily ~~incremental~~due ~~legal~~to ~~fees;~~an ~~investor~~increase ~~relations~~in ~~expenses;~~production ~~registrar~~taxes of $25.8 million and ~~transfer~~ad ~~agent~~valorem ~~fees;~~taxes ~~incremental~~of ~~director~~$2.4 ~~and~~million. ~~officer~~The ~~liability~~production ~~insurance~~taxes ~~costs;~~increased due to higher realized prices and ~~independent~~increased ~~director~~volumes. ~~compensation;~~The ad valorem taxes increased due to increased property valuations.

•· DD&A expense for 2018 was $296.7 million compared to $168.3 million for 2017, a ~~more~~$128.4 ~~active~~million increase (approximately 76%) primarily due to an increase in production volumes related to acquisitions and drilling ~~program;~~activities. Increased production volumes caused DD&A expense to increase by $106.3 million and the change in the DD&A rate between periods caused DD&A expense to increase by $22.1 million.

•· ~~the~~Impairment ~~private~~losses ~~placement~~from the sale of ~~$350.0~~the ~~million~~NLA ~~and~~Disposal Group were $~~150~~214.03 million in ~~February~~2018. ~~2017~~We ~~and~~did ~~September~~not ~~2017,~~have ~~respectively,~~any ofsimilar ~~aggregate~~impairments ~~principal~~from ~~amount~~the sale of ~~our~~assets ~~2025~~in ~~Senior Notes~~2017.

•· ~~combining~~Gains from the ~~financial~~sale ~~position~~of ~~and~~properties ~~results~~were of$2.8 ~~operations~~million ofin ~~Esquisto~~2018. ~~with~~We ~~the~~did ~~predecessor~~not ~~beginning~~have ~~February~~any ~~17,~~gains ~~2015;~~from ~~and~~the sale of assets in 2017.

•· ~~Esquisto’s~~G&A ~~third~~expenses ~~party~~were ~~acquisition~~$65.7 million and $40.7 million (an increase of ~~certain~~approximately ~~oil~~61%) for 2018 and ~~natural~~2017, ~~gas~~respectively. ~~producing~~The ~~properties,~~$25.0 ~~undeveloped~~million ~~acreage~~increase was primarily due to increased salary, wage and ~~water~~stock-based ~~assets~~compensation ~~located~~costs, incosts associated with divesting the ~~Eagle~~NLA ~~Ford~~properties, inand ~~July~~incremental ~~2015~~G&A ~~for~~expenses as a ~~purchase~~result ~~price~~ of ~~$103.0~~being ~~million~~a publicly traded company including, ~~net~~but ofnot ~~customary~~limited ~~post-closing~~to, ~~adjustments~~expenses associated with Sarbanes Oxley compliance and incremental independent auditor fees; offset by lower acquisition expenses.

As· aExploration ~~result~~expense ofwas ~~the~~$22.5 ~~factors~~million ~~listed~~and ~~above~~$36.9 million for 2018 and 2017, asrespectively. ~~well~~The as$14.4 ~~the~~million ~~acquisitions~~decrease ~~and~~in ~~dispositions~~exploration ~~discussed~~expense ~~above~~was largely due to an $11.5 million decrease in ~~“Business—Recent~~seismic ~~Developments”~~acquisition ~~the~~expenses, ~~combined~~a ~~historical~~$10.3 ~~results~~million ofdecrease ~~operations~~in undeveloped leasehold impairments and ~~period-to-period~~abandonments, ~~comparisons~~a decrease of ~~these~~$2.1 ~~results~~million in delay rentals and ~~certain~~a ~~financial~~$1.9 ~~data~~million ~~may~~decrease ~~not~~in bemapping ~~comparable~~costs. orThese ~~indicative~~costs were offset by $11.1 million of ~~future~~geophysical ~~results~~costs for the drilling of certain developmental well and $0.2 million of sand mine exploration costs.

64 40

~~The~~ Table ~~table below summarizes certain~~ of ~~the results of operations and period-to-period comparisons for the periods indicated.~~Contents

	For the Year Ended December 31,
	2017			2016			2015
	(In thousands, except per share data)
Revenues and other income:
Oil sales	$	342,868		$	75,938		$	42,971
Natural gas sales		59,924			43,487			38,665
NGL sales		22,964			5,786			4,295
Other income		1,431			2,131			404
Total revenues and other income		427,187			127,342			86,335
Operating expenses:
Lease operating expenses		39,770			12,320			14,053
Gathering, processing and transportation		11,897			6,581			5,300
Taxes other than income tax		24,158			6,814			5,510
Depreciation, depletion and amortization		168,250			81,757			56,244
Impairment of proved oil and gas properties		—			—			9,312
General and administrative expenses		40,663			23,973			15,903
Exploration expense		36,911			12,026			18,299
Other operating (income) expense		73			99			914
Total operating expenses		321,722			143,570			125,535
Income (loss) from operations		105,465			(16,228	)		(39,200	)
Other income (expense):
Interest expense		(31,934	)		(7,834	)		(6,943	)
Debt extinguishment costs		11			(1,667	)		—
Gain (loss) on derivative instruments		(55,483	)		(26,771	)		13,854
North Louisiana settlement		(7,000	)		—			—
Other income (expense)		(3	)		(151	)		(147	)
Total other income (expense)		(94,409	)		(36,423	)		6,764
Income (loss) before income taxes		11,056			(52,651	)		(32,436	)
Income tax benefit (expense)		38,824			5,575			(604	)
Net income (loss)		49,880			(47,076	)		(33,040	)
Net income (loss) allocated to previous owners		—			(2,681	)		(3,085	)
Net income (loss) allocated to predecessor		—			(33,998	)		(29,955	)
Net income (loss) available to WRD	$	49,880		$	(10,397	)	$	—
Net income (loss) per common share:
Basic and diluted	$	0.32		$	(0.11	)	n/a
Weighted-average common shares outstanding:
Basic and diluted		96,324			91,327		n/a
Oil and natural gas revenue:
Natural gas	$	59,924		$	43,487		$	38,665
Oil		342,868			75,938			42,971
NGLs		22,964			5,786			4,295
Total oil, natural gas and NGL revenue	$	425,756		$	125,211		$	85,931
Production volumes:
Natural gas (MMcf)		20,463			17,820			14,847
Oil (MBbls)		6,606			1,848			968
NGLs (MBbls)		1,206			471			351
Total (MBoe)		11,222			5,289			3,794
Average sales price:
Natural gas (per Mcf)	$	2.93		$	2.44		$	2.60
Oil (per Bbl)	$	51.90		$	41.09		$	44.41
NGLs (per Bbl)	$	19.04		$	12.28		$	12.22
Total (per Boe)	$	37.94		$	23.67		$	22.65
Average production volumes:
Natural gas (Mcf/d)		56.1			48.7			40.7
Oil (Bbls/d)		18.1			5.0			2.7
NGLs (Bbls/d)		3.3			1.3			1.0
Average net production (Boe/d)		30.7			14.5			10.4
Average unit costs per Boe:
Lease operating expenses	$	3.54		$	2.33		$	3.70
Gathering, processing and transportation	$	1.06		$	1.24		$	1.40
Taxes other than income tax	$	2.15		$	1.29		$	1.45
General and administrative expenses	$	3.62		$	4.53		$	4.19
Depletion, depreciation and amortization	$	14.99		$	15.46		$	14.82

Incentive unit compensation expense was $13.8 million for 2018 related to common stock distributions to incentive unit holders in May 2018. This non-cash charge was offset by a deemed capital contribution under the Esquisto Holding plan from NGP.

65· Interest expense was $60.1 million and $31.9 million for 2018 and 2017, respectively. The $28.2 million increase (approximately 88%) was primarily due to an increase in the average debt outstanding as a result of the issuance of $150 million and $200 million of 2025 Senior Notes in September 2017 and April 2018, respectively and increased borrowings under our revolving credit facility. Interest is comprised of interest on our credit facility, interest on our 2025 Senior Notes, premium/discount amortization on the 2025 Senior Notes and amortization of debt issue costs offset by capitalized interest. Capitalized interest was $5.9 million and $3.1 million for 2018 and 2017, respectively, primarily due to drilling activities.

Net gains on derivative instruments of $35.4 million were recognized during 2018, which consisted of a $145.2 million increase in the fair value of open positions and $109.8 million of cash settlements paid or accrued. Net losses on commodity derivatives of $55.5 million were recognized during 2017, which consisted of a $52.2 million decrease in the fair value of open positions and $3.3 million of cash settlements paid or accrued.

Income tax expense for 2018 was $40.2 million compared to an income tax benefit of $38.8 million for 2017. The effective tax rate differed from the statutory federal income tax rate of 21% for 2018 primarily due to incentive unit compensation, stock-based compensation, state tax adjustments associated with the NLA Divestiture, and the impact of the state income tax provision. The effective tax rate differed from the statutory federal income tax rate of 35% for 2017 primarily due to a change in tax rate as a result of the 2017 tax reform legislation informally known as the Tax Cuts and Jobs Act (the “Tax Act”), state income tax and changes in estimates related to a prior-period tax provision.

Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016

• For ~~Oil,~~purposes ~~natural gas and NGL revenues were $425.8 million for 2017 compared to $125.2 million for 2016, an increase~~ of ~~$300.6 million. Production increased 5.9 MMBoe primarily due to increased production from drilling successful wells in~~ the ~~Eagle~~following ~~Ford~~discussion, ~~the~~references ~~Acquisition~~to 2017 and ~~the December~~ 2016 ~~Burleson~~refer ~~North Acquisition. The average realized sales price increased $14.27 per Boe due~~ to ~~higher overall commodity prices and a higher percentage of oil in~~ the ~~production~~years ~~mix.~~ended ~~Oil~~December ~~revenues~~31, ~~increased~~2017 ~~$195.5 million~~ and ~~$71.4 million due to favorable production and pricing variances~~2016, respectively~~. Natural gas revenues increased $10.0 million and $6.5 million due to favorable pricing and production variances~~, ~~respectively.~~unless ~~NGL~~otherwise ~~revenues increased $8~~indicated.~~2 million and $9.0 million due to favorable price and volume variances, respectively.~~

•· ~~LOE~~Oil, ~~was~~natural ~~$39.8~~gas ~~million~~ and NGL revenues were $12425.38 million for 2017 ~~and~~compared ~~2016,~~to ~~respectively. On a per Boe basis, LOE was~~ $3125.~~54 and $~~2~~.33~~ million for ~~2017 and~~ 2016, ~~respectively.~~an ~~The~~ increase inof ~~LOE~~$300.6 onmillion. aRevenue ~~per~~increased ~~unit~~because ~~basis~~production ~~was~~increased ~~largely~~5.9 ~~attributable~~MMBoe toand ~~the~~an ~~Acquisition~~increase ~~and~~in the ~~Burleson~~average ~~North~~realized ~~Acquisition~~sales ~~that~~price ~~came~~of ~~with~~$14.27 ~~less~~per ~~efficient~~Boe ~~legacy~~due ~~wells and~~ to higher ~~workover~~overall ~~expense.~~commodity Weprices ~~recorded~~and ~~$7.7~~a ~~million~~higher ofpercentage ~~workover expenses in 2017. Net production in 2017 consisted~~ of ~~59%~~ oil ~~compared to 35% oil~~ in ~~2016, an increase of approximately 68%. Generally,~~ the production ~~of oil is more expensive than natural gas on a per Boe basis~~mix.

•· ~~GP&T~~LOE ~~expenses~~was ~~were~~ $1139.98 million and $612.63 million for 2017 and 2016, respectively. On a per Boe basis, ~~GP&T~~LOE ~~expenses~~was ~~were~~ $13.0654 and $12.2433 for 2017 and 2016, respectively. The increase in ~~total~~LOE ~~GP&T~~on ~~expenses~~a per unit basis was ~~primarily~~largely attributable to ~~increased~~acquisitions ~~expenses~~that ~~associated~~came with less efficient legacy wells and to higher ~~production~~workover expense. OnWe arecorded ~~per~~$7.7 ~~Boe~~million ~~basis,~~of ~~the~~workover ~~decrease~~expenses isin ~~primarily~~2017. ~~due~~Net production in 2017 consisted of 59% oil compared to an35% ~~increase~~oil in ~~production~~2016, ~~from~~an ~~our~~increase ~~drilling~~of ~~activities~~approximately 68%.

•· ~~Taxes~~GP&T ~~other~~expenses ~~than income tax~~ were $2411.29 million and $6.86 million for 2017 and 2016, respectively. ~~The~~On ~~$17.4~~a ~~million~~per ~~increase~~Boe ~~was primarily due to higher price realizations~~basis, ~~changes~~GP&T inexpenses ~~commodity~~were ~~mix,~~$1.06 ~~higher~~and ad$1.24 ~~valorem~~for ~~taxes~~2017 ~~associated~~and ~~with increased property valuations~~2016, ~~and~~respectively. ~~Louisiana~~The ~~franchise~~increase ~~taxes~~in ~~incurred~~total asGP&T aexpenses ~~result~~was ofprimarily ~~our~~attributable ~~Corporate~~to ~~Reorganization~~increased ~~that~~expenses ~~occurred~~associated ~~in conjunction~~ with ~~our~~higher ~~initial public offering~~production. On a per Boe basis, ~~taxes~~the ~~other~~decrease ~~than~~is ~~income~~primarily ~~tax~~due ~~were~~to ~~$2.15~~an ~~and~~increase ~~$1.29~~in ~~for~~production ~~2017~~from ~~and~~our ~~2016,~~drilling ~~respectively~~activities.

•· ~~DD&A~~Taxes ~~expense~~other ~~for~~than ~~2017~~income ~~was~~tax were $~~168~~24.32 million ~~compared~~and to $816.8 million for 2017 and 2016, anrespectively. The $8617.54 million increase was primarily due to anhigher ~~increase~~realized prices, changes in ~~production~~commodity ~~volumes~~mix, ~~related~~higher toad ~~drilling~~valorem ~~and~~taxes ~~acquisition~~associated ~~activities.~~with ~~Increased~~increased ~~production~~property ~~volumes~~valuations, ~~caused~~and ~~DD&A~~Louisiana ~~expense~~franchise totaxes ~~increase~~incurred byas ~~$91.7~~a ~~million~~result ~~and~~of ~~the~~our ~~change~~Corporate Reorganization that occurred in ~~the~~conjunction ~~DD&A~~with ~~rate~~our ~~between~~initial ~~periods~~public ~~caused~~offering. ~~DD&A~~On ~~expense~~a toper ~~decrease~~Boe bybasis, taxes other than income tax were $5.2.15 ~~million~~and $1.29 for 2017 and 2016, respectively.

•· WeDD&A ~~did~~expense ~~not~~for ~~record~~2017 ~~impairment~~was ~~expenses~~$168.3 onmillion ~~our~~compared ~~proved~~to ~~properties in 2017 and 2016~~$81.8 Inmillion ~~evaluating~~for ~~impairment~~2016, ~~the~~an ~~estimated~~$86.5 ~~future~~million ~~cash~~increase ~~flows~~primarily ~~expected~~due ~~from~~to ~~properties~~an ~~are~~increase ~~compared~~in toproduction ~~their~~volumes ~~carrying~~related ~~values~~ to ~~determine~~drilling ifand ~~the~~acquisition ~~cash flows are unrecoverable~~activities. Increased

• G&A expenses were $40.7 million and $24.0 million for 2017 and 2016, respectively. The $16.7 million increase was primarily due to increased staffing for 2017 compared to 2016 and increased costs associated with being a public company offset by costs recorded in 2016 associated with our initial public offering. Salaries and wages increased by $9.7 million in 2017 primarily due to additional staffing, and we recorded $6.6 million in stock-based compensation costs related to our 2016 LTIP compared to $0.1 million in 2016. During 2017, acquisition expenses increased by $3.9 million due primarily to the Acquisition, which was completed on June 30, 2017. Our previous owner recorded $4.0 million of G&A accrual payable to its members during 2016. Costs related to director fees and officer liability insurance increased $0.9 million between 2016 and 2017. Accounting and audit service fees increased $1.0 million between 2016 and 2017. In 2016, we and our previous owner recorded $1.0 million and $0.6 million, respectively, of initial public offering costs. 41

• Table Exploration expense was $36.9 million and $12.0 million for 2017 and 2016, respectively. The $24.9 million increase in exploration expense was primarily associated with an increase in undeveloped leasehold impairments and abandonments of $17.8 million primarily related to North Louisiana, an increase in seismic acquisitions and other geophysical expense of $12.0 million, and a $1.8 million increase in maps, logging and drafting expenses offset by $6.7 million in expenses associated with the early termination of a rig contract, which was laid down in March 2016 due to low commodity prices.Contents

•production ~~Interest~~volumes ~~expense~~caused ~~was~~DD&A ~~$31.9~~expense ~~million and $7.8 million for 2017 and 2016, respectively. The $24.1 million increase was primarily due~~ to an increase in the average debt outstanding as a result of the issuance of the 2025 Senior Notes. Interest is comprised of interest on our credit facilities, interest on our senior notes and amortization of debt issue costs offset by ~~capitalized interest. Interest expense before the amortization of debt issuance costs and capitalized interest was~~ $3291.~~5 million and $~~7.4 million ~~for 2017~~ and ~~2016,~~the ~~respectively.~~change ~~Amortization~~in ofthe ~~debt~~DD&A ~~issue~~rate ~~costs~~between ~~was~~periods ~~$2.6~~caused ~~million~~DD&A ~~for~~expense ~~2017 compared~~ to ~~less~~decrease ~~than~~by $0.5 ~~million for 2016~~.2 ~~Capitalized interest was $3.1~~ million ~~for 2017 due to increased drilling activities compared to less than $0~~.~~1 million for 2016.~~

•· ~~Debt~~We ~~extinguishment~~did ~~costs~~not ~~were~~record ~~$1.7~~impairment ~~million~~expenses inon ~~2016 due to the write-off of unamortized debt issuance costs associated with the WHR II and Esquisto credit facilities that were terminated in connection with~~ our ~~initial~~proved ~~public~~properties ~~offering. Esquisto also retired and terminated their revolving credit facility and second lien~~ in ~~January~~2017 ~~2016 in connection with the merger of Esquisto I~~ and ~~Esquisto II~~2016.

66· G&A expenses were $40.7 million and $24.0 million for 2017 and 2016, respectively. The $16.7 million increase was primarily due to increased staffing for 2017 compared to 2016 and increased costs associated with being a public company offset by costs recorded in 2016 associated with our initial public offering. Salaries and wages increased by $9.7 million in 2017 primarily due to additional staffing, and we recorded $6.6 million in stock-based compensation costs related to our 2016 LTIP compared to $0.1 million in 2016.

•· ~~During~~Exploration ~~2017,~~expense wewas ~~recognized~~$36.9 amillion and $5512.50 million ~~loss~~for on2017 ~~derivative~~and ~~instruments~~2016, ofrespectively. ~~which~~The $324.39 million ~~was~~increase ain ~~realized~~exploration ~~loss~~expense ~~and~~was aprimarily ~~$52.2~~associated ~~million~~with ~~was~~ an ~~unrealized~~increase ~~loss.~~in ~~Net~~undeveloped ~~losses~~leasehold onimpairments ~~commodity~~and ~~derivatives~~abandonments of $2617.8 million ~~were~~primarily ~~recognized~~related ~~during~~to ~~2016~~North Louisiana, ofan ~~which~~increase in seismic acquisitions and other geophysical expense of $412.50 million, ~~was~~and a ~~realized~~$1.8 ~~gain~~million increase in maps, logging and drafting expenses offset by $316.37 million in expenses associated with the early termination of a rig contract, which was anlaid ~~unrealized~~down ~~loss~~in March 2016 due to low commodity prices.

•· OnInterest ~~February~~expense 1,was ~~2018,~~$31.9 wemillion ~~entered~~and ~~into~~$7.8 ~~the~~million ~~North~~for ~~Louisiana~~2017 ~~Settlement~~and 2016, respectively. ~~Pursuant~~The $24.1 million increase was primarily due to ~~such~~an ~~settlement,~~increase in the ~~third~~average ~~party~~debt ~~agreed~~outstanding toas ~~pay~~a result of the ~~actual~~issuance ~~net~~of ~~costs~~$350 ~~attributable~~million toand ~~interests~~$150 inmillion ~~certain~~of ~~leases~~2025 ~~and/or~~Senior ~~wells~~Notes itin ~~elected~~February toand ~~acquire~~September 2017, respectively. WeInterest ~~agreed~~is tocomprised ~~provide~~of ~~the~~interest ~~third~~on ~~party~~our ~~with~~credit afacilities, ~~$7.0~~interest ~~million~~on ~~credit~~our ~~towards~~senior ~~purchasing~~notes ~~the~~and ~~interests~~amortization ~~selected~~of bydebt ~~the~~issue ~~third~~costs ~~party.~~offset ~~The~~by ~~settlement~~capitalized ~~loss~~interest. ofCapitalized interest was $73.01 million ~~was~~for ~~partially~~2017 ~~offset~~due byto aincreased ~~tax~~drilling ~~benefit~~activities ofcompared to less than $10.61 million for 2016.

•· ~~Income~~During ~~tax~~2017, ~~benefits~~we ~~were~~recognized ~~$38.8~~a ~~million and~~ $555.65 million ~~for~~loss ~~2017~~on ~~and~~derivative ~~2016~~instruments, ~~respectively. The increase~~ of which $333.23 million was ~~primarily~~a ~~due~~realized toloss and a $4352.42 million ~~deferred~~was ~~tax~~an ~~benefit~~unrealized inloss. ~~2017~~Net ~~resulting~~losses ~~from~~on ~~the~~commodity ~~Tax~~derivatives ~~Act,~~of ~~partially offset by~~ $1026.28 million ~~associated~~were ~~with~~recognized ~~pretax~~during ~~income in 2017 as compared to the pretax loss in~~ 2016, ~~and~~of ~~the~~which ~~change in our tax status from a pass-through entity to corporation subsequent to our initial public offering in 2016~~$4.5 ~~The~~million ~~effective~~was ~~tax rate for 2017 differed from the federal statutory income tax rate primarily due to~~ a ~~change~~realized ingain ~~tax rate, state income tax~~ and ~~changes in estimates related to a prior-period tax provision~~$31.3 ~~The~~million ~~effective~~was ~~tax~~an ~~rate~~unrealized ~~for 2016 differed from the federal statutory income tax rate primarily due to the impact of pass-through entities and state income tax~~loss.

~~Year~~· ~~Ended~~We ~~December~~entered 31into the North Louisiana Settlement. Pursuant to such settlement, ~~2016~~we ~~Compared~~agreed to provide a $7.0 million credit to the ~~Year~~third ~~Ended~~party ~~December~~towards ~~31,~~purchasing ~~2015~~the interests selected by the third party. The settlement loss of $7.0 million was partially offset by a tax benefit of $1.6 million.

•· ~~Oil,~~Income ~~natural~~tax ~~gas~~benefits ~~and~~were ~~NGL~~$38.8 ~~revenues~~million ~~were~~and $~~125~~5.26 million for 2017 and 2016, ~~compared~~respectively. toThe increase of $8533.92 million ~~for~~was ~~2015,~~primarily andue ~~increase~~to ofa $3943.34 million. ~~Production~~deferred ~~increased~~tax 1benefit in 2017 resulting from the Tax Act partially offset by $10.52 ~~MMBoe~~million ~~primarily~~associated ~~due~~with topretax ~~increased~~income ~~production~~in ~~from~~2017 ~~drilling~~as ~~successful~~compared ~~wells~~to the pretax loss in 2016 and the ~~Eagle~~change ~~Ford~~in our tax status from a pass-through entity to corporation subsequent to our initial public offering in 2016. The ~~average~~effective ~~realized~~tax ~~sales~~rate ~~price~~for ~~increased~~2017 ~~$1.02~~differed ~~per~~from ~~Boe~~the ~~due~~federal tostatutory aincome ~~higher~~tax ~~percentage~~rate ofprimarily ~~oil~~due to a change in ~~the~~tax ~~production~~rate, ~~mix.~~state Aincome ~~favorable~~tax ~~oil~~and ~~production~~changes ~~variance~~in ~~contributed~~estimates related to a ~~$39~~prior-period tax provision.1 ~~million~~The ~~increase~~effective intax ~~oil~~rate ~~revenues~~for ~~offset~~2016 bydiffered afrom ~~$6.1~~the ~~million~~federal ~~decrease~~statutory income tax rate primarily due to anthe ~~unfavorable~~impact ~~pricing~~of ~~variance~~pass-through entities and state income tax.

• LOE was $12.3 million and $14.1 million for 2016 and 2015, respectively. The decrease primarily is due to operational efficiencies, lower workover expense and lower service costs associated with industry-wide service cost decreases. On a per Boe basis, LOE was $2.33 and $3.70 for 2016 and 2015, respectively. The decrease was due to lower total LOE and certain items, such as direct labor and materials and supplies, generally remaining relatively fixed across broad production volume ranges.

• GP&T expenses were $6.6 million and $5.3 million for 2016 and 2015, respectively. On a per Boe basis, GP&T expenses were $1.24 and $1.40 for 2016 and 2015, respectively. The increase in total GP&T expenses was primarily attributable to an increase in production. The decrease on a per Boe basis was primarily due to an increase in production from our drilling activities.

• Taxes other than income tax were $6.8 million and $5.5 million for 2016 and 2015, respectively. The $1.3 million increase was primarily due to an increase in revenues associated with our oil and natural gas properties. On a per Boe basis, taxes other than income tax were $1.29 and $1.45 for 2016 and 2015, respectively. The decrease was primarily due to severance tax exemptions on high cost horizontal wells.

• DD&A expense for 2016 was $81.8 million compared to $56.2 million for 2015, a $25.6 million increase primarily due to an increase in production volumes related to drilling activities. Increased production volumes caused DD&A expense to increase by $22.2 million and the change in the DD&A rate between periods caused DD&A expense to increase by $3.4 million.

• We did not record impairment expense in 2016 compared to $9.3 million for 2015. The 2015 impairments primarily related to certain non-core properties located in Texas and Louisiana. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily due to declining commodity prices.

• G&A expenses were $24.0 million and $15.9 million for 2016 and 2015, respectively. Salaries and wages increased by $2.6 million primarily due to the successful completion of our initial public offering. Reduction in G&A reimbursements of $1.9 million associated with the termination of a management services agreement with a related party in February 2015 also contributed to the period-to-period increase in G&A expenses. We recorded approximately $1.0 million of initial public offering expenses during 2016. Esquisto recorded G&A expenses of $7.2 million during 2016 compared to $5.0 million from February 17, 2015 to December 31, 2015. During the year ended December 31, 2016, Esquisto accrued $4.0 million, as G&A expenses payable to its members compared to $3.6 million during the period from February 17, 2015 to December 31, 2015. Esquisto paid Petromax Operating Company, Inc. (“Petromax”), who was the operator of the majority of Esquisto’s wells, $1.3 million during the year ended December 31, 2016 and $0.9 million during the period from February 17, 2015 to December 31, 2015 for overhead charges on drilling and producing wells at market rates as set forth in joint operating agreements and in accordance with an operating agreement between Petromax and Esquisto. Esquisto also recorded $0.6 million of expenses related to our initial public offering during 2016.

• Exploration expense was $12.0 million and $18.3 million for 2016 and 2015, respectively. The $6.3 million reduction in exploration expense was primarily due to a reduction in exploration dry hole costs of $7.2 million and a reduction in seismic acquisitions of $4.2 million, offset by $6.8 million in expenses associated with the early termination of a rig contract, which was laid down in March 2016 due to low commodity prices.

• Interest expense was $7.8 million and $6.9 million for 2016 and 2015, respectively. The increase was due to an increase in the average debt outstanding. Interest is comprised of interest on our credit facilities and amortization of debt issue costs.

• Debt extinguishment costs were $1.7 million in 2016 due to the write-off of unamortized debt issuance costs associated with the WHR II and Esquisto credit facilities that were terminated in connection with our initial public offering. Esquisto also retired and terminated their revolving credit facility and second lien in January 2016 in connection with the merger of Esquisto I and Esquisto II. There were no debt extinguishment costs in 2015.

• Net losses on commodity derivatives of $26.8 million were recognized during 2016, of which $4.5 million was a realized gain and $31.3 million was an unrealized loss. During 2015, we recognized a $13.9 million gain on derivative instruments, of which $12.0 million was a realized gain and a $1.9 million was unrealized gain.

• Income tax benefit was $5.6 million for 2016 as compared to income tax expense of a $0.6 million for 2015. The $6.2 million increase was primarily a result of being a corporation subject to federal and state income tax subsequent to our initial public offering. The effective tax rate for 2016 differed from the federal statutory income tax rate primarily due to the impact of pass-through entities and state income tax. The effective tax rate for 2015 differed from the federal statutory income tax rate primarily due to the impact of pass-through entities and state income tax.

Adjusted EBITDAX

Adjusted EBITDAX is a supplemental non-GAAP financial performance measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We include in this Annual Report the non-GAAP financial measure Adjusted EBITDAX and provide our calculation of Adjusted EBITDAX. Adjusted EBITDAX is not a measure of net (loss) income as determined according to GAAP.

We define Adjusted EBITDAX as net income (loss):

Plus:

• Interest expense;

• Income tax expense;

• Depreciation, depletion and amortization (“DD&A”);

• Exploration expense;

• Impairment of proved oil and gas properties;

• Loss on derivative instruments;

• Cash settlements received on expired derivative instruments;

• Stock-based compensation;

• Incentive-based compensation expenses;

• Acquisition related costs;

• Debt extinguishment costs;

• Loss on sale of properties;

• Initial public offering costs;

• North Louisiana Settlement; and

• Other non-cash and non-routine operating items that we deem appropriate.

Less:

• Interest income;

• Income tax benefit;

• Gain on derivative instruments;

• Cash settlements paid on expired commodity derivative instruments;

• Gain on sale of properties; and

• Other non-cash and non-routine operating items that we deem appropriate.

Management believes Adjusted EBITDAX is a useful performance measure because it allows them to more effectively evaluate our operating performance without regard to our financing methods or capital structure. We exclude the items listed above from net (loss) income in arriving at Adjusted EBITDAX 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 EBITDAX should not be considered as an alternative to, or more meaningful than, net (loss) income as determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX 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 EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDAX to net (loss) income, our most directly comparable financial measure calculated and presented in accordance with GAAP.

	For the Year Ended December 31,
	2017			2016			2015
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$	49,880		$	(47,076	)	$	(33,040	)
Interest expense, net		31,934			7,834			6,943
Income tax (benefit) expense		(38,824	)		(5,575	)		604
Depreciation, depletion and amortization		168,250			81,757			56,244
Exploration expense		36,911			12,026			18,299
Impairment of proved oil and gas properties		—			—			9,312
(Gain) loss on derivative instruments		55,483			26,771			(13,854	)
Cash settlements received (paid) on derivative instruments		1,517			4,975			11,517
Stock-based compensation		6,644			68			—
Acquisition related costs		4,348			553			593
(Gain) loss on sale of properties		—			43			—
Debt extinguishment costs		(11	)		1,667			—
Initial public offering costs		182			1,560			—
North Louisiana settlement		7,000			—			—
Non-cash liability amortization		—			(286	)		(760	)
Total Adjusted EBITDAX	$	323,314		$	84,317		$	55,858

Liquidity and Capital Resources

Our development and acquisition activities require us to make significant operating and capital expenditures. Our primary use of capital has been the acquisition and development of oil, natural gas and NGL properties and facilities. As we pursue reserve and production growth, we plan to monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Historically, WHR II’s and Esquisto’s primary sources of liquidity were capital contributions from their former owners, borrowings under their respective revolving credit facilities and second lien loans and cash generated by their operations.

~~Our~~ Based ~~future~~on ~~success~~our incurrent ~~growing~~oil ~~proved~~and ~~reserves~~natural gas price expectations, we believe our cash flows provided by operating activities and ~~production~~availability ~~will~~under beour ~~highly~~revolving ~~dependent~~credit onfacility will provide us with the ~~capital~~financial ~~resources~~flexibility ~~available~~and wherewithal to ~~us.~~meet ~~Our~~our ~~2017~~cash ~~capital~~requirements, ~~expenditures~~including ~~(not~~normal ~~including~~operating ~~$533.6~~needs, ~~million~~and ~~related~~pursue toour currently planned development drilling activities over the ~~Acquisition)~~next ~~were~~twelve ~~$931~~months.0 ~~million~~However, future cash flows are subject to a number of ~~which~~variables, ~~$837.5~~including ~~million~~the ~~was~~level ~~allocated~~of toour ~~Eagle~~oil ~~Ford~~and ~~locations~~natural gas production and ~~$93.5~~the ~~million~~prices towe ~~North~~receive ~~Louisiana.~~for our oil and natural gas production, and significant

Based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned 2018 development drilling activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all. 42

69 Table of Contents

Asadditional ~~of December 31, 2017, we had $0.2 million of cash and cash equivalents and $588.6 million of available borrowings under our revolving credit facility. As of December 31, 2017, we had a working~~ capital ~~deficit~~expenditures ~~balance~~will ofbe ~~$221.1~~required ~~million, primarily due~~ to ~~the~~more ~~accrual~~fully ofdevelop ~~capital~~our ~~expenditures.~~properties ~~As of December 31, 2017, the borrowing base under the Credit Agreement was $875.0 million~~ and weacquire ~~had~~additional ~~$286~~properties.4

Filing Compare · Brazos Valley Longhorn, L.L.C.