WildHorse Resource Development Corp (Form: S-1/A, Received: 11/23/2016 06:10:07)

Large accelerated filer

Accelerated filer

Non-accelerated filer

þ (Do not check if a smaller reporting company)

Smaller reporting company

As filed with the Securities and Exchange Commission on November 23, 2016.

Registration No. 333-214569

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 2

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

WildHorse Resource Development Corporation

(Exact name of registrant as specified in its charter)


Delaware	1311	81-3470246
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(IRS Employer Identification Number)
	9805 Katy Freeway, Suite 400 Houston, TX 77024 (713) 568-4910

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Jay C. Graham

Chief Executive Officer

9805 Katy Freeway, Suite 400

Houston, TX 77024

(713) 568-4910

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Douglas E. McWilliams

Michael S. Telle

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

(713) 758-2222

Sean T. Wheeler

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

Approximate date of commencement of proposed sale of the securities to the public : As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

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

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state or jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated November 23, 2016

PROSPECTUS

LOGO

WildHorse Resource Development Corporation

Common Stock

This is the initial public offering of the common stock of WildHorse Resource Development Corporation, a Delaware corporation. We are offering shares of common stock.

Prior to this offering, there has been no public market for our common stock. The initial public offering price of our common stock is expected to be between $ and $ per share. We have been approved to list our common stock on the New York Stock Exchange under the symbol “WRD.”

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Prospectus Summary—Emerging Growth Company Status.”

Investing in our common stock involves risks. See “ Risk Factors ” on page 23.


	Per Share	Total
Price to the public	$	$
Underwriting discounts and commissions	$	$
Proceeds to us (before expenses)	$	$

We have granted the underwriters the option to purchase up to additional shares of common stock on the same terms and conditions as set forth above to the extent the underwriters sell more than shares of common stock in this offering.

See “Underwriting (Conflicts of Interest)” beginning on page 172 of this prospectus for additional information regarding underwriter compensation.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares of common stock on or about , 2016.

Book-Running Managers


Barclays		BofA Merrill Lynch		BMO Capital Markets


Citigroup		Wells Fargo Securities

Co-Managers


Guggenheim Securities		J.P. Morgan		Raymond James


Simmons & Company International		Tudor, Pickering, Holt & Co.
Energy Specialists of Piper Jaffray


Capital One Securities		Comerica Securities		Scotia Howard Weil		Wunderlich

Prospectus dated , 2016.

LOGO

TABLE OF CONTENTS


PROSPECTUS SUMMARY			1
RISK FACTORS			23
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			51
USE OF PROCEEDS			53
DIVIDEND POLICY			54
CAPITALIZATION			55
DILUTION			57
SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA			59
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			61
BUSINESS			101
MANAGEMENT			138
EXECUTIVE COMPENSATION			143
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			155
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			158
DESCRIPTION OF CAPITAL STOCK			162
SHARES ELIGIBLE FOR FUTURE SALE			167
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS			169
INVESTMENT IN WILDHORSE RESOURCE DEVELOPMENT CORPORATION BY EMPLOYEE BENEFIT PLANS			173
UNDERWRITING (CONFLICTS OF INTEREST)			175
LEGAL MATTERS			183
EXPERTS			183
WHERE YOU CAN FIND MORE INFORMATION			184
INDEX TO FINANCIAL STATEMENTS			F-1
ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS			A-1

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or the information to which we have referred you. We and the underwriters have not authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date. We will update this prospectus as required by law, including with respect to any material change affecting us or our business prior to the completion of this offering.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Until , 2016 (25 days after the date of this prospectus), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Commonly Used Defined Terms

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

•

“WildHorse Development,” “we,” “our,” “us” or like terms refer collectively to WildHorse 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 WildHorse, Esquisto and Acquisition Co., as of and following the completion of our Corporate Reorganization. Information expressed on a pro forma basis gives effect to certain transactions more fully described herein as if they had occurred (i) on January 1, 2014 or January 1, 2015, as applicable, for pro forma statements of operations purposes, (ii) on September 30, 2016 for pro forma balance sheet purposes and (iii) on January 1, 2014 or January 1, 2015, as applicable, for production and other operating data. For further details, please read “Prospectus Summary—Summary Pro Forma Financial Data;”

•

“WildHorse” or our “predecessor” refers to WildHorse Resources II, LLC, together with its consolidated subsidiaries, which owns all of our North Louisiana Acreage;

•

“Esquisto” refers (i) for the period beginning January 1, 2014 through June 19, 2014, to the Initial Esquisto Assets, (ii) for the period beginning June 20, 2014 through July 30, 2015, to Esquisto I, (iii) for the period beginning July 31, 2015 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 date hereof, to Esquisto II (which merged with Esquisto I on that date in the Esquisto Merger); Esquisto owns all of our Eagle Ford Acreage;

•

“Existing Owners” refers, collectively, to (i) NGP and (ii)(a) in the case of WildHorse, the Management Members that directly or indirectly own equity interests in WildHorse prior to the completion of the Corporate Reorganization and in WildHorse Holdings as of and following the completion of the Corporate Reorganization and (b) in the case of Esquisto, the Management Members that directly or indirectly own equity interests in Esquisto prior to the completion of the Corporate Reorganization and in Esquisto Holdings as of and following the completion of the Corporate Reorganization;

•

“Management Members” refers (i) in the case of WildHorse, collectively to the individual founders and employees and other individuals who, together with NGP, initially formed WildHorse and (ii) in the case of Esquisto, collectively to the individual founders and employees and other individuals who initially formed Esquisto;

•

“Initial Esquisto Assets” refers to the oil and natural gas properties contributed to Esquisto I in connection with the formation of Esquisto I on June 20, 2014, which contribution we refer to as the “contribution of the Initial Esquisto Assets;”

•

“Esquisto I” refers to Esquisto Resources, LLC;

•

“Esquisto II” refers to Esquisto Resources II, LLC;

•

“Esquisto Merger” refers to the merger of Esquisto I with and into Esquisto II on January 12, 2016;

•

“Acquisition Co.” refers to WHE AcqCo., LLC, an entity recently formed to acquire the Burleson North Assets;

•

the “Corporate Reorganization” refers to (i) the current owners of WildHorse exchanging all of their interests in WildHorse for equivalent interests in WildHorse Investment Holdings and the current 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 WildHorse, the contribution by Esquisto Investment Holdings to Esquisto Holdings of all of the interests in Esquisto and the contribution by the current 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 officers

and employees as described in this prospectus and (iv) the contribution by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings to us of all of the interests in WildHorse, Esquisto and Acquisition Co., respectively, in exchange for shares of our common stock (prior to and in connection with the issuance of shares of common stock in this offering), as described more fully in “Prospectus Summary—Corporate Reorganization;”

•

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

•

“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 to be issued by WildHorse Holdings in connection with this offering as further described elsewhere in this prospectus;

•

“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 to be issued by Esquisto Holdings in connection with this offering as further described elsewhere in this prospectus;

•

“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 WildHorse, and where we primarily target the overpressured Cotton Valley play;

•

“Terryville Complex” refers to the play located primarily in Lincoln Parish, Louisiana, and northern Jackson Parish, Louisiana;

•

“RCT Area” refers to our Ruston-Choudrant-Tremont acreage within the Terryville Complex located primarily in Lincoln Parish, Louisiana;

•

“Weyerhaeuser Area” refers to the acreage that we have the right to lease within the Terryville Complex located in northern Jackson Parish, Louisiana, which acreage is included in our acreage in this prospectus (see “Business—Reserve Data—Acreage);

•

“Eagle Ford Acreage” refers to our acreage in the northern area of the Eagle Ford Shale in Southeast Texas, which has historically been owned and operated by Esquisto;

•

“Comstock Assets” refers to certain producing properties, undeveloped acreage and water assets Esquisto II acquired from a wholly owned subsidiary of Comstock Resources, Inc. in July 2015, which acquisition we refer to as the “Comstock Acquisition;”

•

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

•

“Acquisitions” refers to the acquisitions described in “Prospectus Summary—Recent Developments,” including the Burleson North Acquisition; and

•

“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 WildHorse, Esquisto and Acquisition Co.

We have also included a glossary of some of the oil and natural gas industry terms used in this prospectus in Annex A to this prospectus.

iii

Presentation of Financial and Operating Data

Unless otherwise indicated, the historical financial information presented in this prospectus is that of WildHorse, our predecessor for accounting purposes. The pro forma financial information presented in this prospectus treats the contribution to us of WildHorse and Esquisto in connection with our Corporate Reorganization as a reorganization of entities under common control as if it had occurred on January 1, 2014. Because WildHorse and Esquisto have been under common control since February 2015, once we file a balance sheet after this offering that reflects the completed Corporate Reorganization, prior period financial statements will be retroactively recast to be presented on a combined basis to include the results of Esquisto for periods during which Esquisto was under common control with WildHorse. Please see “Prospectus Summary—Corporate Reorganization” and the unaudited pro forma financial statements included elsewhere in this prospectus.

In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is that of our predecessor and Esquisto on a combined basis as of the dates and for the periods presented. Unless another date is specified or the context otherwise requires, all acreage, well count, hedging and drilling location data is presented in this prospectus as of September 30, 2016. Unless otherwise noted, references to production volumes refer to sales volumes.

Certain amounts and percentages included in this prospectus have been rounded. Accordingly, in certain instances, the sum of the numbers in a column of a table may not exactly equal the total figure for that column.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, we and the underwriters have not independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^® , TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our common stock. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the related notes to those financial statements, before investing in our common stock. The information presented in this prospectus assumes an initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters’ option to purchase additional shares of our common stock has not been exercised. Further, unless indicated otherwise or the context otherwise requires, references to our acreage, drilling locations, working interest and well counts as of September 30, 2016 in this prospectus are adjusted to give effect to the Acquisitions described in “—Recent Developments.” You should read “Risk Factors” for information about important risks that you should consider carefully before investing in our common stock. Certain common used terms are defined in “Commonly Used Defined Terms” or in the glossary included in this prospectus as Appendix A.

WildHorse Development

We are a growth-oriented, independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in Southeast Texas and North Louisiana with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. In Southeast Texas, we operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale (our “Eagle Ford Acreage”), which is one of the most active shale trends in North America. In North Louisiana, we operate in and around the highly prolific Terryville Complex, where we primarily target the overpressured Cotton Valley play (our “North Louisiana Acreage”).

We were formed by our management and technical teams and affiliates of Natural Gas Partners (“NGP”), a family of energy-focused private equity investment funds. Prior to our formation, the founding members of our management and technical teams successfully built and sold multiple NGP-sponsored oil and natural gas assets in and around the location of our acreage. Our Chief Executive Officer, Jay C. Graham, our President, Anthony Bahr, and other members of our management team, have significant experience across our acreage. Messrs. Graham and Bahr 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. Certain members of our technical team have also been actively involved in drilling in and around our Eagle Ford Acreage since 2008.

Since we commenced operations in 2013, our management and technical teams have successfully executed our development program, growing our acreage position to approximately 375,000 net acres. We have also grown our production from 4.5 MBoe/d for the three months ended March 31, 2014 to approximately 14.0 MBoe/d for the three months ended September 30, 2016, representing a compound annual growth rate (“CAGR”) of approximately 57%, as described below, and our production for the three months ended September 30, 2016 was 17.9 MBoe/d after giving pro forma effect to the Acquisitions.

As of September 30, 2016, we had assembled a total leasehold position of approximately 375,000 net acres across our expanding acreage, including approximately 267,000 net acres in the Eagle Ford and approximately 108,000 net acres in North Louisiana. We have identified a total of approximately 4,391 gross (2,298 net) drilling locations across our acreage, with further upside potential given the multiple stacked pay zones across much of our acreage. Based on our 2017 drilling program, our identified locations represent an inventory of approximately 46 years.

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. To date, our drilling program has predominantly targeted our Eagle Ford locations in Burleson County. While not included in our estimate of future horizontal drilling locations, we believe significant additional locations may also exist in the Austin Chalk trend in Burleson County and the Eagle Ford in Washington County. On our North Louisiana Acreage, our horizontal drilling locations target the Upper Red, Lower Red and Upper Deep Pink zones in the RCT and Weyerhaeuser Areas in the overpressured Cotton Valley formation in the Terryville Complex. To date, our drilling program has predominantly targeted our Upper Red locations in the RCT Area. While not included in our estimate of future horizontal drilling locations, we believe additional locations may also exist in additional Cotton Valley intervals across our North Louisiana Acreage.

The following chart provides information regarding our production growth since the first quarter of 2014:

LOGO

(1)	Includes production attributable to the Comstock Assets acquired in July 2015 for all periods presented.

(2)

Compound annual growth rate, or CAGR, represents a calculation of the average annual compounded growth rate of our average daily production from the first quarter of 2014 to the third quarter of 2016 by comparing our average daily production for the third quarter of 2016 to our average daily production for the first quarter of 2014. The calculation assumes that the growth rate derived from the calculation is even across the periods covered by the calculation and does not take into account any fluctuations in our production for any periods other than the two periods used to calculate the CAGR. Accordingly, the use of CAGR may have limitations, particularly in situations where there are substantial fluctuations in production between the periods used to make the calculation. For a more detailed description of how CAGR is calculated, please see the glossary included in this prospectus as Appendix A.

Our Drilling Program and Completion Techniques

Our primary objective is to deliver shareholder value through accretive growth in reserves, production and cash flow by developing and expanding our significant portfolio of drilling locations. We believe that our recent well results demonstrate that many of our wells are capable of producing attractive single-well rates of return that are competitive with many of the top performing basins in the United States. We are focused on generating shareholder value by drilling wells with high rates of returns and increasing estimated ultimate recoveries (“EURs”) while driving drilling, completion and operating efficiencies. Our technical expertise has resulted in cost efficiency gains as well as increased hydrocarbon recovery from our wells. For example, in our Eagle Ford Acreage, due to new drilling technologies and improved procedures, on average we were able to drill twice as many wells per rig during the nine months ended September 30, 2016 as we were able to drill during 2014. Additionally, due to improvements in well completions in our Eagle Ford Acreage, we have increased EURs by approximately 29% per completed lateral foot from an average of 76 Boe per foot for our wells completed using Generation 1 hydraulic fracturing design to 98 Boe per foot for our wells completed using Generation 3 hydraulic fracturing design.

In July 2015, we reduced our drilling program in our North Louisiana Acreage to one rig in response to low commodity prices and continued operating a one-rig drilling program through February 2016. Similarly, in early October 2015, we reduced our drilling program in our Eagle Ford Acreage to one rig, which we ran until February 2016, at which point we ceased drilling due to the commodity price environment. We are currently running a one-rig program in our Eagle Ford Acreage and we intend to add an additional rig in our North Louisiana Acreage in late 2016. We intend to add four additional rigs during the remainder of 2017 in order to run a six-rig program by the end of 2017 with four rigs drilling in our Eagle Ford Acreage and two rigs drilling in our North Louisiana Acreage.

The tables below detail certain information on estimated ultimate recoveries (“EUR”) and production for wells we have drilled to date. Please see “Business—Our Drilling Program” for more detail on our wells drilled in our Eagle Ford Acreage and North Louisiana Acreage.

Eagle Ford Wells(1)


Completion Technique	Well Count		Lateral Length (Feet)		EUR (Mboe) (2)		EUR (Mboe/ 1000’)(2)		Days Pro- ducing		Cumu- lative Prod. (MBoe)(3)		Gross Wellhead Flow Rates After Processing (Boe/d)(3)(4)								D&C ($MM)(5)		D&C ($/Lat Foot)(5)		% EUR Liq			% EUR Oil
													Gross Wellhead Flow Rates After Processing (Boe/d)(3)(4)
													0-30		0-90		91-180		181-360
Generation 1		7		6,225		443		76		739		155		745		568		297		177		13.5		2,958		88	%		71	%
Generation 2		15		6,447		523		81		401		122		611		508		318		216		7.1		1,111		87	%		69	%
Generation 3		9		6,739		633		98		145		67		743		492		481				6.2		966		93	%		78	%

(1)

Information included in this table represents our average well results in our Eagle Ford Acreage for each of our Generation 1, Generation 2 and Generation 3 completion techniques. For a description of the differences in completion techniques, please see “Business—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.” All wells drilled in our Eagle Ford Acreage have been located in our Burleson Main area.

(2)	EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report as of June 30, 2016 and cumulative sales from such location as of such date. EUR is shown on a combined basis for oil/condensate and gas.

(3)	Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.

(4)	The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.

(5)	Includes all wells drilled and completed as of September 30, 2016. Drilling and completion (“D&C”) costs exclude land costs and title fees.

North Louisiana Wells

Wells Drilled in Terryville Complex


Well Name	Formation		Completion Type(1)		Lateral Length (Feet)		EUR (Bcfe)(2)		EUR (BCFE/ 1000’)(2)		First Pro- duction		Days Pro- ducing		Cumu- lative Prod. (Bcfe)(3)		Gross Wellhead Flow Rates (MMcfe/d)(3)(4)								D&C ($MM)(5)		D&C ($/Lat Foot)(5)		% EUR Gas
																	Gross Wellhead Flow Rates (MMcfe/d)(3)(4)
																	0-30		0-90		91- 180		181- 360
Taylor 13 12 H-1		Upper Red		Gen 1		6,796		20.4		3.0		3/6/2015		575		5.0		21.8		17.7		9.6		6.7		14.8		2,180		98	%
Pipes 14 11 HC-1		Upper Red		Gen 1		8,221		2.3		0.3		5/19/2015		501		0.9		5.4		4.0		2.1		1.2		18.3		2,220		97	%
Spillers 18 7 HC-1		Upper Red		Gen 1		8,884		16.6		1.9		7/13/2015		446		3.7		19.4		15.0		8.6		6.2		11.6		1,303		98	%
Rounsaville 21 16 HC-1		Upper Red		Gen 1		4,633		0.3		0.1		8/21/2015		407		0.4		1.5		1.3		1.1				11.3		2,443		99	%
Surline 13 12 HC-1		Lower Red		Gen 1		7,210		0.3		0.0		9/3/2015		394		0.4		1.6		1.3		1.1				12.9		1,789		98	%
Ates 18 7 HC-1		Upper Red		Gen 2		6,705		12.7		1.9		11/17/2015		319		2.5		16.0		12.4		7.2				11.2		1,677		98	%
Smelley 15 22 H-1		Upper Red		Gen 2		8,410		16.4		1.9		12/3/2015		303		2.8		17.0		13.6		7.8				12.9		1,536		97	%
Taylor 13 12 H-2		Upper Red		Gen 1		4,594		5.9		1.3		1/8/2016		267		1.1		8.6		6.2		3.3				8.3		1,814		98	%
Pruitt 16 21 HC-1		Upper Red		Gen 1		9,102		10.8		1.2		3/25/2016		190		1.3		10.4		8.6						11.9		1,304		98	%

(1)	For a description of the differences in completion techniques, please see “Business—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.”

(2)	EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report and cumulative sales from such location. EUR is shown on a combined basis for oil/condensate and gas.

(3)	Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.

(4)	The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.

(5)	Includes wells drilled and completed as of September 30, 2016 in the Terryville Complex. D&C costs exclude land costs and title fees.


Average (1)	Well Count		Lateral Length (Feet)		EUR (Bcfe)(2)		EUR BCFE/ 1000’(2)		Days Pro- ducing		Cumu- lative Prod. (Bcfe)(3)		Gross Wellhead Flow Rates (MMcfe/d)(3)(4)								D&C ($MM)(5)		D&C ($/Lat Foot)(5)		% EUR Gas
Average (1)													Gross Wellhead Flow Rates (MMcfe/d)(3)(4)
Completion Technique													0-30		0-90		91- 180		181- 360
Generation 1		7		7,063		8.1		1.1		397		1.8		9.8		7.7		4.3		4.7		12.7		1,865		98	%
Generation 2		2		7,558		14.5		1.9		311		2.6		16.5		13.0		7.5				12.1		1,606		97	%

(1)

Information included in this table represents our average well results for wells drilled to date in the Terryville Complex in North Louisiana for each of our Generation 1 and Generation 2 completion techniques. For a description of the differences in completion techniques, please see “Business—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.”

(2)	EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report as of June 30, 2016 and cumulative sales from such location as of such date. EUR is shown on a combined basis for oil/condensate and gas.

(3)	Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.

(4)	The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.

(5)	Includes wells drilled and completed as of September 30, 2016 in the Terryville Complex. D&C costs exclude land costs and title fees.

Our Acreage and Drilling Locations

The table below provides a summary of our net acreage, average working interest, average net revenue interest and horizontal drilling locations as of September 30, 2016:


	Acreage								Horizontal Drilling Locations(3)(4)
	Net Acreage		Average WI %(1)			Average NRI %(2)			Gross		Net
Eagle Ford		266,501		82	%		64	%		2,977		1,650
North Louisiana(5)		108,437		74	%		57	%		1,414		648

Total		374,938		79	%		62	%		4,391		2,298

(1)	Represents our weighted average working interest across our acreage position.

(2)	Represents our weighted average net revenue interest across our acreage position.

(3)

Please see “Business—Our Properties—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see “Risk Factors—Risks Related to Our Business—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.”

(4)

We expect to operate 2,511 gross (1,943 net) of our 4,391 gross (2,298 net) horizontal drilling locations, of which 1,890 gross (1,509 net) are located on our Eagle Ford Acreage and 621 gross (434 net) are located on our North Louisiana Acreage. We have an approximate 80% and 70% average working interest in our operated horizontal drilling locations in our Eagle Ford and North Louisiana Acreage, respectively.

(5)	Includes acreage we have the right to lease pursuant to an oil and gas lease option agreement with affiliates of Weyerhaeuser Company. See “Business—Reserve Data—Acreage.”

Our extensive inventory of locations in East Texas primarily targets the Eagle Ford Shale. We subdivide our Burleson County acreage areas based on our assessment of depth and reservoir characteristics. To date, all of our drilling activity has been focused in our Burleson Main area; however, we own working interests in producing wells in each of the other areas and in our Eagle Ford Acreage. Our Burleson North acreage represents the acreage we intend to acquire from Clayton Williams Energy, Inc. prior to or contemporaneously with the closing of this offering. In North Louisiana, we target multiple horizons within the lower Cotton Valley including the Upper and Lower Red as well as the Upper Deep Pink. The following table provides information regarding our gross and net horizontal drilling locations by area as of September 30, 2016:


	Net Horizontal Drilling Locations										Gross Horizontal Drilling Locations
	Proved		Probable		Possible		Management		Total		Total
Eagle Ford:
Burleson Main		103		165		295		68		631		1,331
Burleson North		—		—		—		670		670		670
Burleson West		6		23		26		5		60		225
Burleson South		2		4		16		38		59		292
Washington County		2		7		4		—		12		36
Lee County		6		12		120		81		218		423

Total Eagle Ford		117		211		461		862		1,650		2,977


North Louisiana:
RCT
Upper Red		7		15		108		31		161		308
Lower Red		—		—		72		94		166		319
Upper Deep Pink		—		—		45		122		167		320
Weyerhaeuser
Upper Red		—		—		36		27		64		205
Lower Red		—		—		36		27		64		205
Bear Creek		—		—		26		2		28		57

Total North Louisiana		7		15		323		303		648		1,414

Our Reserve Information

We believe we have substantial reserves. The following table summarizes the estimated net proved, probable and possible oil, natural gas and NGL reserves of WildHorse and Esquisto on a combined basis as of June 30, 2016 without giving effect to any of the Acquisitions. Cawley, Gillespie & Associates (“Cawley”), our independent petroleum engineer, prepared Esquisto’s reserves estimates and audited WildHorse’s reserves estimates.


	Estimated Total Proved Reserves
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)		% Liquids			% Developed
Eagle Ford		49,003		26,518		7,269		60,692		93	%		21	%
North Louisiana		703		274,246		306		46,717		2	%		49	%

Total		49,706		300,764		7,575		107,409		53	%		33	%


	Estimated Total Probable Reserves
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)		% Liquids
Eagle Ford		60,675		26,758		7,439		72,574		94	%
North Louisiana		612		164,640		—		28,052		2	%

Total		61,287		191,398		7,439		100,626		68	%


	Estimated Total Possible Reserves
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)		% Liquids
Eagle Ford		105,989		46,761		12,887		126,669		94	%
North Louisiana		3,953		1,063,042		—		181,127		2	%

Total		109,942		1,109,803		12,887		307,796		40	%

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 the overpressured Cotton Valley formation in and around the Terryville Complex, 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 4,391 gross (2,298 net) drilling locations across our 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 67%, from $2,958 per foot for our wells completed using Generation 1 hydraulic fracturing design to approximately $966 per foot for our wells completed using Generation 3 hydraulic fracturing design, in part by drilling our last 18 wells in an average of approximately 11 days. 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 98 Boe per foot. In our North Louisiana Acreage, we have reduced our drilling and completion costs per completed lateral foot by approximately 22%, from approximately $1,987 per foot for the nine months ended September 30, 2015 to approximately $1,559 per foot for the nine months ended September 30, 2016. 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, (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage and (iv) additional Cotton Valley intervals across our North Louisiana 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 Acquisitions. 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 two basins and strategically expand those positions through bolt-on acquisitions over time. We believe our Eagle Ford and North Louisiana Acreage create 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, which, being a two-basin company, we believe will allow us to strategically deploy capital among projects across our acreage. After giving effect to this offering and the use of the proceeds (including the repayment and termination of the WildHorse revolving credit facility, the Esquisto revolving credit facility and the notes payable by Esquisto to its members), we will have approximately $ million of available borrowing capacity under our new revolving credit facility. We intend to fund our growth primarily with internally generated cash flows 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 two of North America’s leading oil and gas plays . We own an extensive and substantially contiguous acreage position targeting two of the premier plays in North America, the Eagle Ford Shale and the overpressured Cotton Valley formation in and around the Terryville Complex. As of September 30, 2016, we had approximately 375,000 net acres and, as of June 30, 2016, we had 107 MMBoe of proved reserves (46% oil, 47% natural gas and 7% NGLs), 101 MMBoe of probable reserves (61% oil, 32% natural gas and 7% NGLs) and 308 MMBoe of possible reserves (36% oil, 60% natural gas and 4% NGLs) across our acreage. We believe that our recent well results demonstrate that many of the wells on our high-quality acreage are capable of producing attractive 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 4,391 gross (2,298 net) drilling locations across our acreage position, providing us with approximately 46 years of drilling inventory based on our 2017 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, and on our North Louisiana Acreage, our horizontal drilling locations target the Upper Red, Lower Red and Upper Deep Pink zones in the RCT and Weyerhaeuser Areas in the overpressured Cotton Valley formation in the Terryville Complex. 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, (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage and (iv) additional Cotton Valley intervals across our North Louisiana 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.

Balanced asset portfolio with significant capital allocation optionality . We believe our balanced exposure to both oil and natural gas gives us the ability to adjust our capital plan and drilling program to rebalance our production as market conditions evolve. We have significant exposure to natural gas and NGLs in our North Louisiana Acreage and significant exposure to oil, natural gas and NGLs in our Eagle Ford Acreage. As of June 30, 2016, 53% and 47% of our total proved reserves were comprised of liquids and natural gas, respectively. In addition, 52% and 48% of our production for the nine months ended September 30, 2016 on a pro forma basis was comprised of liquids and natural gas, respectively. As changes in the commodity price environment occur, we intend to adapt and manage our capital spending and production profile to benefit from these trends.

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 and North Louisiana. 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, 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, as shown below in “ — Corporate Reorganization.” 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 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 North Louisiana Acreage, we own and operate a gathering system with capacity of approximately 250 MMcf/d as of September 30, 2016, as well as a saltwater disposal system. On our Eagle Ford Acreage, we own substantial fresh water supply and storage and are in the process of developing a saltwater disposal system. 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.

Recent Developments

Rosewood Acquisition

In September 2016, we agreed to acquire from certain third parties approximately 7,500 net acres, consisting primarily of additional working interests in our Eagle Ford Acreage in Lee County (the “Rosewood Acquisition”). The closing of the acquisition will occur contemporaneously with the closing of this offering, and we will issue shares to such third parties as consideration (based on the midpoint of the price range set forth on the cover page of this prospectus). The actual number of shares to be issued to such sellers will be determined by dividing the acquisition consideration value of approximately $19.6 million by the price per share

of our common stock in this offering. Accordingly, an increase or decrease in the initial public offering price will decrease or increase, as applicable, the number of shares to be issued to the sellers. For example, a $ decrease in the assumed initial public offering price would result in the sellers receiving an additional shares of our common stock. The acreage we will acquire includes one producing well that was producing approximately 30 Boe/d as of October 15, 2016 and results in the addition of approximately 78 net drilling locations to our drilling inventory.

Burleson North Acquisition

In October 2016, Acquisition Co. entered into a purchase and sale agreement with Clayton Williams Energy, Inc. to acquire approximately 158,000 net acres of oil and gas properties adjacent to our Eagle Ford Acreage (the “Burleson North Assets”) for a purchase price of $400.0 million in cash, subject to customary purchase price adjustments, $45.0 million of which was funded at signing by Acquisition Co. The Burleson North Assets produced an average of approximately 3.9 MBoe/d (80% oil) for the three months ended September 30, 2016 and added 670 gross and net drilling locations to our drilling inventory. We expect to close the Burleson North Acquisition prior to or contemporaneously with the closing of this offering, using a portion of the proceeds from this offering to fund the remaining purchase price.

November Acquisition

In November 2016, we acquired from certain third parties approximately 4,900 net acres in Burleson County for approximately $30.0 million (the “November Acquisition” and, together with the Burleson North Acquisition and the Rosewood Acquisition, the “Acquisitions”). The assets acquired in the November Acquisition were producing approximately 14 Boe/d as of October 1, 2016, and result in the addition of 68 gross (66 net) drilling locations to our drilling inventory.

Capital Program

We intend to develop our multi-year drilling inventory by utilizing our significant expertise in horizontal drilling to grow our production, reserves and cash flow. Our 2016 capital budget for drilling and completion, leasehold acquisition and midstream infrastructure development is $137.5 million, of which we have invested $99.8 million through September 30, 2016. We are currently running a one-rig program in our Eagle Ford Acreage and we intend to add one rig in our North Louisiana Acreage in late 2016. We intend to add four additional drilling rigs during 2017 in order to a run a six-rig program by the end of 2017 with four rigs drilling in our Eagle Ford Acreage and two rigs drilling in our North Louisiana Acreage. For the twelve months ending December 31, 2017, we plan to invest $539.5 million in capital expenditures as follows:

•

$471.2 million to drill and complete 81 gross (67 net) wells across our acreage as follows:

^¡

$409.0 million in our Eagle Ford Acreage to drill 84 gross (73 net) wells with an average lateral length of 6,406 feet, 72 gross (62 net) of which we expect to complete in 2017;

^¡

$62.2 million in our North Louisiana Acreage to drill 12 gross (seven net) wells with an average lateral length of 9,062 feet, nine gross (five net) of which we expect to complete in 2017;

•

$39.6 million for lease extension and renewals;

•

$22.3 million for midstream infrastructure development; and

•

$6.4 million in other investments, including seismic and capital workover projects.

We plan to fund our 2017 capital program through cash flow from operations and borrowings under our new $1.0 billion revolving credit facility. Further, we intend to monitor conditions in the debt capital markets and may determine to issue long-term debt securities, including potentially in the near term, to fund a portion of our 2017 capital program. We cannot predict with certainty the timing, amount and terms of any future issuances of any such debt securities.

By operating the majority of our acreage, the amount and timing of our capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including the success of our drilling activities, volatility in commodity prices, the availability of necessary equipment, infrastructure, personnel and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions and drilling and acquisition costs. Any reduction in our capital expenditure budget could have the effect of delaying or limiting our development program, which would negatively impact our ability to grow production and could materially and adversely affect our future business, financial condition, results of operations or liquidity. For further discussion of the risks we face, please read “Risk Factors—Risks Related to Our Business—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.”

Risk Factors

An investment in our common stock involves a number of risks that include the speculative nature of oil and natural gas exploration, competition, volatile commodity prices and other material factors. You should carefully consider, in addition to the other information contained in this prospectus, the risks described in “Risk Factors” before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment:

•

Oil, natural gas and NGL prices are volatile. A sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.

•

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.

•

Part of our business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

•

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.

•

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 obligations under applicable debt instruments, which may not be successful.

•

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.

•

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.

•

Our producing properties are located in the Eagle Ford and in North Louisiana, making us vulnerable to risks associated with operating in a limited number of geographic areas.

•

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.

•

The loss of senior management or technical personnel could adversely affect operations.

•

NGP has the ability to direct the voting of a majority of our common stock, and its interests may conflict with those of our other stockholders.

•

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.

•

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

Corporate Reorganization

We were incorporated under the laws of the State of Delaware in August 2016 to become a holding company for the assets and operations of WildHorse and Esquisto. WildHorse was founded in June 2013, with equity commitments from affiliates of NGP and its Management Members, and Esquisto was founded in June 2014.

Contemporaneously with this offering, (i) the current owners of WildHorse will exchange all of their interests in WildHorse for equivalent interests in WildHorse Investment Holdings and the current owners of Esquisto will exchange all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings will contribute all of the interests in WildHorse to WildHorse Holdings, Esquisto Investment Holdings will contribute all of the interests in Esquisto to Esquisto Holdings and the current owner of Acquisition Co. will contribute all of its interests in Acquisition Co. to Acquisition Co. Holdings, (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will issue management incentive units to certain of our officers and employees as described in this prospectus and (iv) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will contribute all of the interests in WildHorse, 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, WildHorse, Esquisto and Acquisition Co. will become direct, wholly owned subsidiaries of WildHorse Resource Development Corporation.

We were incorporated to serve as the issuer in this offering and have no previous operations, assets or liabilities. For more information on our reorganization and the ownership of our common stock by our principal stockholders, please see “Security Ownership of Certain Beneficial Owners and Management” and the unaudited pro forma financial statements included elsewhere in this prospectus.

The following diagram indicates our simplified ownership structure after giving effect to our Corporate Reorganization and this offering (assuming that the underwriters’ option to purchase additional shares is not exercised) and does not give effect to shares of common stock reserved for future issuance under the WildHorse Resource Development Corporation 2016 Long-Term Incentive Plan (our “LTIP”), as described in “Executive Compensation—2016 Long-Term Incentive Plan” or our intended grant of restricted shares of common stock to certain officers under such plan in connection with the successful completion of this offering. See “Executive Compensation—Narrative Disclosures—Compensation Following This Offering—IPO Bonuses” for more information.

LOGO

*	Includes shares issued in connection with the Rosewood Acquisition.

Our Principal Stockholders

Following the completion of this offering and our Corporate Reorganization, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will directly own %, % and %, respectively, of our common stock, or %, % and %, respectively, if the underwriters’ option to purchase additional shares is exercised in full. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings are controlled by NGP. Please see “—Corporate Reorganization.”

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”). For as long as we are an emerging growth company, unlike public companies that are not emerging growth companies under the JOBS Act, we will not be required to:

•

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 of 2002 (the “Sarbanes-Oxley Act”);

•

provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations;

•

comply with any new requirements adopted by the Public Company Accounting Oversight Board (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 our financial statements;

•

provide certain disclosures regarding executive compensation required of larger public companies or hold stockholder advisory votes on the executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”); or

•

obtain stockholder approval of any golden parachute payments not previously approved.

We will cease to be an emerging growth company upon the earliest of:

•

the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;

•

the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30);

•

the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

•

the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 9805 Katy Freeway, Suite 400, Houston, Texas 77024, and our telephone number at that address is (713) 568-4910.

Our website address is www.wildhorserd.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

The Offering

Issuer

WildHorse Resource Development Corporation.

Common stock offered by us

shares (or shares, if the underwriters exercise in full their option to purchase additional shares).

Common stock outstanding after this offering

shares (or shares, if the underwriters exercise in full their option to purchase additional shares).

Option to purchase additional shares

We have granted the underwriters a 30-day option to purchase up to additional shares of our common stock to the extent the underwriters sell more than shares of common stock in this offering.

Use of proceeds

We expect to receive approximately $ million of net proceeds, based upon the assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses payable by us. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $ million.

We intend to use the proceeds from this offering, along with borrowings under our new revolving credit facility, to (i) fund the remaining portion of the Burleson North Acquisition purchase price and (ii) repay in full and terminate the WildHorse revolving credit facility and the Esquisto revolving credit facility and repay in full all notes payable by Esquisto to its members. Please read “Use of Proceeds.”

Conflicts of Interest

Because an affiliate of each of Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and Comerica Securities, Inc. is a lender under the WildHorse revolving credit facility and/or the Esquisto revolving credit and will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings under such credit facilities, each of Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and Comerica Securities, Inc. is deemed to have a conflict of interest within the meaning of Rule 5121 of the Financial Industry Regulatory Authority, Inc. (“FINRA”). Accordingly, this offering will be conducted in accordance with Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus. Barclays Capital Inc. has agreed to act as a qualified independent underwriter for this offering and to undertake the legal responsibilities and liabilities of an underwriter under the Securities Act, specifically including those inherent in Section 11 thereof. Barclays Capital Inc. will not receive any additional fees for

serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify Barclays Capital Inc. against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act. See “Underwriting (Conflicts of Interest)—Conflicts of Interest.”

Dividend policy

We do not anticipate paying any cash dividends on our common stock. In addition, our new revolving credit facility places certain restrictions on our ability to pay cash dividends. Please read “Dividend Policy.”

Listing and trading symbol

We have been approved to list our common stock on the New York Stock Exchange (the “NYSE”) under the symbol “WRD.”

Risk factors

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.

The information above excludes shares of common stock reserved for issuance pursuant to our LTIP, which we intend to adopt in connection with the completion of this offering and does not include restricted shares of our common stock expected to be issued to certain officers in connection with the successful completion of this offering pursuant to our LTIP. See “Executive Compensation—Narrative Disclosures—Compensation Following This Offering—IPO Bonuses” for more information.

Summary Pro Forma Financial Data

The following table shows summary unaudited pro forma financial data of WildHorse Development for the periods and as of the dates indicated.

The summary unaudited pro forma statement of operations data for the year ended December 31, 2014 has been prepared to give pro forma effect to (i) the Corporate Reorganization and (ii) the contribution of the Initial Esquisto Assets to Esquisto as part of its formation as if they had occurred on January 1, 2014. The summary unaudited pro forma statements of operations data for the year ended December 31, 2015 and the nine months ended September 30, 2015 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The summary unaudited statement of operations data for the nine months ended September 30, 2016 and the summary unaudited pro forma balance sheet data as of September 30, 2016 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Burleson North Acquisition and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015 and September 30, 2016, respectively. Please see “Use of Proceeds.” This data is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

For selected historical consolidated financial data of WildHorse, our predecessor, as of and for the years ended December 31, 2014 and 2015, derived from the audited historical consolidated financial statements of WildHorse, please see “Selected Historical Consolidated and Unaudited Pro Forma Financial Data” included elsewhere in this prospectus.

You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “—Corporate Reorganization,” the historical consolidated financial statements of WildHorse and the unaudited pro forma financial statements included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.


	Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,
	2014			2015			2015			2016
	(Unaudited)
	(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil sales	$	17,826		$	142,614		$	112,087		$	86,279
Natural gas sales		38,345			38,063			29,199			29,560
NGL sales		2,285			6,722			5,069			4,428
Gathering system income		—			314			—			1,158

Total revenues		58,456			187,714			146,355			121,426

Operating expenses:
Lease operating expenses		10,540			35,339			26,272			21,865
Gathering system operating expense		—			914			317			99
Production and ad valorem taxes		3,405			12,991			9,915			8,600
Cost of oil sales		687			—			—			—
Depreciation, depletion and amortization		23,269			99,009			71,834			79,519
Impairment of proved oil and gas properties		24,721			9,312			8,032			—
General and administrative expenses		8,226			16,611			11,707			14,058
Exploration expenses		1,599			17,863			14,512			8,975

Total operating expenses		72,447			192,039			142,589			133,116

Gain (loss) from operations		(13,991	)		(4,325	)		3,766			(11,691	)

Other income (expense):
Interest expense		(3,286	)		(2,048	)		(1,539	)		(1,539	)
Other expense		(120	)		(150	)		(472	)		(429	)
Gain (loss) on derivatives instruments		6,514			13,854			7,179			(8,694	)

Total other income		3,108			11,656			5,168			(10,662	)

Net income (loss) before income taxes		(10,883	)		7,331			8,934			(22,353	)
Income tax benefit (expense)		4,502			(1,686	)		(2,398	)		8,956

Net (loss) income	$	(6,381	)	$	5,645		$	6,536		$	(13,397	)

Net (loss) income per common share:
Basic and diluted	$			$			$			$
Weighted average common shares outstanding:
Basic and diluted
Other Financial Data:
Adjusted EBITDAX(1)	$	32,120		$	132,906		$	104,381		$	81,726
Balance Sheet Data (at period end):
Cash and cash equivalents										$	11,226
Total assets										$	1,332,590
Total liabilities										$	192,200
Owners’ equity										$	1,140,390
Total liabilities and owners’ equity										$	1,332,590

(1)

Adjusted EBITDAX is not a financial measure calculated in accordance with United States generally accepted accounting principles (“GAAP”). For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measure.”

Non-GAAP Financial Measure

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 define Adjusted EBITDAX as net (loss) income before interest expense, income taxes, depreciation, depletion and amortization, exploration expense and impairment of unproved properties, gains on derivatives excluding effects of settled derivatives and other non-cash and non-recurring operating items. Adjusted EBITDAX is not a measure of net (loss) income as determined according to GAAP.

Management believes Adjusted EBITDAX is a useful performance measure because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers 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.


	Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,
	2014			2015			2015			2016
	(In thousands)
Adjusted EBITDAX reconciliation to net (loss) income:
Net (loss) income	$	(6,381	)	$	5,645		$	6,536		$	(13,397	)
Interest expense		3,286			2,048			1,539			1,539
Income tax (benefit) expense		(4,502	)		1,686			2,398			(8,956	)
Depreciation, depletion and amortization		23,269			99,009			71,834			79,519
Exploration expense and impairment of properties		26,320			27,175			22,544			8,975
(Gain) loss on derivatives		(6,514	)		(13,854	)		(7,179	)		8,694
Effects of derivative settlements		(2,712	)		11,958			7,324			5,637
Non-cash liability amortization		(646	)		(759	)		(615	)		(286	)

Adjusted EBITDAX	$	32,120		$	132,906		$	104,381		$	81,726

Summary Combined Reserve and Pro Forma Operating Data

Summary Reserve Data

The following table summarizes the estimated net proved, probable and possible oil, natural gas and NGL reserves of WildHorse and Esquisto on a combined basis as of June 30, 2016 without giving effect to any of the Acquisitions. Cawley prepared Esquisto’s reserves estimates and audited WildHorse’s reserves estimates. Such reserves estimates were prepared in accordance with the SEC’s rules regarding oil, natural gas and NGL reserve reporting.

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business—Reserve Data” in evaluating the material presented below.


	As of June 30, 2016(1)
Estimated Proved Reserves:
Oil (MMBbls)		49.7
Natural gas (Bcf)		300.8
NGLs (MMBbls)		7.6

Total proved reserves (MMBoe)		107.4

Estimated Proved Developed Reserves:
Oil (MMBbls)		9.3
Natural gas (Bcf)		142.0
NGLs (MMBbls)		2.6

Total proved developed reserves (MMBoe)		35.6

Proved developed reserves as a percentage of total proved reserves		33.1	%

Estimated Proved Undeveloped Reserves:
Oil (MMBbls)		40.4
Natural gas (Bcf)		158.7
NGLs (MMBbls)		5.0

Total proved undeveloped reserves (MMBoe)		71.8

Proved undeveloped reserves as a percentage of total proved reserves		66.9	%

Estimated Probable Reserves:
Oil (MMBbls)		61.3
Natural gas (Bcf)		191.4
NGLs (MMBbls)		7.4

Total probable reserves (MMBoe)(2)		100.6

Estimated Possible Reserves:
Oil (MMBbls)		109.9
Natural gas (Bcf)		1,109.8
NGLs (MMBbls)		12.9

Total possible reserves (MMBoe)(2)		307.8

(1)

WildHorse’s and Esquisto’s estimated net proved, probable and possible reserves 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 $43.12 per barrel as of June 30, 2016 was adjusted for

quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.24 per MMBtu as of June 30, 2016 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 the WildHorse properties are $39.78 per barrel of oil, $2.32 per Mcf of natural gas and $12.37 per barrel of NGL as of June 30, 2016. The average adjusted product prices weighted by production over the remaining lives of the Esquisto properties are $40.46 per barrel of oil, $1.35 per Mcf of natural gas and $10.35 per barrel of NGL as of June 30, 2016.

(2)	All of our estimated probable and possible reserves are classified as undeveloped.

Production and Operating Data

The following table sets forth information regarding our pro forma production, realized prices and production costs for the nine months ended September 30, 2016 and the year ended December 31, 2015. For additional information on pro forma adjustments and price calculations, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31, 2015		Nine Months Ended September 30, 2016
Net Production Volumes:
Oil (MBbls)		3,100.9		2,246.9
Natural gas (MMcf)		16,766.7		14,766.3
NGLs (MBbls)		564.1		407.0

Total (MBoe)		6,459.5		5,114.9

Average net daily production (MBoe/d)		17.7		18.7
Average Sales Prices:
Oil (per Bbl) (excluding impact of settled derivatives)	$	45.99	$	38.40
Oil (per Bbl) (after impact of settled derivatives)	$	46.32	$	39.28
Natural gas (per Mcf) (excluding impact of settled derivatives)	$	2.27	$	2.00
Natural gas (per Mcf) (after impact of settled derivatives)	$	2.92	$	2.25
NGLs (per Bbl)	$	11.92	$	10.88

Total (per Boe) (excluding impact of settled derivatives)	$	29.01	$	23.51
Total (per Boe) (after impact of settled derivatives)	$	30.86	$	24.62

Expenses per Boe:
Lease operating expenses	$	5.47	$	4.27
Gathering system operating expenses	$	0.14	$	0.02
Production and ad valorem taxes	$	2.01	$	1.68
Depreciation, depletion and amortization	$	15.33	$	15.55
Impairment of proved oil and gas properties	$	1.44		—
General and administrative expenses	$	2.57	$	2.75
Exploration expenses	$	2.77	$	1.75

RISK FACTORS

An investment in our common stock involves a number of risks. You should carefully consider each of the following risk factors and all of the other information set forth in this prospectus before making an investment decision. If any of the events discussed in the risk factors below actually occur, our business, financial condition and results of operations could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. If any of these risks occur, the trading price of our common stock could decline and you may lose all or part of your investment.

Risks Related to Our Business

The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access to capital, future rate of growth and the carrying value of our properties. Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to market uncertainty and to relatively minor changes in the supply of and demand for oil, natural gas and NGLs. Historically, oil, natural gas and NGL prices have been volatile. For example, during the period from January 1, 2014 through November 7, 2016, the WTI spot price for oil declined from a high of $107.95 per Bbl on June 20, 2014 to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:

•

worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGLs;

•

the price and quantity of foreign imports of oil, natural gas and NGLs;

•

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

•

actions of the Organization of the Petroleum Exporting Countries, its members and other state-controlled oil companies relating to oil price and production controls;

•

the level of global exploration, development and production;

•

the level of global inventories;

•

prevailing prices on local price indexes in the areas in which we operate;

•

the proximity, capacity, cost and availability of gathering and transportation facilities;

•

localized and global supply and demand fundamentals and transportation availability;

•

the cost of exploring for, developing, producing and transporting reserves;

•

weather conditions and natural disasters;

•

technological advances affecting energy consumption;

•

the price and availability of alternative fuels;

•

expectations about future commodity prices; and

•

U.S. federal, state and local and non-U.S. governmental regulation and taxes.

In the second half of 2014, oil prices began a rapid and significant decline from a high WTI spot price of $107.95 on June 20, 2014, as global oil supply began to outpace demand. Prices continued to decline through 2015 and into 2016, reaching a low of $26.19 on February 11, 2016. Since then, prices have recovered some with oil prices reaching a high of $51.23 in the second quarter of 2016, although oil prices have subsequently fallen to $44.89 as of November 7, 2016. In general, the imbalance between supply and demand, and the perception of such imbalance, that has influenced the current commodity price cycle 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 a sustained effort to retain and capture additional 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 excess storage levels begin to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure on oil prices. NGL prices generally correlate with the price of oil. Additionally, the supply of NGLs has continued to grow in the United States due to an increase in industry participants targeting NGL producing projects, which places additional pressure on the price of NGLs. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and thus far in 2016.

Similarly, the declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The duration and magnitude of the commodity price decline cannot be accurately predicted. Compared to 2014, our pro forma realized oil price for 2015 fell 47% to $45.99 per barrel, and our pro forma realized oil price for the nine months ended September 30, 2016 has further decreased to $38.40 per barrel. Similarly, our pro forma realized natural gas price for 2015 decreased 43% to $2.27 per Mcf, and our pro forma realized price for NGLs declined 53% to $11.92 per barrel. For the nine months ended September 30, 2016, our pro forma realized price for natural gas was $2.00 per Mcf, and our realized price for NGLs was $10.88 per barrel.

Lower commodity prices may reduce our cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In 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 ability to raise capital, which may require us to re-evaluate and postpone or eliminate our development program, and result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.

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 2016 and 2017 capital budget is $137.5 million and $539.5 million, respectively. We expect to fund our 2016 and 2017 capital budget with cash generated by operations and borrowings under our new 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 a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby 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 other 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 settlements from our derivative activities;

•

our ability to borrow under our new revolving credit facility; and

•

our ability to access the capital markets.

If our revenues or the borrowing base under our new 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. For a period of 180 days following the date of this prospectus, we will not be able to sell any shares of our common stock, whether pursuant to a private or public offering, without the prior written consent of Barclays Capital Inc. See “Underwriting (Conflicts of Interest)” for more information. If cash flow generated by our operations or available borrowings under our new 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 strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. The difficulties we face drilling horizontal wells include:

•

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 gases (“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

•

other market limitations in our industry.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our new 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 our 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 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. Our new 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.

Our new revolving credit facility contains a number of significant covenants, including restrictive covenants that will limit our ability to, among other things:

•

incur additional indebtedness;

•

make loans to others;

•

make investments;

•

merge or consolidate with another entity;

•

make certain payments;

•

hedge future production or interest rates;

•

incur liens;

•

sell assets; and

•

engage in certain other transactions without the prior consent of the lenders.

In addition, our new revolving credit facility requires us to maintain compliance with certain financial covenants.

The restrictions in our new revolving credit facility will also impact our ability to obtain capital to withstand a downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our new revolving credit facility may impose on us.

A breach of any covenant in our new revolving credit facility will result in a default under the agreement and an event of default under the agreement if there is no grace period or if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under our new revolving credit facility and in an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

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

Our new revolving credit facility, which we plan to enter into in connection with the completion of this offering, will limit 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 (the “Required Lenders”) with more than 66.6% of the loans and commitments under the facility 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”). 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. We expect our initial borrowing base to be $450.0 million, following the completion of the Burleson North Acquisition. Our next Scheduled Redetermination is expected in May 2017.

In the future, we may not be able to access adequate funding under our new revolving credit facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a borrowing base 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.

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

We enter into derivative instrument contracts for a portion of our oil and natural gas production. As of November 1, 2016, we had entered into swaps and collars through December 2019 covering a total of 1,664 MBbl of our projected oil production and 17,520,000 MMBtu 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, our new revolving credit facility 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.

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.

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, probable and possible 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, probable and possible reserves will be developed within the periods anticipated.

You should not assume that the present value of future net revenues from our reserves presented in this prospectus 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 June 30, 2016 and related standardized measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $43.12 per barrel of oil (WTI) and $2.24 per MMBtu of natural gas (Henry Hub spot), which, for certain periods in 2016, 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.

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 4,391 potential drilling locations. We do not expect to operate 1,880 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 September 30, 2016, we had identified 2,977 gross horizontal drilling locations on our Eagle Ford Acreage and 1,414 gross horizontal drilling locations on our North Louisiana Acreage. As a result of the limitations described in this prospectus, 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 new 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 new revolving credit facility.

As of September 30, 2016, approximately 46% of our total net acreage was held by production. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases or the leases are renewed. For example, as of September 30, 2016, 9% and 32% of our net undeveloped acreage will expire in 2016 and 2017, respectively, after giving effect to the Rosewood Acquisition. 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 to extend substantially all of our net acreage associated with identified drilling locations through a combination of development drilling, 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. 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 “Business—Reserve Data—Undeveloped Acreage Expirations” for more information regarding acreage expirations and our plans for extending and renewing our acreage. Our ability to drill and develop our acreage and establish production to maintain our leases depends on a number of uncertainties, including oil, 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 to and availability of water sourcing and distribution systems, regulatory approvals and other factors.

Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.

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

Water is an essential component of 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.

Our producing properties are located in the Eagle Ford and in North Louisiana, making us vulnerable to risks associated with operating in a limited number of geographic areas.

All of our producing properties are geographically concentrated in the Eagle Ford and in North Louisiana. At June 30, 2016, all of our total estimated proved reserves were attributable to properties located in these areas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas 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.

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

As of June 30, 2016, 67% 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. Moreover, the development of our probable and possible reserves will require additional capital expenditures and are less certain to be recovered than proved reserves. Estimated future development costs relating to the development of our PUDs at June 30, 2016 are approximately $675.0 million over the next five years. We expect to fund these expenditures through cash generated by operations, borrowings under our new 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 our probable and possible reserves 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 our probable and possible reserves into proved reserves or that our undeveloped or unproved 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.

Accounting 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. Recently, commodity prices have declined significantly. On November 7, 2016, the WTI spot price for crude oil was $44.89 per barrel and the Henry Hub spot price for natural gas was $2.816 per MMBtu, representing decreases of 58% and 65%, respectively, from the high of $107.95 per barrel of oil and $8.15 per MMBtu for natural gas during 2014. Likewise, NGLs have suffered significant recent declines in realized prices. 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. As a result of lower commodity prices, we recorded $24.7 million and $9.3 million of impairment expense during the years ended December 31, 2014 and 2015, respectively, on a pro forma basis. 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 we replace our reserves with new reserves and develop those new reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

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 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 years ended December 31, 2015 and 2014, three and two purchasers, respectively, accounted for an aggregate 70% and 67%, respectively, of WildHorse’s and Esquisto’s total revenue on a combined basis. During such years, no other purchaser accounted for 10% or more of WildHorse’s and Esquisto’s revenue on a combined basis. The loss of any such greater than 10% purchaser as a purchaser could adversely affect our revenues in the short term.

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 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 U.S. Environmental Protection Agency (“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 taking 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 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 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.

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.

WildHorse 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. Prior to this offering, WildHorse and Esquisto had separate management teams, and going forward, after giving effect to the Corporate Reorganization, we will have one management team. Further, the transition services agreement we will enter into in connection with the closing of this offering will only be effective for six months. 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, including the 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, our new revolving credit facility will 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.

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.

The 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.

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.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA 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 GHG emissions. Facilities required to obtain preconstruction permits for their GHG emissions 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 oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. In May 2016, the EPA finalized rules 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. The EPA has also announced that it intends to impose methane emission standards for existing sources but, to date, has not yet issued a proposal. And in 2015, EPA published a rule, known as the Clean Power Plan, to limit greenhouse gases from electric power plants. On February 9, 2016, the Supreme Court stayed the implementation of the Clean Power Plan while legal challenges to the rule proceed. Depending on the ultimate outcome of those challenges, and how various states choose to implement this rule, it may alter the power generation mix between natural gas, coal, oil, and alternative energy sources, which would ultimately affect the demand for natural gas and oil in electric generation.

community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States was one of 175 countries to sign 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 is expected to enter into force in November 2016. The United States is one of over 70 nations that has indicated it intends to comply with the agreement.

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. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce.

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 events; if any such effects were to occur, they could have a material adverse effect on our operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but certain federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. The EPA also finalized rules in 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.

Certain governmental reviews are either underway or have been conducted that focus on environmental aspects of hydraulic fracturing practices. For example, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report preliminarily concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board, which is in progress. Other governmental agencies, including the White House Council on Environmental Quality, United States Department of Energy and the United States Department of the Interior, have or are currently evaluating various other aspects of hydraulic fracturing. These studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. 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.

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

State and federal regulatory agencies have recently focused on a possible connection between the hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In addition, a number of lawsuits have been filed 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, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of saltwater disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a new rule governing permitting or re-permitting of disposal 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 question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the saltwater 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.

We dispose of large volumes of saltwater gathered from our drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of saltwater gathered from our drilling and production 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.

The loss of senior management or technical personnel could adversely affect operations.

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.

Increases in interest rates could adversely affect our business.

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 new 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.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction, transportation and sales.

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.

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

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

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

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our 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, in November 2013, the CFTC proposed new 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 recently 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, the impact of which is not clear at this time.

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, WildHorse 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 which has elected to be treated as a corporation for U.S. federal income tax purposes. Accordingly, our standardized measure does not provide for U.S. federal, state or local income taxes other than certain state franchise taxes and federal income tax for our predecessor subsidiary discussed above. However, following the Corporate Reorganization, we will be 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 prospectus should not be construed as accurate estimates of the current fair value of our proved reserves.

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.

Risks Related to this Offering and Our Common Stock

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, 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.

As a public company, we will need 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 with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need 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, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. 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.

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 would likely have a negative effect on the trading price of our common stock.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated among us and the representatives of the underwriters, based on numerous factors, which we discuss in “Underwriting (Conflicts of Interest),” and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

The following factors could affect our stock price:

•

our operating and financial performance and drilling locations, including reserve estimates;

•

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

•

the public reaction to our press releases, our other public announcements and our filings with the SEC;

•

strategic actions by our competitors;

•

changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

•

speculation in the press or investment community;

•

the failure of research analysts to cover our common stock;

•

sales of our common stock by us or other stockholders, or the perception that such sales may occur;

•

changes in accounting principles, policies, guidance, interpretations or standards;

•

additions or departures of key management personnel;

•

actions by our stockholders;

•

general market conditions, including fluctuations in commodity prices;

•

domestic and international economic, legal and regulatory factors unrelated to our performance; and

•

the occurrence of any risks described under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

NGP has the ability to direct the voting of a majority of our common stock, and its interests may conflict with those of our other stockholders.

Upon completion of this offering, NGP, through WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, will beneficially own approximately % of our outstanding common stock (or approximately % if the underwriters’ over-allotment option is exercised in full). As a result, NGP will be 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 NGP 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 this concentrated ownership, NGP would have to approve any potential acquisition of us. In addition, certain of our directors are currently employees of NGP. These directors’ duties as employees of NGP 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, in connection with this offering, we expect to enter into a stockholders’ agreement with WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The stockholders’ agreement is expected to provide WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings with the right to designate a certain number of nominees to our board of directors so long as they and their affiliates collectively beneficially own more than 5% of the outstanding shares of our common stock. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.” The existence of a significant stockholder and the stockholders’

agreement 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 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. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Certain Relationships and Related Party Transactions.”

Our governing documents will 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 will, among other things:

•

permit 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

•

provide 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. Please read “Description of Capital Stock—Corporate Opportunity.”

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.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, will 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 will authorize 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. 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:

•

at any time after a group that includes WildHorse Investment Holdings, Esquisto Investment Holdings, WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP and certain of NGP’s affiliates (collectively, the “Sponsor Group”) no longer collectively own or control the voting of more than 50% of our outstanding common stock:

•

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

•

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);

•

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;

•

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

•

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.

Our amended and restated certificate of incorporation will designate 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 will provide 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 (the “DGCL”), our amended and restated certificate of incorporation or our 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.

Investors in this offering will experience immediate and substantial dilution of $ per share.

Based on an assumed initial public offering price of $ per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of September 30, 2016 after giving effect to this offering would be $ per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

We do not intend to pay cash dividends on our common stock, and our new revolving credit facility places restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not plan to declare cash dividends on shares of our common stock in the foreseeable future. Additionally, our new revolving credit facility places restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay in this offering.

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. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have outstanding shares of common stock. This number includes shares that we are selling in this

offering but excludes shares that we may sell in this offering if the underwriters’ over-allotment option is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, and assuming full exercise of the underwriters’ over-allotment option, the Existing Owners will own shares of our common stock, or approximately % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between them and the underwriters described in “Underwriting (Conflicts of Interest),” but may be sold into the market in the future. Each of the Existing Owners will be party to a registration rights agreement, which will require us to effect the registration of its shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering.

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our LTIP. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction.

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 shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We, all of our directors and executive officers, and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our common stock for a period of 180 days following the date of this prospectus. Barclays Capital Inc., at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. See “Underwriting (Conflicts of Interest)” for more information on these agreements. If the restrictions under the lock-up agreements are waived, then the common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

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

Our amended and restated certificate of incorporation will authorize 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.

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

Upon completion of this offering, the Sponsor Group will beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. As a result, we expect to 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.

Following this offering, we intend to utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to such corporate governance requirements. See “Management.”

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 $1.0 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.

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.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, 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 prospectus, 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 the heading “Risk Factors” included in this prospectus.

Forward-looking statements may include statements about:

•

our business strategy;

•

our estimated proved, probable and possible reserves;

•

our drilling prospects, inventories, projects and programs;

•

our ability to replace the reserves we produce through drilling and property acquisitions;

•

our financial strategy, liquidity and capital required for our development program;

•

our realized oil, natural gas and NGL prices;

•

the timing and amount of our future production of oil, natural gas and NGLs;

•

our hedging strategy and results;

•

our future drilling plans;

•

our competition and government regulations;

•

our ability to obtain permits and governmental approvals;

•

our pending legal or environmental matters;

•

our marketing of oil, natural gas and NGLs;

•

our leasehold or business acquisitions;

•

our costs of developing our properties;

•

general economic conditions;

•

credit markets;

•

uncertainty regarding our future operating results; and

•

our plans, objectives, expectations and intentions contained in this prospectus 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 “Risk Factors” in this prospectus.

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 prospectus 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 prospectus 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 prospectus.

USE OF PROCEEDS

We expect to receive approximately $ million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

Affiliates of certain of the underwriters are lenders under the Esquisto revolving credit facility and the WildHorse revolving credit facility and, as a result, will indirectly receive a portion of the proceeds of this offering.

The following table illustrates our anticipated use of the proceeds of this offering:


Sources of Funds (in millions)		Uses of Funds (in millions)
Gross proceeds from this offering	$	Burleson North Acquisition	$
New revolving credit facility		Repayment of WildHorse revolving credit facility
		Repayment of Esquisto revolving credit facility
		Repayment of Esquisto notes payable to members
		Underwriting discounts, fees and certain other expenses

Total	$	Total	$

As of September 30, 2016, WildHorse had $108.5 million of outstanding borrowings under the WildHorse revolving credit facility. The WildHorse revolving credit facility matures on August 8, 2018 and bears interest at a variable rate, which was 3.03% per annum at September 30, 2016. Borrowings under the WildHorse revolving credit facility were incurred primarily to fund WildHorse’s capital expenditures and leasehold acquisitions.

As of September 30, 2016, Esquisto had $125.0 million of outstanding borrowings under the Esquisto revolving credit facility. The Esquisto revolving credit facility matures on July 22, 2020 and bears interest at a variable rate, which averaged 2.79% per annum at September 30, 2016. Borrowings under the Esquisto revolving credit facility were incurred primarily to fund Esquisto’s capital expenditures and leasehold acquisitions, including the Comstock Acquisition. As of September 30, 2016, Esquisto had $9.6 million in principal amount of notes payable to certain of its members. The Esquisto notes payable to members are payable to such members by December 31, 2022 and bear interest after a year at the Applicable Federal Rate compounded annually, paid at maturity. Borrowings from Esquisto’s members were incurred primarily to fund general and administrative expenses incurred on behalf of Esquisto.

Affiliates of certain of the underwriters are lenders under the WildHorse revolving credit facility and/or the Esquisto revolving credit facility and accordingly will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings under such credit facilities. Accordingly, this offering is being made in compliance with FINRA Rule 5121. Please read “Underwriting (Conflicts of Interest).”

A $1.00 increase or decrease in the assumed initial public offering price of $ per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $ million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. If the proceeds increase for any reason, we would use the additional net proceeds to reduce borrowings under our new revolving credit facility. If the proceeds decrease for any reason, then we would make additional borrowings under our new revolving credit facility.

DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance our operations and the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our new revolving credit facility places restrictions on our ability to pay cash dividends.

CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of September 30, 2016:

•

on an actual basis for WildHorse, our predecessor;

•

on an as adjusted basis to give effect to the Corporate Reorganization; and

•

on an as further adjusted basis to give effect, along with borrowings under our new revolving credit facility, to (i) the sale of shares of our common stock in this offering at an assumed initial public offering price of $ per share (which is the midpoint of the range set forth on the cover of this prospectus), (ii) the issuance of shares of our common stock in connection with the closing of the Rosewood Acquisition and (iii) the application of the net proceeds from this offering to (a) fund the remaining portion of the Burleson North Acquisition purchase price and (b) repay in full and terminate the WildHorse revolving credit facility and the Esquisto revolving credit facility and repay in full all notes payable by Esquisto to its members, as set forth under “Use of Proceeds.”

The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our financial statements and related notes appearing elsewhere in this prospectus.


	As of September 30, 2016
	Actual			As Adjusted		As further Adjusted(1)
	(In thousands, except number of shares and par value)
Cash and cash equivalents	$	1,336		$	1,451	$

Long-term debt:
WildHorse revolving credit facility(2)		108,500			108,500		—
Esquisto revolving credit facility(3)		—			128,000		—
Esquisto notes payable to members		—			9,625		—
New revolving credit facility		—			—		—

Total long-term debt	$	108,500		$	246,125	$	—

Members’/Stockholders’ equity:
Members’ equity		337,974			—
Common stock—$0.01 par value; no shares authorized, issued or outstanding, actual; 500,000,000 shares authorized, shares issued and outstanding, as further adjusted		—
Additional paid-in capital		—
Accumulated deficit		(77,378	)

Total owners’ and stockholders’ equity	$	260,596		$		$

Total capitalization	$	369,096		$		$

(1)

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus) would increase (decrease) each of additional paid-in capital, total equity and total capitalization by approximately $ million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions payable by us. We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares offered by us at

an assumed offering price of $ per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) each of additional paid-in capital, total stockholders’ equity and total capitalization by approximately $ million after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

(2)	As of November 21, 2016, total borrowings under the WildHorse revolving credit facility were approximately $110.3 million, and WildHorse expects to draw approximately $ million in additional borrowings under such facility prior to the completion of this offering to fund capital expenditures.

(3)	As of November 21, 2016, total borrowings under the Esquisto revolving credit facility were approximately $145.0 million, and Esquisto expects to draw approximately $ million in additional borrowings under such facility prior to the completion of this offering to fund capital expenditures.

DILUTION

Purchasers of our common stock in this offering will experience immediate and substantial dilution in the net tangible book value (tangible assets less total liabilities) per share of our common stock for accounting purposes. Our pro forma net tangible book value as of September 30, 2016, after giving effect to the Corporate Reorganization, was approximately $ million, or $ per share.

Pro forma net tangible book value per share is determined by dividing our net tangible book value, or total tangible assets less total liabilities, by our shares of common stock that will be outstanding immediately prior to the closing of this offering, including giving effect to the Corporate Reorganization. Assuming an initial public offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us), our adjusted pro forma net tangible book value as of September 30, 2016 would have been approximately $ million, or $ per share. This represents an immediate increase in the net tangible book value of $ per share to our existing stockholders and an immediate dilution to new investors purchasing shares in this offering of $ per share, resulting from the difference between the offering price and the pro forma as adjusted net tangible book value after this offering. The following table illustrates the per share dilution to new investors purchasing shares in this offering:


Assumed initial public offering price per share		$
Pro forma net tangible book value per share as of September 30, 2016 (after giving effect to the Corporate Reorganization)	$
Increase per share attributable to new investors in this offering

As adjusted pro forma net tangible book value per share (after giving effect to the Corporate Reorganization and this offering)

Dilution in pro forma net tangible book value per share to new investors in this offering		$

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus) would increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $ and increase (decrease) the dilution to new investors in this offering by $ per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table summarizes, on an adjusted pro forma basis as of September 30, 2016, the total number of shares of common stock owned by Existing Owners and to be owned by new investors at $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus) and the total consideration paid and the average price per share paid by our Existing Owners and to be paid by new investors in this offering at $ (which is the midpoint of the price range set forth on the cover page of this prospectus) calculated before deduction of estimated underwriting discounts and commissions.


	Shares Acquired				Total Consideration					Average Price Per Share
	Number	Percent			Amount		Percent			Average Price Per Share
Existing Owners				%	$	(1)			%	$
Rosewoood Acquisition sellers
New investors in this offering

Total			100	%	$			100	%	$

(1)	Represents the combined net members equity associated with the membership interests in WildHorse, Esquisto and Acquisition Co. to be contributed by the Existing Owners to WildHorse Resource

Development Corporation in connection with the offering. To date, the Existing Owners have made contributions of $ million in cash to WildHorse and Esquisto on a combined basis representing $ per share of common stock.

The data in the table excludes shares of common stock reserved for issuance under our LTIP (which amount may be increased each year in accordance with the terms of our LTIP) and does not include restricted shares of our common stock expected to be issued to certain officers in connection with the successful completion of this offering pursuant to our LTIP. See “Executive Compensation—Narrative Disclosures—Compensation Following This Offering—IPO Bonuses” for more information. If the underwriters’ over-allotment option is exercised in full, the number of shares held by new investors will be increased to , or approximately % of the total number of shares of common stock.

SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

WildHorse Development was formed as a holding company in August 2016, has not had any operations since its formation and does not have historical operating results. Accordingly, the following table shows selected historical consolidated financial data, for the periods and as of the dates indicated, of WildHorse Development’s accounting predecessor, WildHorse.

The selected historical consolidated financial data as of and for the years ended December 31, 2014 and 2015 were derived from the audited historical consolidated financial statements of WildHorse, our predecessor, included elsewhere in this prospectus.

The selected historical consolidated financial data as of and for the nine months ended September 30, 2015 and 2016 were derived from the unaudited historical consolidated financial statements of WildHorse included elsewhere in this prospectus. The selected unaudited historical consolidated financial data has been prepared on a consistent basis with the audited consolidated financial statements of WildHorse. In the opinion of management, such selected unaudited historical consolidated interim financial data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present the financial position and results of operations of our predecessor for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year.

The selected unaudited pro forma statement of operations data for the year ended December 31, 2014 has been prepared to give pro forma effect to (i) the Corporate Reorganization and (ii) the contribution of the Initial Esquisto Assets to Esquisto as part of its formation as if they had occurred on January 1, 2014. The selected unaudited pro forma statements of operations data for the year ended December 31, 2015 and the nine months ended September 30, 2015 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The selected unaudited statement of operations data for the nine months ended September 30, 2016 and the selected unaudited pro forma balance sheet data as of September 30, 2016 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Burleson North Acquisition and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015 and September 30, 2016, respectively. Please see “Use of Proceeds.” This data is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The selected unaudited pro forma financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Prospectus Summary—Corporate Reorganization,” the historical consolidated financial statements of WildHorse and the unaudited pro forma financial statements included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.


	Predecessor Historical												Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,						Year Ended December 31,						Nine Months Ended September 30,
	2014			2015			2015			2016			2014			2015			2015			2016
							(Unaudited)						(Unaudited)
				(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil sales	$	2,780		$	3,305		$	2,240		$	2,971		$	17,826		$	142,614		$	112,087		$	86,279
Natural gas sales		37,741			30,556			23,381			25,273			38,345			38,063			29,199			29,560
NGL sales		989			1,451			1,100			658			2,285			6,722			5,069			4,428
Gathering system income		—			314			—			1,158			—			314			—			1,158

Total revenues		41,510			35,627			26,721			30,061			58,456			187,714			146,355			121,426

Operating expenses:
Lease operating expenses		9,428			8,606			6,178			4,543			10,540			35,339			26,272			21,865
Gathering system operating expense		—			914			317			99			—			914			317			99
Production and ad valorem taxes		2,584			2,666			1,891			1,843			3,405			12,991			9,915			8,600
Cost of oil sales		687			—			—			—			687			—			—			—
Depreciation, depletion and amortization		15,297			25,526			17,516			27,305			23,269			99,009			71,834			79,519
Impairment of proved oil and gas properties		24,721			9,312			8,032			—			24,721			9,312			8,032			—
General and administrative expenses		5,838			10,567			7,475			8,399			8,226			16,611			11,707			14,058
Exploration expense		1,597			14,896			14,306			8,973			1,599			17,863			14,512			8,975

Total operating expense		60,152			72,487			55,715			51,162			72,447			192,039			142,589			133,116

Gain (loss) from operations		(18,642	)		(36,861	)		(28,994	)		(21,102	)		(13,991	)		(4,325	)		3,766			(11,691	)

Other income (expense):
Interest expense		(2,680	)		(2,576	)		(2,249	)		(2,732	)		(3,286	)		(2,048	)		(1,539	)		(1,539	)
Other income (expense)		213			(45	)		9			(76	)		(120	)		(150	)		(472	)		(429	)
Gain (loss) on derivatives instruments		6,514			9,510			6,063			(2,894	)		6,514			13,854			7,179			(8,694	)

Total other income (expense)		4,047			6,889			3,823			(5,702	)		3,108			11,656			5,168			(10,662	)

Net gain (loss) before income taxes		(14,595	)		(29,972	)		(25,171	)		(26,804	)		(10,883	)		7,331			8,934			(22,353	)
Income tax benefit (expense)		158			17			82			(15	)		4,502			(1,686	)		(2,398	)		8,956

Net (loss) income	$	(14,437	)	$	(29,955	)	$	(25,089	)	$	(26,819	)	$	(6,381	)	$	5,645		$	6,536		$	(13,397	)

Net loss per common share:
Basic and diluted													$			$			$			$
Weighted average common shares outstanding:
Basic and diluted
Cash Flow Data:
Net cash provided by (used in) operating activities	$	25,660		$	25,374		$	10,894		$	(9,542	)
Net cash used in investing activities	$	(128,968	)	$	(147,321	)	$	(109,842	)	$	(15,055	)
Net cash provided by financing activities	$	114,589		$	131,984		$	118,594		$	3,708
Other Financial Data:
Adjusted EBITDAX(1)													$	32,120		$	132,906		$	104,381		$	81,726
Balance Sheet Data (at period end):
Cash and cash equivalents	$	12,188		$	22,225		$	31,835		$	1,336											$	11,226
Total assets	$	335,722		$	427,850		$	420,073		$	390,990											$	1,332,590
Total liabilities	$	156,730		$	153,715		$	160,963		$	130,394											$	192,200
Owners’ equity	$	178,992		$	274,134		$	259,110		$	260,596											$	1,140,390
Total liabilities and owners’ equity	$	335,722		$	427,850		$	420,073		$	390,990											$	1,332,590

(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 “Prospectus Summary—Non-GAAP Financial Measure.”

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated and Unaudited Pro Forma Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. 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 below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. 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.

The pro forma statement of operations data for the year ended December 31, 2014 has been prepared to give pro forma effect to (i) the Corporate Reorganization and (ii) the contribution of the Initial Esquisto Assets to Esquisto as part of its formation as if they had occurred on January 1, 2014. The unaudited pro forma statements of operations data for the year ended December 31, 2015 and the nine months ended September 30, 2015 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The pro forma statement of operations data for the nine months ended September 30, 2016 and the pro forma balance sheet data as of September 30, 2016 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Burleson North Acquisition and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015 and September 30, 2016, respectively.

WildHorse Resource Development Corporation

We are a growth-oriented, independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in two basins with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. Our acreage position is focused in two areas, Southeast Texas and North Louisiana. In Southeast Texas, we operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale, which is one of the most active shale trends in North America. In North Louisiana, we operate in and around the highly prolific Terryville Complex, where we primarily target the overpressured Cotton Valley play.

We were formed as a Delaware corporation in August 2016 to serve as a holding company and have not had any operations since our formation. As a result, we do not have historical financial operating results, and our accounting predecessor is WildHorse. WildHorse, Esquisto and Acquisition Co. will be contributed to us in connection with this offering. Acquisition Co. was formed for the sole purpose of acquiring the Burleson North Assets. The Burleson North Acquisition is expected to be consumated prior to or contemporaneously with the completion of this offering. Please see “Prospectus Summary—Corporate Reorganization,” for a description of our Corporate Reorganization and “—Factors Affecting the Comparability of Our Results of Operations to the Historical Results of Operations of Our Predecessor” for discussion of important factors that may cause our future results of operations to differ from the historical results of operations of our predecessor. Further, certain information is presented herein on a pro forma basis to give effect to, among other things, the Corporate Reorganization and the Burleson North Acquisition. Please see “—Pro Forma Results of Operations and Operating Expense—Pro Forma Adjustments” for a description of the pro forma adjustments that we made for each period presented.

Overview

Market Conditions

The oil and natural gas industry is cyclical and commodity prices are highly volatile. In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. 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. 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 excess storage levels begins to decline, prices are expected to remain under pressure. 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 to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and in the first half of 2016. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The duration and magnitude of the commodity price declines cannot be accurately predicted.

Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL production. Compared to 2014, our pro forma realized oil price for 2015 fell 47% to $45.99 per barrel, and our pro forma realized oil price for the nine months ended September 30, 2016 has further decreased to $38.40 per barrel. Similarly, compared to 2014, our pro forma realized natural gas price for 2015 decreased 43% to $2.27 per Mcf and our pro forma realized price for NGLs declined 53% to $11.92 per barrel. For the nine months ended September 30, 2016, our pro forma realized price for natural gas was $2.00 per Mcf and our pro forma realized price for NGLs was $10.88 per barrel.

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 new 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.

Drilling Activity

WildHorse

WildHorse commenced drilling with one rig in June 2014 and added a second rig in July 2014. During 2014, WildHorse completed two successful horizontal wells. WildHorse started 2015 running two rigs. In July 2015, WildHorse reduced its drilling program to one rig in response to low commodity prices and continued operating a one-rig drilling program through the end of 2015. During 2015, WildHorse completed seven successful horizontal wells and one vertical well. WildHorse started 2016 running one rig but released that rig in March 2016 in response to low commodity prices. WildHorse drilled and completed two horizontal wells, and participated in a third horizontal well that was drilled and completed by another operator, during the nine months ended September 30, 2016. In our North Louisiana Acreage, we intend to recommence drilling by adding one rig in late 2016 and one rig in 2017.

Esquisto

During 2014, Esquisto drilled and completed five successful operated horizontal wells, utilizing one rig for the majority of the year, and participated in another eleven successful horizontal wells drilled by other operators. During 2015, Esquisto ran one rig until July when a second rig was added around the time of the Comstock Acquisition. During 2015, Esquisto drilled and completed a total of 18 successful horizontal wells and participated in another seven successful horizontal wells drilled by other operators. In early October 2015, Esquisto reduced its drilling program to one rig, which it ran until February 2016, at which point it ceased drilling due to the commodity price environment. Esquisto drilled and completed two successful operated horizontal wells during the three months ended March 31, 2016. During the second quarter of 2016, Esquisto recommenced drilling under a one-rig drilling program and drilled and completed a total of eight successful operated horizontal wells during the second and third quarters of 2016. In our Eagle Ford Acreage, we are currently running a one-rig program and intend to add three additional drilling rigs in 2017.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, the sale of NGLs that are extracted from our natural gas during processing, and the gathering charge paid by certain third parties for their share of volumes that run through our gathering system. For the nine months ended September 30, 2016, of our pro forma revenues, 71% came from oil sales, 24% came from natural gas sales, 4% came from NGL sales and 1% came from gathering charges. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors. See “—Overview—Market Conditions” for information regarding the current commodity price environment. A $1.00 per barrel change in our realized oil price would have resulted in a $2.2 million change in pro forma oil sales for the nine months ended September 30, 2016. A $0.15 per Mcf change in our realized natural gas price would have resulted in a $2.2 million change in our pro forma natural gas sales for the nine months ended September 30, 2016. A $1.00 per barrel change in NGL prices would have changed pro forma NGL sales by $0.4 million for the nine months ended September 30, 2016.

The following table presents our pro forma average realized commodity prices, as well as the effects of derivative settlements during the periods indicated.


	Nine Months Ended September 30,				Year Ended December 31,
	2016		2015		2015		2014
Crude Oil (per Bbl):
Average NYMEX price	$	41.33	$	51.00	$	48.80	$	93.00
Realized price, before the effects of derivative settlements	$	38.40	$	48.47	$	45.99	$	86.13
Effects of derivative settlements	$	0.88	$	0.16	$	0.33		—
Natural Gas:
Average NYMEX price (per MMBtu)	$	2.29	$	2.80	$	2.66	$	4.41
Realized price, before the effects of derivative settlements (per Mcf)	$	2.00	$	2.46	$	2.27	$	4.01
Effects of derivative settlements (per Mcf)	$	0.25	$	0.59	$	0.65	$	(0.28	)
NGLs (per Bbl):
Average realized NGL price	$	10.88	$	12.12	$	11.92	$	25.55

While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials for these products.

See “—Pro Forma Results of Operations and Operating Expenses” and “—Predecessor Results of Operations and Operating Expense” below for an analysis of the impact changes in realized prices had on our revenues.

Production Results

The following table presents pro forma production volumes for our properties during the periods indicated:


	Nine Months Ended September 30,				Year Ended December 31,
	2016		2015		2015		2014
Oil (MBbls)		2,246.9		2,312.5		3,100.9		207.0
Natural gas (MMcf)		14,766.3		11,875.4		16,766.7		9,551.7
NGLs (MBbls)		407.0		418.2		564.1		89.4

Total (MBoe)		5,114.9		4,709.9		6,459.5		1,888.4
Average net daily production (MBoe/d)		18.7		17.3		17.7		5.2

Like other businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil and natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost effective manner. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost effective manner and to timely obtain drilling permits and regulatory approvals. Our ability to add reserves through drilling projects and acquisitions is dependent on many factors, including our ability to generate cash flow from operations, borrow or raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read “Risk Factors—Risks Related to Our Business” for a discussion of these and other risks affecting our proved reserves and production.

Derivative Activity

Oil, natural gas and NGL prices are volatile and unpredictable, and we expect this volatility to continue in the future. Due to this volatility, we have historically used commodity derivative instruments, such as collars, puts and swaps, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil, natural gas and NGL prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil, natural gas and NGL prices and may partially limit our potential gains from future increases in prices. See “—Quantitative and Qualitative Disclosure About Market Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

We have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices. However, in times of low commodity prices, our ability to enter into additional commodity derivative contracts with favorable commodity price terms may be limited, which may adversely impact our future revenues and cash flows as compared to historical periods during which we were able to hedge our oil and natural gas production at higher prices. For example, as illustrated by the following tables, we have from time to time been able to hedge our production at prices higher that the prices associated with our current commodity derivative contracts. Specifically, our natural gas derivative contracts covering all or part of 2014 were at a weighted

average price of more than $4.00 per MMBtu while the weighted average price of our current natural gas derivative contracts is significantly below $4.00 per MMBtu. Likewise, the weighted average price associated with our natural gas derivative contracts covering all or part of 2015 was higher than the weighted average price associated with our existing natural gas derivative contracts. We have not experienced a significant change in the price at which we have hedged our oil production due to the fact that we did not start hedging our oil production until 2015 following the significant decline in commodity prices during the second half of 2014. The following tables below provide additional information about our historical hedging activity and results as well as a summary of our existing hedges as of November 1, 2016.

The following table summarizes the notional quantity and weighted average price for all hedges that were entered into by WildHorse and on a pro forma basis covering all or part of the first nine months of 2016. We will not acquire any hedges from Clayton Williams Energy, Inc. in connection with the Burleson North Acquisition.


	WildHorse				Pro Forma
Commodity	Notional Quantity 1/1/2016 - 9/30/2016		Weighted Average Price		Notional Quantity 1/1/2016 - 9/30/2016		Weighted Average Price
Crude oil swaps (Bbls)		18,000	$	50.41		370,212	$	47.22
Crude oil puts (Bbls)		—		—		87,783	$	50.00
Natural gas swaps (MMBtu)		4,790,000	$	2.91		4,790,000	$	2.91
Natural gas collars (MMBtu)		2,314,286	$	2.71-$3.03		2,314,286	$	2.71-$3.03

The following table summarizes the historical results of hedging activities for WildHorse on a pro forma basis for the nine months ended September 30, 2016:


	Nine Months Ended September 30, 2016
	WildHorse		Pro Forma
Average realized prices before effects of hedges:
Oil (Bbl)	$	45.39	$	38.40
Natural gas (Mcf)	$	2.01	$	2.00
NGL (Bbl)	$	13.42	$	10.88
Average realized prices after effects of hedges:
Oil (Bbl)	$	48.67	$	39.28
Natural gas (Mcf)	$	2.30	$	2.25
NGL (Bbl)	$	13.42	$	10.88

The following table summarizes the notional quantity and weighted average price for all hedges that were entered into by WildHorse and on a pro forma basis covering all or part of 2015:


	WildHorse				Pro Forma
Commodity	Notional Quantity 1/1/2015 - 12/31/2015		Weighted Average Price		Notional Quantity 1/1/2015 - 12/31/2015		Weighted Average Price
Crude oil swaps (Bbls)		14,000	$	61.81		101,228	$	51.91
Crude oil puts (Bbls)		—		—		104,759	$	50.00
Natural gas swaps (MMBtu)		10,737,362	$	3.65		10,737,362	$	3.65

The following table summarizes the historical results of hedging activities for WildHorse on a pro forma basis for the year ended December 31, 2015:


	Year Ended December 31, 2015
	WildHorse		Pro Forma
Average realized prices before effects of hedges:
Oil (Bbl)	$	45.20	$	45.99
Natural gas (Mcf)		2.24		2.27
NGL (Bbl)		14.05		11.92
Average realized prices after effects of hedges:
Oil (Bbl)	$	47.16	$	46.32
Natural gas (Mcf)		3.04		2.92
NGL (Bbl)		14.05		11.92

The following table summarizes the notional quantity and weighted average price for all hedges that were entered into by WildHorse and on a pro forma basis covering all or part of 2014:


	WildHorse				Pro Forma
Commodity	Notional Quantity 1/1/2014 - 12/31/2014		Weighted Average Price		Notional Quantity 1/1/2014 - 12/31/2014		Weighted Average Price
Natural gas swaps (MMBtu)		7,090,000	$	4.01		7,090,000	$	4.01
Natural gas collars (MMBtu)		700,000	$	4.25-$5.20		700,000	$	4.25-$5.20

The following table summarizes the historical results of hedging activities for WildHorse and on a pro forma basis for the year ended December 31, 2014:


	Year Ended December 31, 2014
	WildHorse		Pro Forma
Average realized prices before effects of hedges:
Oil (Bbl)	$	90.59	$	86.13
Natural gas (Mcf)		4.02		4.01
NGL (Bbl)		23.90		25.55
Average realized prices after effects of hedges:
Oil (Bbl)	$	90.59	$	86.13
Natural gas (Mcf)		3.73		3.73
NGL (Bbl)		23.90		25.55

The following tables provide a summary of the financial derivative contracts to which our predecessor and Esquisto on a combined basis were a party as of November 1, 2016:


Commodity / Term	Contract Type	Average Monthly Volume (MMBtu)		Weighted Average Price per Unit
Natural Gas:
November 2016—December 2016	Swaps		740,000	$	2.880
January 2017—December 2017	Swaps		630,000	$	3.100
January 2018—December 2018	Swaps		170,000	$	2.945
November 2016—December 2016	Collars		460,000	$	2.620 – $2.940
January 2017—December 2017	Collars		460,000	$	3.000 – $3.362


Commodity / Term	Contract Type		Average Monthly Volume (Bbls)		Weighted Average Price per Unit
Crude Oil:
November 2016—December 2016		Swaps		75,200	$	46.430
January 2017—December 2017		Swaps		65,950	$	49.200
January 2018—December 2018		Swaps		47,000	$	51.040
January 2019—December 2019		Swap		5,000	$	55.050
November 2016—June 2018		Collar		4,900	$	50.000 – $62.100

We expect to continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis.

Operating Costs and Expenses

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. As of September 30, 2016 and December 31, 2015, we owned a working interest in 885 and 876 gross producing wells, respectively. 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 System Operating Expense . Gathering system operating expenses include contract labor, water disposal, dehydration equipment rentals, chemical and facilities-related expenses and facility termination fees that are incurred in the operation of our North Louisiana gathering system.

Production and Ad Valorem 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. 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. 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.

Cost of Oil Sales. When oil inventory is acquired in an acquisition the oil in tanks is recorded at the price paid by us, which is the market price. As the oil in tanks is sold, it is replaced by oil produced by us and is recorded at the lower of cost or market. This accounting adjustment to reduce oil inventory from market price to the lower of cost or market is reflected on our income statement in the account cost of oil sales.

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.

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, 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.

Factors Affecting the Comparability of Our Results of Operations to the Historical Results of Operations of Our Predecessor

Our future results of operations may not be comparable to the historical results of operations of WildHorse for the periods presented, primarily for the reasons described below.

Corporate Reorganization

We were incorporated to serve as the issuer in this offering and have no previous operations, assets or liabilities. WildHorse and Esquisto will be contributed to us in connection with this offering as part of the Corporate Reorganization and will thereby become our wholly owned subsidiaries. Furthermore, Acquisition Co. will also be contributed to us in connection with the Corporate Reorganization, and Acquisition Co. will acquire the Burleson North Assets prior to or contemporaneously with the closing of this offering. For more information on our reorganization and the ownership of our common stock by our principal stockholders, please see “Security Ownership of Certain Beneficial Owners and Management” and the unaudited pro forma financial statements included elsewhere in this prospectus.

The historical consolidated financial statements included in this prospectus are the financial statements of WildHorse, our accounting predecessor, and therefore do not include financial information of Esquisto or the Burleson North Assets. The pro forma financial information presented in this prospectus treats the contribution to us of WildHorse and Esquisto in connection with our Corporate Reorganization as a reorganization of entities under common control as if it had occurred on January 1, 2014 and our acquisition of the Burleson North Assets under the acquisition method of accounting. As a result, the historical financial data and pro forma financial information presented in this prospectus may not give you an accurate indication of what our actual results would have been if our Corporate Reorganization and the Burleson North Acquisition had been completed at the beginning of the periods presented.

Drilling Activity

For certain periods during 2015, we ran a four-rig drilling program on a combined basis with up to two rigs operating in our Eagle Ford Acreage and up to two rigs operating in our North Louisiana Acreage. After temporarily reducing the pace of our drilling and completions activities in the first quarter of 2016 due to commodity prices, we began running one rig on our Eagle Ford Acreage starting in May 2016. In our North Louisiana Acreage, we intend to recommence drilling by adding one rig in late 2016 and one rig in 2017, and in our Eagle Ford Acreage, we intend to add three additional drillings rigs in 2017, for a six-rig program across our entire acreage by the end of 2017. Please see “—Overview—Drilling Activity.” We retain the flexibility to adjust our rig count based on the commodity price environment. Reductions in drilling and completion activity may result in slower growth of, or declining levels in, our oil, natural gas and NGLs production and reserves.

Oil and Gas Property Acquisitions

WildHorse . Throughout 2014, WildHorse acquired approximately 23,021 net acres of oil and natural gas properties in North Louisiana. Such acquisitions included six producing wells.

Esquisto . The Contribution of the Initial Esquisto Assets occurred in June 2014, and Esquisto completed the Comstock Acquisition, whereby Esquisto II acquired producing properties, undeveloped acreage and water assets from a wholly owned subsidiary of Comstock Resources, Inc. in July 2015. The Comstock Acquisition included 15 producing wells and, at the time of the acquisition, had net daily production of 2,177 Boe/d. Further, Esquisto has completed or will complete the November Acquisition and the Rosewood Acquisition which are not included in its historical financial statements or our pro forma financial statements.

Acquisition Co . In October 2016, Acquisition Co. entered into a purchase agreement to acquire the Burleson North Assets, which included approximately 158,000 net acres that produced approximately 3.9 MBoe/d for the three months ended September 30, 2016.

Public Company Expenses

Upon completion of this offering, we expect to incur direct, 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. These direct, incremental G&A expenses are not included in our predecessor’s historical results of operations.

Income Taxes

WildHorse Development is a corporation for federal income tax purposes, and, as a result, will be subject to U.S. federal, state and local income taxes. Although, our predecessor was subject to certain franchise taxes and had one subsidiary taxed as a corporation, our predecessor generally was not subject to entity level income tax, and the financial data attributable to our predecessor contains substantially no provision for U.S. federal income taxes or income taxes in any state or locality. We estimate that WildHorse Development will be subject to U.S. federal, state and local taxes at a blended statutory rate of 40% of pre-tax earnings.

Impairment Expense

We evaluate our proved properties for impairment when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount

exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. On a pro forma basis, we recorded $24.7 million and $9.3 million of impairment expense during the years ended December 31, 2014 and 2015, respectively. See “Risk Factors—Risks Related to Our Business—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.”

Management Services Agreement

In June 2014, our predecessor entered into a Management Services Agreement with MRD (the “Management Services Agreement”) pursuant to which we were obligated to provide accounting and operating transition services to MRD. Pursuant to the Management Services Agreement, we made $57.6 million in net payments in 2015 and received net payments of $53.0 million in 2014. In February 2015, the Management Services Agreement was terminated effective March 1, 2015. For more information about the Management Services Agreement, please see “Certain Relationships and Related Party Transactions—Related Party Transactions prior to the Corporate Reorganization.”

Derivative Activities

In the year ended December 31, 2015 and the nine months ended September 30, 2016, our hedging activities resulted in our recognizing a $13.9 million derivative gain, of which $12.0 million was realized and $1.9 million was unrealized, and a $8.7 million derivative loss, of which $5.6 million was a realized gain and $14.3 million was an unrealized loss, respectively, due primarily to fluctuations in commodity prices during those periods. As commodity prices fluctuate, so will the income or loss we recognize from our hedging activities. For more information regarding our historic hedging activities, please see “—Overview—Derivative Activity.”

Pro Forma Results of Operations and Operating Expense

We were formed as a Delaware corporation in August 2016 to serve as a holding company and have not had any operations since our formation. As a result, we do not have historical financial operating results. Our accounting predecessor is WildHorse, but our future results of operations may not be comparable to the historical results of operations of WildHorse due to the fact that the composition of us and our assets will change as a result of the Corporate Reorganization and the Burleson North Acquisition and for the other reasons described in “—Factors Affecting the Comparability of Our Results of Operations to the Historical Results of Operations of Our Predecessor.” Accordingly, in addition to presenting a discussion of WildHorse’s results of operations, we are also presenting WildHorse’s pro forma results of operations which gives effect to the adjustments described below under “—Pro Forma Adjustments.” The pro forma information presented below should be read in conjunction with the unaudited pro forma financial statements included elsewhere in this prospectus, which describe the assumptions and adjustments used in preparing such information. The pro forma adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the pro forma assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma combined financial statements.

The pro forma information is presented for illustrative purposes only. If this offering and other transactions contemplated herein had occurred in the past, operating results might have been materially different from those presented in the pro forma financial information. The pro forma financial information should not be relied upon as an indication of operating results that we would have achieved if this offering and other transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the pro forma results reflected herein and should not be relied on as an indication of our future results following the completion of this offering and the other transactions contemplated by this pro forma financial information.

Pro Forma Adjustments

The unaudited pro forma combined statements of operations give effect to the following:

•

for the year ended December 31, 2014, the Corporate Reorganization and the contribution to Esquisto of the Initial Esquisto Assets as if they had been completed as of January 1, 2014;

•

for the nine months ended September 30, 2015, (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015;

•

for the year ended December 31, 2015, (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015; and

•

for the nine months ended September 30, 2016, (i) the Corporate Reorganization (ii) the Burleson North Acquisition and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015.

For additional information regarding our pro forma financial information, please see the unaudited pro forma financial statements included elsewhere in this prospectus.

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

Revenues . The following table provides the components of our pro forma revenues, net of transportation and gathering fees, for the periods indicated, as well as each period’s respective realized average prices and production volumes:


	Pro Forma				Change			% Change
	Nine Months Ended September 30,
	2016		2015
Revenues (in thousands):
Oil sales	$	86,279	$	112,087	$	(25,808	)		(23	)%
Natural gas sales		29,560		29,199		361			1	%
NGL sales		4,428		5,069		(640	)		(13	)%
Gathering system income		1,158		—		1,158			N/A

Total revenues	$	121,426	$	146,355	$	(24,929	)		(17	)%

Average sales price:(1)
Oil (per Bbl)	$	38.40	$	48.47	$	(10.07	)		(21	)%
Natural gas (per Mcf)		2.00		2.46		(0.46	)		(19	)%
NGL (per Bbl)		10.88		12.12		(1.24	)		(10	)%

Total (per Boe)	$	23.51	$	31.07	$	(7.56	)		(24	)%

Production:
Oil (MBbls)		2,247		2,312		(66	)		(3	)%
Natural gas (MMcf)		14,766		11,875		2,891			24	%
NGLs (MBbls)		407		418		(11	)		(3	)%

Total (MBoe)		5,115		4,710		405			9	%

Average daily production volume:
Oil (Bbls/d)		8,201		8,471		(270	)		(3	)%
Natural gas (Mcf/d)		53,891		43,500		10,392			24	%
NGLs (Bbls/d)		1,485		1,532		(47	)		(3	)%

Total (Boe/d)		18,668		17,253		1,415			8	%

(1)	Average prices shown in the table reflect realized prices before the effects of our pro forma realized commodity derivative transactions but after gathering and transportation expense.

As reflected in the table above, our total revenues on a pro forma basis for the nine months ended September 30, 2016 were 17%, or $24.9 million, lower than the same period in 2015. This was due to a decrease of approximately $29.9 million due to lower commodity prices offset by an increase of approximately $3.8 million due to higher production volumes from additional drilling and approximately $1.2 million of revenues from our gathering system, which commenced operations in October 2015.

Oil sales decreased 23%, or $25.8 million, for the nine months ended September 30, 2016 as compared to the prior year period primarily from decreased oil production totaling approximately $3.2 million and lower oil prices of approximately $22.6 million. Gas sales increased 1%, or $0.4 million, for the nine months ended September 30, 2016 as compared to the prior year period primarily from additional drilling totaling approximately $7.1 million partially offset by lower natural gas prices of approximately $6.7 million. NGL sales decreased 13%, or $0.6 million for the nine months ended September 30, 2016 as compared to the prior year period primarily from a decrease of $0.5 million due to lower NGL prices and a decrease in NGL production of approximately $0.1 million.

Our gathering system became operational in October 2015 and generated $1.2 million in gathering fee income for the nine months ended September 30, 2016. Gathering system income includes a transportation and metering fee, which is charged to certain third parties. There was no gathering system income during the prior year period as the gathering system was not operational.

The following table summarizes our expenses for the periods indicated on a pro forma basis, which includes a presentation of expenses per Boe because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:


	Pro Forma					Change			% Change
	Nine Months Ended September 30,
	2016			2015
	(Unaudited)
Operating expenses (in thousands):
Lease operating expenses	$	21,865		$	26,272	$	(4,407	)		(17	)%
Gathering system operating expense		99			317		(218	)		(69	)%
Production and ad valorem taxes		8,600			9,915		(1,315	)		(13	)%
Depreciation, depletion and amortization		79,519			71,834		7,685			11	%
Impairment of proved oil and gas properties		—			8,032		(8,032	)		(100	)%
General and administrative expenses		14,058			11,707		2,351			20	%
Exploration expense		8,975			14,512		(5,537	)		(38	)%

Total operating expense	$	133,116		$	142,589	$	(9,473	)		(7	)%

Gain (loss) from operations	$	(11,691	)	$	3,766	$	(15,457	)		(410	)%

Expenses per Boe:
Lease operating expenses	$	4.27		$	5.58	$	(1.30	)		(23	)%
Gathering system operating expense		0.02			0.07		(0.05	)		(71	)%
Production and ad valorem taxes		1.68			2.11		(0.42	)		(20	)%
Depreciation, depletion and amortization		15.55			15.25		0.29			2	%
Impairment of proved oil and gas properties		—			1.71		(1.71	)		(100	)%
General and administrative expenses		2.75			2.49		0.26			11	%
Exploration expense		1.75			3.08		(1.33	)		(43	)%

Total operating expenses per Boe	$	26.03		$	30.27	$	(4.25	)		(14	)%

Gain (loss) from operations	$	(2.29	)	$	0.80	$	(3.09	)		(386	)%

Lease Operating Expenses . LOE decreased 17%, or $4.4 million, in the nine months ended September 30, 2016 compared to the prior year period, primarily due to lower production from the Burleson North Assets, lower location and road maintenance expenses, lower workover costs and lower service costs associated with industry-wide service cost decreases. Lease operating expense per Boe decreased 23%, from $5.58 to $4.27, in the nine months ended September 30, 2016 compared to the prior year period primarily due to lower LOE and certain items, such as direct labor and materials and supplies, generally remaining relatively fixed across higher production volume ranges.

Gathering System Operating Expenses . Gathering system operating expenses decreased 69%, or $0.2 million, in the nine months ended September 30, 2016 compared to the prior year nine-month period, primarily due to startup costs associated with bringing the gathering system online in 2015. Gathering system operating expense per Boe decreased 71%, from $0.07 to $0.02, in the nine months ended September 30, 2016 compared to the prior year period.

Production and Ad Valorem Taxes . Production and ad valorem taxes decreased 13%, or $1.3 million, in the nine months ended September 30, 2016 compared to the prior year period, primarily due to a decrease in revenues associated with our oil and natural gas properties. Production and ad valorem taxes per Boe decreased 20%, from $2.11 to $1.68, in the nine months ended September 30, 2016 compared to the prior year period due primarily to a decrease in revenue associated with our oil and natural gas properties and severance tax exemptions on high-cost horizontal wells.

Depreciation, Depletion and Amortization . DD&A increased 11%, or $7.7 million, for the nine months ended September 30, 2016 compared to the prior year period, primarily due to increased production. Increased production volumes caused DD&A expense to increase by $6.2 million, and the rate of DD&A increased between periods as a result of a decrease in commodity prices, capital expenditures associated with our drilling program and land costs transferred to our depletion pools, which outpaced reserve adds and caused the DD&A expense to increase by $1.5 million.

Impairment of Proved Oil and Gas Properties . We had no impairment expense for the nine months ended September 30, 2016. For the nine months ended September 30, 2015, we impaired certain non-core properties in Texas and Louisiana by $8.0 million. The estimated future cash flows expected from these non-core properties were compared to their carrying values and determined to be unrecoverable, primarily due to a significant decrease in commodity prices.

General and Administrative Expenses . G&A expenses increased 20%, or $2.4 million, for the nine months ended September 30, 2016 compared to the prior year period. The increase was primarily due to the reduction in G&A reimbursements of $1.9 million in the current period due to the termination in February 2015 of the Management Services Agreement and an increase in professional fees associated with this offering. Please see “Certain Relationships and Related Party Transactions—Related Party Transactions prior to the Corporate Reorganization.”

Exploration Expense . Exploration expense decreased 38%, or $5.5 million, in the nine months ended September 30, 2016 compared to the prior year period. Exploration expense for the nine months ended September 30, 2016 included a $6.8 million expense associated with the early termination of a rig contract, which was laid down in March 2016 due to low commodity prices. While the full amount of the early termination fee was recorded for book purposes in the nine months ended September 30, 2016, the liability will be paid in equal monthly installments through December 31, 2016. Exploration expense for the nine months ended September 30, 2015 included $7.2 million of dry hole expense, $1.3 million of leasehold impairment and $4.2 million of seismic purchases.

Other Income and Expenses . The following table summarizes our other income and expenses on a pro forma basis for the periods indicated:


	Pro Forma						Change			% Change
	Nine Months Ended September 30,
	2016			2015
	(Unaudited)
Other (expense) income (in thousands):
Interest expense	$	(1,539	)	$	(1,539	)		—			—
Other (expense) income		(429	)		(472	)	$	43			(9	)%
Gain (loss) on derivative instruments		(8,694	)		7,179			(15,873	)		(221	)%

Total other income (expense)	$	(10,662	)	$	5,168		$	(15,830	)		NM

Income tax benefit	$	8,956		$	(2,398	)	$	11,354			NM

NM—Not Meaningful

Interest Expense . Interest expense did not change in the nine months ended September 30, 2016 compared to the prior period.

Other (Expense) Income. In each of the nine months ended September 30, 2016 and 2015, we had other expense of $0.4 million. The other expense during the nine months ended September 30, 2016 primarily related to the write-off of unamortized debt issuance costs associated with the retirement and termination of the Esquisto BOK revolving credit facility and the payment of a pre-payment penalty related to the early pay-off and termination of Esquisto’s second lien debt in January 2016. The other expense during the nine months ended September 30, 2015 was due to costs associated with the Comstock Acquisition and another potential transaction that did not materialize.

Gain (Loss) on Derivative Instruments . In the nine months ended September 30, 2016, we recognized a $8.7 million derivative loss, of which $5.6 million was a realized gain and $14.3 million was an unrealized loss. For the prior period, we recognized a $7.2 million derivative gain, of which $7.3 million was a realized gain and $0.1 million was an unrealized loss. 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.

Income Tax Benefit. We recognized a $9.0 million income tax benefit at September 30, 2016 and a $2.4 million income tax expense at September 30, 2015. The difference is primarily due to generating an $8.9 million gain before income taxes at September 30, 2015 and a $22.3 million loss before income taxes at September 30, 2016. Income tax benefit, on a pro forma basis, results from our being subject to U.S. federal income taxes as if the Corporate Reorganization occurred on January 1, 2015.

Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

Revenues . The following table provides the components of our revenues on a pro forma basis, net of transportation and gathering fees, for the years indicated, as well as each year’s respective realized average prices and production volumes:


	Pro Forma
	Year Ended December 31,				$ Change			% Change
	2015		2014		$ Change			% Change
Revenues (in thousands):
Oil sales	$	142,614	$	17,826	$	124,788			700	%
Natural gas sales		38,063		38,345		(282	)		(1	)%
NGL sales		6,722		2,285		4,438			194	%
Gathering system income		314		—		314			N/A

Total revenues	$	187,713	$	58,456	$	129,258			221	%

Average sales price:(1)
Oil (per Bbl)	$	45.99	$	86.13	$	(40.14	)		(47	)%
Natural gas (per Mcf)		2.27		4.01		(1.74	)		(43	)%
NGLs (per Bbl)		11.92		25.55		(13.63	)		(53	)%

Total (per Boe)	$	29.01	$	30.96	$	(1.94	)		(6	)%

Production:
Oil (MBbls)		3,101		207		2,894			1,398	%
Natural gas (MMcf)		16,767		9,552		7,215			76	%
NGLs (MBbls)		564		89		475			531	%

Total (MBoe)		6,459		1,888		4,571			242	%

Average daily production volumes:
Oil (Bbls/d)		8,496		567		7,929			1,398	%
Natural gas (Mcf/d)		45,936		26,169		19,767			76	%
NGLs (Bbls/d)		1,545		245		1,300			531	%

Total (Boe/d)		17,697		5,174		12,524			242	%

(1)	Average prices shown in the table reflect prices before the effects of our pro forma realized commodity derivative transactions but after gathering and transportation expense.

As reflected in the table above, our total revenues on a pro forma basis for 2015 were 221%, or $129.3 million, higher than 2014. This was due to an increase of approximately $99.0 million due to higher production volumes from additional drilling and approximately $191.3 million due to higher production from the Burleson North Assets and the Comstock Assets, partially offset by approximately $161.4 million due to lower commodity prices and a $0.3 million increase from our gathering system, which commenced operations in October 2015.

Oil sales increased 700%, or $124.8 million, for the year ended December 31, 2015 as compared to the prior year primarily from additional drilling totaling approximately $70.5 million and from additional production from the Burleson North Assets and the Comstock Assets of approximately $178.9 million, partially offset by lower oil prices of approximately $124.5 million. Gas sales decreased 1%, or $0.3 million, for the year ended December 31, 2015 as compared to the prior year primarily from decreased natural gas prices of approximately $29.3 million, partially offset by increases from additional drilling totaling approximately $21.5 million and from additional production from the Burleson North Assets and the Comstock Assets of approximately $7.5 million. NGL sales increased 194%, or $4.4 million, for the year ended December 31, 2015 as compared to the prior year primarily from additional drilling totaling approximately $7.0 million and additional production from the Burleson North Assets and the Comstock Assets of approximately $5.1 million, partially offset by lower NGL prices of approximately $7.7 million.


	Pro Forma
	Year Ended December 31,						$ Change			% Change
	2015			2014			$ Change			% Change
Operating expenses (in thousands):
Lease operating expenses	$	35,339		$	10,540		$	24,799			235	%
Gathering system operating expenses		914			—			914			N/A
Production and ad valorem taxes		12,991			3,405			9,586			282	%
Cost of oil sales		—			687			(687	)		(100	)%
Depreciation, depletion and amortization		99,009			23,269			75,740			326	%
Impairment of proved oil and gas properties		9,312			24,721			(15,409	)		(62	)%
General and administrative expenses		16,611			8,226			8,386			102	%
Exploration expense		17,863			1,599			16,264			NM

Total operating expenses	$	192,039		$	72,447		$	119,592			165	%

Loss from operations	$	(4,325	)	$	(13,991	)	$	9,666			69	%

Expenses per Boe:
Lease operating expenses	$	5.47		$	5.58		$	(0.11	)		(2	)%
Gathering system operating expenses		0.14			—			0.14			N/A
Production and ad valorem taxes		2.01			1.80			0.21			12	%
Cost of oil sales		—			0.36			(0.36	)		(100	)%
Depreciation, depletion and amortization		15.33			12.32			3.01			24	%
Impairment of proved oil and gas properties		1.44			13.09			(11.65	)		(89	)%
General and administrative expenses		2.57			4.36			(1.78	)		(41	)%
Exploration expense		2.77			0.85			1.92			227	%

Total operating expenses per Boe	$	29.73		$	38.37		$	(8.64	)		(23	)%

Gain (loss) from operations	$	(0.67	)	$	(7.41	)	$	6.74			91	%

Lease Operating Expenses . In 2015, LOE increased 235%, or $24.8 million, when compared to 2014, primarily due to LOE associated with increased production volumes, properties acquired in the Burleson North Acquisition and the Comstock Acquisition and increased water disposal charges related to our new wells partially offset by lower service costs associated with industry-wide service cost decreases. On a Boe basis, lease operating expense decreased from $5.58 to $5.47 primarily due to certain items, such as direct labor and materials and supplies, generally remaining relatively fixed across higher production volume ranges, and lower workover costs in 2015 compared to 2014.

Gathering System Operating Expenses . Gathering system operating expenses was $0.9 million in the year ended December 31, 2015. The gathering system commenced operations in October 2015, prior to which there were no gathering system operating expenses. In 2015, gathering system operating expenses included $0.7 million of non-recurring expenses related to the termination of an amine plant and the associated mobilization and demobilization expenses, which was mobilized but ended up being unnecessary.

Production and Ad Valorem Taxes . Production and ad valorem taxes increased 282%, primarily due to the Burleson North Acquisition and the Comstock Acquisition and increased oil and natural gas production. On a Boe basis, production and ad valorem taxes increased 12%, from $1.80 in 2014 to $2.01 in 2015.

market price. As the oil in tanks is sold, it is replaced by oil produced by us, which is recorded at the lower of cost or market. The accounting adjustment to reduce oil to the lower of cost or market in 2014 was $0.7 million. No accounting adjustment was needed in 2015.

Depreciation, Depletion and Amortization . In 2015, DD&A expense increased 326%, or $75.7 million, when compared to 2014, primarily due to increased production volumes from the properties acquired in the Burleson North Acquisition and the Comstock Acquisition. Increased production volumes caused DD&A expense to increase by $56.3 million and an increased rate of DD&A between periods as a result of capital expenditures associated with our drilling program and land costs transferred to our depletion pools, outpacing reserve adds, caused the DD&A expense to increase by $19.4 million.

Impairment of Proved Oil and Gas Properties . Impairment expense, related to certain Texas and Louisiana properties, decreased 62%, or $15.4 million, from $24.7 million in 2014 to $9.3 million in 2015. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable, primarily due to a significant decrease in commodity prices.

General and Administrative Expenses . G&A expenses increased 102%, or $8.4 million, in 2015 compared to 2014. The increase was primarily due to the reduction in G&A reimbursements of $8.7 million in the current period due to the termination in February 2015 of the Management Services Agreement under which we were reimbursed for certain G&A expenses. Please see “Certain Relationships and Related Party Transactions—Related Party Transactions prior to the Corporate Reorganization.” This increase in G&A expenses was partially offset by lower wages, salaries and corporate expenses in 2015.

Exploration Expense . Exploration expense increased to $17.9 million in 2015, as compared to $1.6 million in 2014, primarily due to $8.4 million of costs associated with drilling a dry well, $3.3 million of seismic surveying costs, $1.6 million of state lease delay rentals and a $2.8 million impairment of our unproved leasehold costs.

Other Income and Expenses . The following table summarizes our other income and expenses on a pro forma basis for the years indicated:


	Pro Forma
	Year Ended December 31,						$ Change			% Change
	2015			2014			$ Change			% Change
Other income (expense) (in thousands):
Interest expense	$	(2,048	)	$	(3,286	)	$	1,238			(38	)%
Other expense		(150	)		(120	)		(30	)		(25	)%
Gain on derivative instruments		13,854			6,514			7,340			113	%

Total other income (expense)	$	11,656		$	3,108		$	8,548			275	%

Income tax benefit (expense)	$	(1,686	)	$	4,502		$	(6,188	)		(137	)%

Interest Expense . Interest expense decreased $1.2 million, or 38%, primarily due to a lower average debt balance in 2015 compared to 2014.

Other Expense . In 2014, we recognized other expense of $0.1 million compared to other expense of $0.2 million in 2015, or an increase in expense of $0.03 million. The increase in expense is due primarily to a decrease in interest income.

Gain on Derivative Instruments . In 2015, we recognized a $13.9 million derivative gain of which $12.0 million was realized and $1.9 million was unrealized. For 2014, we recognized a $6.5 million derivative gain, of which $2.7 million was a realized loss and $9.2 million was an unrealized gain. Net losses on our derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

Income Tax Benefit . Pro forma income tax changed from a $4.5 million benefit at December 31, 2014 to a $1.7 million expense at December 31, 2015. Income tax benefit, on a pro forma basis, results from our being subject to U.S. federal income taxes as if the Corporate Reorganization had occurred on January 1, 2014.

Predecessor Results of Operations and Operating Expense

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

Revenues . The following table provides the components of our predecessor’s revenues, net of transportation and gathering fees, for the periods indicated, as well as each period’s respective realized average prices and production volumes:


	Predecessor				$ Change			% Change
	Nine Months Ended September 30,
	2016		2015
Revenues (in thousands):
Oil sales	$	2,971	$	2,240	$	731			33	%
Natural gas sales		25,273		23,381		1,892			8	%
NGL sales		658		1,100		(441	)		(40	)%
Gathering system income		1,158		—		1,158			N/A

Total revenues	$	30,061	$	26,721	$	3,340			12	%

Average sales price:(1)
Oil (per Bbl)	$	45.39	$	46.80	$	(1.42	)		(3	)%
Natural gas (per Mcf)		2.01		2.44		(0.43	)		(18	)%
NGL (per Bbl)		13.42		13.33		0.09			1	%

Total (per Boe)	$	13.06	$	15.46	$	(2.40	)		(16	)%

Production:
Oil (MBbls)		65		48		18			37	%
Natural gas (MMcf)		12,592		9,588		3,005			31	%
NGLs (MBbls)		49		83		(33	)		(41	)%

Total (MBoe)		2,213		1,728		485			28	%

Average daily production volume:
Oil (Bbls/d)		239		175		64			36	%
Natural gas (Mcf/d)		45,958		35,120		10,838			31	%
NGLs (Bbls/d)		179		302		(123	)		(41	)%

Total (Boe/d)		8,078		6,331		1,747			28	%

(1)	Average prices shown in the table reflect realized prices before the effects of our predecessor’s realized commodity derivative transactions but after gathering and transportation expense.

As reflected in the table above, our predecessor’s total revenues for the nine months ended September 30, 2016 were 12%, or $3.3 million, higher than the prior year period. The increase is primarily due to an increase in production from drilling new wells, the impact of which more than offset the overall 16% decrease in commodity prices from period to period.

Oil sales increased 33%, or $0.7 million, for the nine months ended September 30, 2016 as compared to the prior year period due to an increase of $0.8 million due to higher production partially offset by a decrease of $0.1 million due to lower commodity prices. Natural gas sales increased 8%, or $1.9 million, for the nine months ended September 30, 2016 as compared to the prior year period resulting from an increase of $7.3 million due to higher production partially offset by a decrease of $5.4 million due to lower commodity prices. NGL sales

decreased 40%, or $0.4 million, for the nine months ended September 30, 2016 as compared to the prior year period resulting from a decrease of $0.4 million due to lower production.

Our predecessor’s gathering system became operational in October 2015 and generated $1.2 million in revenues for the nine months ended September 30, 2016. There was no gathering system income during the prior period.

The following table summarizes our predecessor’s expenses for the periods indicated, which includes a presentation of expenses per Boe because our predecessor uses this information to evaluate its performance relative to its peers and to identify and measure trends it believes may require additional analysis:


	Predecessor						$ Change			% Change
	Nine Months Ended September 30,
	2016			2015
	(Unaudited)
Operating expenses (in thousands):
Lease operating expenses	$	4,543		$	6,178		$	(1,635	)		(26	)%
Gathering system operating expense	$	99		$	317		$	(218	)		(69	)%
Production and ad valorem taxes	$	1,843		$	1,891		$	(48	)		(3	)%
Impairment of proved oil and gas properties		—		$	8,032		$	(8,032	)		(100	)%
Depreciation, depletion and amortization	$	27,305		$	17,516		$	9,789			56	%
General and administrative expenses	$	8,399		$	7,475		$	924			12	%
Exploration expense	$	8,973		$	14,306		$	(5,333	)		(37	)%

Total operating expenses	$	51,162		$	55,715		$	(4,553	)		(8	)%

Loss from operations	$	(21,102	)	$	(28,994	)	$	7,892			27	%


Expenses per Boe:
Lease operating expenses	$	2.05		$	3.57		$	(1.52	)		(43	)%
Gathering system operating expense	$	0.04		$	0.18		$	(0.14	)		(76	)%
Production and ad valorem taxes	$	0.83		$	1.09		$	(0.26	)		(24	)%
Impairment of proved oil and gas properties		—		$	4.65		$	(4.65	)		(100	)%
Depreciation, depletion and amortization	$	12.34		$	10.13		$	2.20			22	%
General and administrative expenses	$	3.79		$	4.32		$	(0.53	)		(12	)%
Exploration expense	$	4.05		$	8.28		$	(4.22	)		(51	)%

Total operating expenses per Boe	$	23.12		$	32.24		$	(9.12	)		(28	)%

Loss from operations	$	(9.53	)	$	(16.78	)	$	7.24			(43	)%

Lease Operating Expenses . LOE decreased 26%, or $1.6 million, in the nine months ended September 30, 2016 compared to the prior year period, primarily due to lower location and road maintenance expenses, lower net water disposal costs, lower workover costs and lower service costs associated with industry-wide service cost decreases. LOE per Boe decreased 43% from $3.57 to $2.05 in the nine months ended September 30, 2016 compared to the prior year period due primarily to lower lease operating costs and certain items, such as direct labor and materials and supplies, generally remaining relatively fixed across higher production volume ranges.

Gathering System Operating Expenses . Gathering system operating expenses decreased 69%, or $0.2 million, in the nine months ended September 30, 2016 compared to the prior year period, primarily due to startup costs associated with the gathering system becoming operational in 2015. Gathering system operating expenses per Boe decreased 76%, from $0.18 to $0.04, in the nine months ended September 30, 2016 compared to the prior year period.

Production and Ad Valorem Taxes . Production and ad valorem taxes decreased 3%, or $0.1 million, in the nine months ended September 30, 2016 compared to the prior year period. Production and ad valorem taxes per Boe decreased from $1.09 in the nine months ended September 30, 2015 to $0.83 in the nine months ended September 30, 2016 due primarily to severance tax exemptions on new high-cost horizontal wells.

Depreciation, Depletion and Amortization . DD&A increased 56%, or $9.8 million, for the nine months ended September 30, 2016 compared to the prior year period, primarily due to increased production volumes. Increased production volumes caused DD&A expense to increase by $4.9 million, and an increased DD&A rate between periods as a result of a decrease in commodity prices and capital expenditures associated with our predecessor’s drilling program and land costs transferred to our predecessor’s depletion pools, which outpaced reserve adds and caused DD&A expense to increase by $4.9 million.

Impairment of Proved Oil and Gas Properties . Our predecessor had no impairment expense for the nine months ended September 30, 2016. For the nine months ended September 30, 2015, our predecessor impaired certain oil and natural gas properties in Texas and Louisiana by $8.0 million. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable, primarily due to a significant decrease in commodity prices.

General and Administrative Expenses . G&A expenses increased 12%, or $0.9 million, for the nine months ended September 30, 2016 compared to the prior year period. The increase was primarily due to the reduction in G&A reimbursements of $1.9 million in the current period due to the termination in February 2015 of the Management Services Agreement under which our predecessor was reimbursed for certain G&A expenses. Please see “Certain Relationships and Related Party Transactions—Related Party Transactions prior to the Corporate Reorganization.” This increase was offset by approximately $1.0 million in lower wages, salaries and payroll taxes.

Exploration Expense . Exploration expense decreased 37%, or $5.3 million, in the nine months ended September 30, 2016 compared to the prior year period. Exploration expense for the nine months ended September 30, 2016 included a $6.8 million expense accrual as a result of the termination of a rig contract, which was laid down in March 2016 due to low commodity prices. While the full amount of the early termination fee was recorded in the nine months ended September 30, 2016, the liability will be paid in equal monthly installments through December 31, 2016. Exploration expense for the nine months ended September 30, 2015 included $7.2 million of dry hole expense, $4.2 million of seismic purchases and $1.3 million of leasehold impairment.

Other Income and Expenses . The following table summarizes our predecessor’s other income and expenses for the periods indicated:


	Predecessor						$ Change			% Change
	Nine Months Ended September 30,
	2016			2015
	(Unaudited)
Other (expense) income (in thousands):
Interest expense	$	(2,732	)	$	(2,249	)	$	(483	)		21	%
Other income (expense)		(76	)		9			(86	)		NM
Gain (loss) on derivative instruments		(2,894	)		6,063			(8,957	)		(148	)%

Total other income (expense)	$	(5,702	)	$	3,823		$	(9,526	)		(249	)%

Income tax expense	$	(15	)	$	82		$	(96	)		(118	)%

Interest Expense . Interest expense increased 21%, or $0.5 million, compared to the prior year period due to a higher interest rate paid on average debt outstanding. The higher interest rate was the result of paying a higher spread due to utilizing a greater percentage of our predecessor’s available borrowing base during the nine months ended September 30, 2016.

Gain (loss) on Derivative Instruments . In the nine months ended September 30, 2016, our predecessor recognized a $2.9 million derivative loss, of which $3.9 million was a realized gain and $6.8 million was an unrealized loss. In the nine months ended September 30, 2015, our predecessor recognized a $6.1 million derivative gain, of which $7.0 million was a realized gain and $0.9 million was an unrealized loss. Net realized and unrealized gains on our predecessor’s derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

Revenues . The following table provides the components of our predecessor’s revenues, net of transportation and gathering fees, for the years indicated, as well as each year’s respective realized average prices and production volumes:


	Predecessor
	Year Ended December 31,				$ Change			% Change
	2015		2014		$ Change			% Change
Revenues (in thousands):
Oil sales	$	3,305	$	2,780	$	525			19	%
Natural gas sales		30,556		37,741		(7,185	)		(19	)%
NGL sales		1,451		989		462			47	%
Gathering system income		314		—		314			NM

Total revenues	$	35,627	$	41,510	$	(5,884	)		(14	)%

Average sales price:(1)
Oil (per Bbl)	$	45.20	$	90.59	$	(45.39	)		(50	)%
Natural gas (per Mcf)	$	2.24	$	4.02	$	(1.78	)		(44	)%
NGLs (per Bbl)	$	14.05	$	23.90	$	(9.84	)		(41	)%

Total (per Boe)	$	14.42	$	25.36	$	(10.94	)		(43	)%

Production:
Oil (MBbls)		73		31		42			138	%
Natural gas (MMcf)		13,637		9,388		4,249			45	%
NGLs (MBbls)		103		41		62			150	%

Total (MBoe)		2,449		1,637		812			50	%

Average daily production volumes:
Oil (Bbls/d)		200		84		116			138	%
Natural gas (Mcf/d)		37,361		25,721		11,640			45	%
NGLs (Bbls/d)		283		113		170			150	%

Total (Boe/d)		6,710		4,484		2,226			50	%

NM—Not Meaningful

(1)	Average prices shown in the table reflect prices before the effects of our predecessor’s realized commodity derivative transactions but after gathering and transportation expense.

As shown in the table above, our predecessor’s total revenues for 2015 were 14%, or $5.9 million, lower than in 2014. This was due to a decrease in revenue of $28.6 million due to lower commodity prices partially offset by an increase of $22.4 million due to an increase in production from drilling additional wells and a $0.3 million increase from our gathering system.

Oil sales increased 19%, or $0.5 million, for the year ended December 31, 2015 as compared to the prior year due to an increase of $3.8 million due to higher production partially offset by a decrease of $3.3 million due to commodity prices. Natural gas sales decreased 19%, or $7.2 million, for the year ended December 31, 2015 as

compared to the prior year due to a decrease of $24.3 million due to lower commodity prices partially offset by an increase of $17.1 million due to an increase in production from drilling additional wells. NGL sales increased 47%, or $0.5 million, for the year ended December 31, 2015 as compared to the prior year due to an increase of $1.5 million due to an increase in production from drilling such additional wells partially offset by a decrease of $1.0 million due to commodity prices. Please see “Overview—Drilling Activity.”


	Predecessor
	Year Ended December 31,						$ Change			% Change
	2015			2014			$ Change			% Change
Operating expenses (in thousands):
Lease operating expenses	$	8,606		$	9,428		$	(822	)		(9	)%
Gathering system operating expenses		914			—			914			N/A
Production and ad valorem taxes		2,666			2,584			82			3	%
Cost of oil sales		—			687			(687	)		(100	)%
Depreciation, depletion and amortization		25,526			15,297			10,229			67	%
Impairment of proved oil and gas properties		9,312			24,721			(15,409	)		(62	)%
General and administrative expenses		10,567			5,838			4,729			81	%
Exploration expense		14,896			1,597			13,299			833	%

Total operating expenses	$	72,487		$	60,152		$	12,335			21	%

Loss from operations	$	(36,861	)	$	(18,642	)	$	(18,219	)		(98	)%

Expenses per Boe:
Lease operating expenses	$	3.51		$	5.76		$	(2.25	)		(39	)%
Gathering system operating expenses	$	0.37			—		$	0.37			N/A
Production and ad valorem taxes	$	1.09		$	1.58		$	(0.49	)		(31	)%
Cost of oil sales		—		$	0.42		$	(0.42	)		(100	)%
Depreciation, depletion and amortization	$	10.42		$	9.35		$	1.08			12	%
Impairment of proved oil and gas properties	$	3.80		$	15.10		$	(11.30	)		(75	)%
General and administrative expenses	$	4.31		$	3.57		$	0.75			21	%
Exploration expense	$	6.08		$	0.98		$	5.11			523	%

Total operating expenses per Boe	$	29.60		$	36.75		$	(7.15	)		(19	)%

Loss from operations	$	(15.05	)	$	(11.39	)	$	(3.66	)		(32	)%

Lease Operating Expenses . Our predecessor experienced volatility in its LOE as a result of fluctuations in service provider costs and seasonality in workover expense. In 2015, LOE decreased 9%, or $0.8 million when compared to 2014, primarily due to lower workover expenses of $1.5 million and lower service costs associated with industry-wide service cost decreases, partially offset by higher water disposal fees for new wells. On a Boe basis, lease operating expense decreased from $5.76 to $3.51 due primarily to certain items, such as direct labor and materials and supplies, generally remaining relatively fixed across higher production volumes, and lower workover costs in 2015 compared to 2014.

Gathering System Operating Expenses . Gathering system operating expense was $0.9 million in the year ended December 31, 2015. The gathering system commenced operations in 2015, prior to which there were no gathering system operating expenses. In 2015, gathering system operating expenses included $0.7 million of non-recurring expenses related to the termination of an entire plant and the associated mobilization and demobilization expenses, which was mobilized but ended up being unnecessary.

Production and Ad Valorem Taxes . Production and ad valorem taxes increased 3%, primarily due to increased oil and natural gas production. Production and ad valorem taxes as a percentage of our predecessor’s revenue were 7.5% for 2015 compared to 6.2% for 2014. On a Boe basis, production and ad valorem taxes decreased from $1.58 in 2014 to $1.09 in 2015 due primarily to severance tax exemptions on new high-cost horizontal wells.

Cost of Oil Sales . Cost of oil sales in 2014 was $0.7 million and there were no cost of oil sales in 2015. When oil inventory is acquired in an acquisition, the oil in tanks is recorded at the price paid, which is the market price. As the oil in tanks is sold, it is replaced by oil produced by us, which is recorded at the lower of cost or market. The accounting adjustment to reduce oil to the lower of cost or market in 2014 was $0.7 million. No accounting adjustment was needed in 2015.

Depreciation, Depletion and Amortization . In 2015, DD&A expense increased 67%, or $10.2 million, when compared to 2014, primarily due to increased production. Increased production volumes caused DD&A expense to increase by $7.6 million and an increased DD&A rate between periods as a result of capital expenditures associated with our predecessor’s drilling program and land costs transferred to our predecessor’s depletion pools, outpacing reserve adds, caused DD&A expense to increase by $2.6 million

Impairment of Proved Oil and Gas Properties . Impairment expense decreased 62%, or $15.4 million in 2015 compared to 2014. The impairments were on certain oil and natural gas Southeast Texas and North Louisiana properties. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable, primarily due to a significant decrease in commodity prices.

General and Administrative Expenses . G&A expenses increased 81%, or $4.7 million, in 2015 compared to 2014. The increase was primarily due to the reduction in G&A reimbursements of $8.7 million in the current period due to the termination in February 2015 of the Management Services Agreement under which our predecessor was reimbursed for certain G&A expenses. Please see “Certain Relationships and Related Party Transactions—Related Party Transactions prior to the Corporate Reorganization.” This increase was partially offset by lower wages and salaries and corporate expenses in 2015.

Exploration Expense . Exploration expense increased to $14.9 million in 2015 as compared to $1.6 million in 2014, primarily due to $8.4 million of costs associated with the drilling a dry well, $3.3 million of seismic surveying costs and $1.6 million of state lease delay rentals.

Other Income and Expenses . The following table summarizes our predecessor’s other income and expenses for the years indicated:


	Predecessor
	Year Ended December 31,						$ Change			% Change
	2015			2014			$ Change			% Change
Other income (expense) (in thousands):
Interest expense	$	(2,576	)	$	(2,680	)	$	104			4	%
Other (expense) income		(45	)		213			(258	)		(121	)%
Gain on derivative instruments		9,510			6,514			2,996			46	%

Total other income	$	6,889		$	4,047		$	2,842			70	%

Income tax benefit	$	17		$	158		$	(141	)		(89	)%

Interest Expense . Interest expense decreased 4%, or $0.1 million, compared to the prior year period primarily due to a higher interest rate paid on average debt outstanding, as well as to increased borrowings. The higher interest rate was the result of paying a higher spread due to utilizing a greater percentage of our predecessor’s available borrowing base during the three months ended March 31, 2016.

Other (Expense) Income . In 2014, our predecessor recognized other income of $0.2 million compared to other expense of $0.05 million in 2015, or a decrease in income of $0.3 million. The decrease in income is due primarily to the reduction in interest income of $0.3 million in 2015 compared to 2014.

Gain on Derivative Instruments . In 2015, our predecessor recognized a $9.5 million derivative gain of which $11.1 million was realized offset with an unrealized loss of $1.6 million. In 2014, our predecessor recognized a $6.5 million derivative gain, of which $2.7 million was a realized loss and $9.2 million was an unrealized gain. Net gains on derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

Income Tax Benefit . For 2015 and 2014, our predecessor recognized net tax benefits of $0.02 million and $0.2 million, respectively, associated with Texas franchise tax and federal income taxes associated with our predecessor’s 100% owned single member management company, which has elected to be treated as a corporation for U.S. federal income tax purposes.

Capital Resources and Liquidity

Our development and acquisition activities require us to make significant operating and capital expenditures. WildHorse’s and Esquisto’s primary use of capital has been the acquisition and development of oil, natural gas and NGL properties and facilities, and the development of a gathering and salt water disposal system. Historically, WildHorse’s and Esquisto’s primary sources of liquidity were capital contributions from their Existing Owners, borrowings under their respective revolving credit facilities and cash generated by their operations. Following this offering, our Existing Owners will have no obligation to make capital contributions to us.

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.

Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us. Our 2016 capital budget is $137.5 million, substantially all of which we intend to allocate to our current areas of operation. This represents a 68% decrease over the $424.6 million in 2015 combined capital expenditures, which includes capital expenditures related to acquisitions. We intend to allocate approximately $106.9 million of our 2016 capital budget to the drilling of 19 gross (16 net) wells and the completion of 19 gross (16 net) wells, approximately $2.7 million to midstream, and approximately $26.5 million to leasehold acquisitions, which includes approximately $17.7 million for lease extensions and renewals. See “Business—Reserve Data—Undeveloped Acreage Expiration.” As of September 30, 2016, 14 gross (12 net) of such wells had been completed and 10 gross (nine net) of such wells have been spud, and we had spent $99.8 million of our 2016 capital expenditure budget. Our 2017 capital expenditure budget is $539.5 million, of which we expect to spend $471.2 million to drill and complete 81 gross (67 net) wells across our acreage, including $409.0 million in our Eagle Ford Acreage to drill 84 gross (73 net) wells with an average lateral length of 6,406 feet, 72 gross (62 net) of which we expect to complete in 2017, and $62.2 million in our North Louisiana Acreage to drill 12 gross (seven net) wells with an average lateral length of 9,062 feet, nine gross (five net) of which we expect to complete in 2017, $39.6 million for lease extensions and renewals, $22.3 million for midstream infrastructure development and $6.4 million for other investments, including seismic and capital workover projects. For more information, please see “Prospectus Summary—Capital Program.”

Following this offering, we expect to fund our capital expenditures with cash generated by operations, cash on hand and borrowings under our new revolving credit facility. Further, we intend to monitor conditions in the debt capital markets and may determine to issue long-term debt securities, including potentially in the near term, to fund a portion of our 2017 capital program. We cannot predict with certainty the timing, amount and terms of any future issuances of any such debt securities. Specifically, after giving effect to this offering and the use of the

proceeds, our new revolving credit facility will have a $450.0 million borrowing base, of which we expect approximately $ million will be available following the completion of the Burleson North Acquisition. Our cash flow from operations has historically contributed less than external financing to funding our capital requirements, specifically with respect to our capital expenditure budget. We believe that the lag time between initial investment and cash flow from such investment is typical of the oil and natural gas industry. The amount, timing and allocation of capital expenditures is largely discretionary and within our control, and our 2016 and 2017 capital budgets may be adjusted as business conditions warrant. Recently, commodity prices declined significantly and have remained depressed thus far in 2016. If oil or natural gas prices remain depressed or decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will have the highest expected rates of return and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control. Any reduction in our capital expenditure budget could have the effect of delaying or limiting our development program, which would negatively impact our ability to grow production and could materially and adversely affect our future business, financial condition, results of operations or liquidity.

We intend to fund our remaining 2016 capital expenditures and our 2017 capital expenditure budget of $539.5 million and our cash requirements, including normal cash operating needs, debt service obligations and commitments and contingencies through December 31, 2017, with borrowings under our new revolving credit facility and our operating cash flow. However, to the extent that we consider market conditions favorable, we may access the capital markets to raise capital from time to time to fund acquisitions, pay down our new revolving credit facility and for general working capital purposes.

We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we expect to maintain an active hedging program that seeks to reduce our exposure to commodity prices and protect our cash flow.

Predecessor Cash Flows

The following table summarizes our predecessor’s cash flows for the periods indicated.


	Predecessor
	Year Ended December 31,						Nine Months Ended September 30,
	2014			2015			2015			2016
							(unaudited)
	(In thousands)
Net cash provided by (used in) operating activities	$	25,660		$	25,374		$	10,894		$	(9,542	)
Net cash used in investing activities	$	(128,968	)	$	(147,321	)	$	(109,842	)	$	(15,055	)
Net cash provided by financing activities	$	114,589		$	131,984		$	118,594		$	3,708

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $25.4 million for the year ended December 31, 2015, compared to $25.7 million of net cash provided by operating activities for the year ended December 31, 2014. The change in operating cash flow was primarily the result of the significant decrease in commodity prices and higher G&A expense, largely offset by higher realized hedging gains, higher production and changes in working capital.

Net cash used by operating activities was $9.5 million for the nine months ended September 30, 2016, compared to $10.9 million of net cash provided by operating activities for the nine months ended September 30, 2015. The change in operating cash flow was primarily the result of changes in working capital.

Cash Flow Used In Investing Activities

During the years ended December 31, 2015 and 2014, cash flows used in investing activities were $147.3 million and $129.0 million, respectively. The increase for 2015 compared to the prior year is primarily due to greater drilling activity and costs associated with building our gathering system.

During the nine months ended September 30, 2016 and 2015, cash flows used in investing activities were $15.0 million and $109.8 million, respectively. The decrease is primarily related to a decrease in drilling activity due to lower gas prices.

Cash Flow Provided By Financing Activities

Net cash provided by financing activities of $132.0 million during the year ended December 31, 2015 was primarily attributable to capital contributions from Existing Owners, and borrowings from WildHorse’s revolving credit facility. Net cash provided by financing activities of $114.6 million during the year ended December 31, 2014 was the result of capital contributions from Existing Owners, and borrowings from WildHorse’s revolving credit facility.

Net cash provided by financing activities of $3.7 million during the nine months ended September 30, 2016 was primarily attributable to capital contributions from Existing Owners. Net cash provided by financing activities of $118.6 million during the nine months ended September 30, 2015 was primarily the result of capital contributions from Existing Owners borrowings from the WildHorse revolving credit facility.

Debt Agreements

New Revolving Credit Facility . Concurrently with the closing of this offering, we anticipate that we, as borrower, and certain of our current and future subsidiaries, as guarantors, will enter into a new senior secured revolving credit facility. We expect our new revolving credit facility to be a five-year, $1.0 billion revolving credit facility with, following the completion of the Burleson North Acquisition, an initial borrowing base of $450.0 million and aggregate elected commitments of $450.0 million.

Our new revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil, NGL and natural gas properties and our commodity derivative contracts as determined by our lenders in their sole discretion consistent with their normal and customary oil and gas lending practices semi-annually (in the case of Scheduled Redeterminations), from time to time at our election in connection with material acquisitions, or no more frequently than twice in any fiscal year at the request of the Required Lenders or us (in the case of Interim Redeterminations), in each case based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, and our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base, while only Required Lender approval is required to maintain or decrease the borrowing base, pursuant to a Redetermination. In the future, we may be unable to access sufficient capital under our new revolving credit facility as a result of (i) a decrease in our borrowing base due to a borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations. For more information, please see “Risk Factors—Risks Related to Our Business—Any significant reduction in our borrowing base under our new revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.”

A decline in commodity prices could result in a redetermination that lowers our borrowing base and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. If a redetermination of our borrowing base

results in our borrowing base being less than our aggregate elected commitments, our aggregate elected commitments will be automatically reduced to the amount of such reduced borrowing base. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our new revolving credit facility.

Borrowings under the new revolving credit facility will be secured by liens on substantially all of our properties, but in any event, not less than 85% of the present value, as determined by the administrative agent, of the proved reserves attributable to our oil and natural gas properties included in our most recent reserve report (initially 75% of the present value in the case of the proved reserves attributable to oil and natural gas properties of WildHorse and Acquisition Co. included in such reserve report), and all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property but excluding equity interests in and assets of unrestricted subsidiaries.

Additionally, borrowings under the new revolving credit facility will bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the thirty-day adjusted LIBOR plus 1.0%, in each case, plus a margin that varies from 1.25% to 2.25% per annum according to the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the least of the total commitments, the borrowing base and the aggregate elected commitments then in effect), (ii) the adjusted LIBO rate plus a margin that varies from 2.25% to 3.25% per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies from 2.25% to 3.25% per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage.

Our new revolving credit facility requires maintenance of a ratio of total debt to EBITDAX (as each term is determined under the new revolving credit facility) of not more than 4.00 to 1.00 and maintenance of a ratio of current assets (including availability under the facility) to current liabilities of not less than 1.00 to 1.00.

Additionally, the new revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production; and prepay certain indebtedness.

Events of default under the new revolving credit facility will include, but are not be limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable cure period, default under any other material debt, change of control, bankruptcy or other insolvency event and certain material adverse effects on our business.

If we fail to perform our obligations under these and other covenants, the revolving credit commitments could be terminated and any outstanding indebtedness under the new revolving credit facility, together with accrued interest, fees and other obligations under the credit agreement, could be declared immediately due and payable.

WildHorse Revolving Credit Facility . On August 8, 2013, WildHorse entered into a revolving credit agreement (as amended on September 27, 2013, the “WildHorse revolving credit facility”) with BMO Harris Bank, N.A., as the administrative agent, Bank of America, N.A. and Wells Fargo Bank, National Association, as co-syndication agents, Comerica Bank and U.S. Bank National Association, as co-documentation agents, and certain other lenders party thereto, which provides for a revolving credit with commitments of $500.0 million (subject to the borrowing base), consisting of borrowings and letters of credit. As of September 30, 2016, the borrowing base under the WildHorse revolving credit facility was $120 million. As of September 30, 2016, we had $108.5 million outstanding under the WildHorse revolving credit facility and $0.6 million of letters of credit

outstanding, and we were able under certain circumstances to incur approximately $11.5 million of additional indebtedness under the WildHorse revolving credit facility. The WildHorse revolving credit facility matures on August 8, 2018.

In connection with the completion of this offering, we will repay and terminate the WildHorse revolving credit facility using a portion of the net proceeds of this offering.

Esquisto Revolving Credit Facility . In July 2015, in conjunction with the Comstock Acquisition, Esquisto entered into a new revolving credit facility (the “Esquisto revolving credit facility”) with a syndicate of financial institutions, led by Wells Fargo Bank, National Association The initial loan commitment is $250.0 million and it expires in July, 2020. As of December 31, 2015, the borrowing base under the Esquisto revolving credit facility was $60.0 million, Esquisto had $50.0 million in outstanding borrowings and Esquisto was in compliance with all of its debt covenants.

In June 2014, Esquisto entered into a revolving credit facility (the “Esquisto BOK revolving credit facility”) with a syndicate of financial institutions, led by Bank of Oklahoma, N.A. (“BOK”). The initial loan commitment was $50.0 million and as amended was set to expire on March 31, 2016. As of December 31, 2015, the borrowing base under the Esquisto BOK revolving credit facility was $50.0 million, Esquisto had $40.0 million in outstanding borrowings and Esquisto was in compliance with all of its debt covenants. As of June 30, 2016, Esquisto was in compliance with its debt covenants under the Esquisto revolving credit facility.

Esquisto Second Lien . In December 2014, Esquisto entered into a second lien with BOK (the “Esquisto second lien”) for $20 million that was increased to $30.0 million in May 2015, which was the balance due as of December 31, 2015. The Esquisto second lien was set to mature on June 30, 2016.

In connection with the Esquisto Merger in January 2016, the Esquisto BOK revolving credit facility and the Esquisto second lien were retired and terminated and the Esquisto revolving credit facility was increased to a borrowing base of $135.0 million, $70.0 million of which was drawn at consummation to pay off the Esquisto BOK revolving credit facility and the Esquisto second lien, bringing the outstanding balance to $120.0 million. As of September 30, 2016, the balance on the Esquisto revolving credit facility was $125.0 million and the borrowing base was $160 million.

In connection with the completion of this offering, we will repay and terminate the Esquisto revolving credit facility using a portion of the proceeds of this offering.

Esquisto Notes Payable to Members . Esquisto owed $9.6 million as of September 30, 2016 to members of Esquisto for general and administrative expenses incurred on behalf of Esquisto (the “Esquisto notes payable to members”). The Esquisto notes payable to members are payable to members by December 31, 2022. They will accrue interest at the Applicable Federal Rate (as established by the Internal Revenue Service) beginning in 2017 if not paid in full and be subordinate to all other bank debt. For further description of the Esquisto notes payable to members, see “Certain Relationships and Related Party Transactions.”

In connection with the completion of this offering, we will repay and terminate the Esquisto notes payable to members using a portion of the proceeds of this offering.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2015 for WildHorse, for Esquisto and on a combined basis is provided in the following table. The table does not reflect this offering or the use of proceeds therefrom.


	Payments Due During
	2016		2017		2018		2019		2020		Thereafter		Total
	(In thousands)
Contractual Obligations
WildHorse
Revolving credit facility(1)	$	—	$	—	$	118,000	$	—	$	—	$	—	$	118,000
Drilling services(2)		10,760		—		—		—		—		—		10,760
Office lease		1,211		1,235		1,258		1,282		1,305		548		6,839
Gas transportation service agreement(3)		4,392		4,380		4,380		768		—		—		13,920
Compressor and equipment(4)		85		—		—		—		—		—		85

WildHorse Total	$	16,448	$	5,615	$	123,638	$	2,050	$	1,305	$	548	$	149,604

Esquisto
Revolving credit facilities(1)(5)	$	40,000	$	—	$	—	$	—	$	50,000	$	—	$	90,000
Second lien(5)		30,000		—		—		—		—		—		30,000
Drilling commitments		1,127		—		—		—		—		—		1,127
Notes payable to Members(6)		—		—		—		—		—		6,438		6,438

Esquisto Total	$	71,127	$	—	$	—	$	—	$	50,000	$	6,438	$	127,565

Combined
Long-term debt(1)	$	70,000	$	—	$	118,000	$	—	$	50,000	$	6,438	$	244,438
New revolving credit facility(7)		—		—		—		—		—		—		—
Drilling services(2)		10,760		—		—		—		—		—		10,760
Office lease		1,211		1,235		1,258		1,282		1,305		548		6,839
Gas transportation service agreement(3)		4,392		4,380		4,380		768		—		—		13,920
Compressor and equipment(4)		85		—		—		—		—		—		85
Drilling commitments		1,127		—		—		—		—		—		1,127

Combined Total	$	87,575	$	5,615	$	123,638	$	2,050	$	51,305	$	6,986	$	277,169

(1)

As of September 30, 2016, we had $108.5 million outstanding under the WildHorse revolving credit facility and $0.6 million of letters of credit outstanding, and it was able under certain circumstances to incur approximately $11.5 million of additional indebtedness under its revolving credit facility. As of September 30, 2016, Esquisto had $125.0 million outstanding under its revolving credit facility and no letters of credit outstanding, and it was able to incur approximately $35.0 million of additional indebtedness under its revolving credit facility. We intend to use a portion of the net proceeds from this offering to fully repay borrowings under and retire each of the WildHorse revolving credit facility and the Esquisto revolving credit facility. Please see “Use of Proceeds.”

(2)	We terminated our rig contract in March 2016. A rig termination fee of $6.5 million was accrued as of March 31, 2016. This termination fee is being paid monthly through the end of the original lease term, December 2016.

(3)

We were assigned a firm gas transportation service agreement with Regency Intrastate Gas LLC as a result of our property acquisition on August 8, 2013. 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 until March 5, 2019.

(4)

The compressor and equipment rental agreements expire at various times with the latest expiring in June 2016. Most of these agreements contain 30-day termination clauses. Total compressor and equipment rental expense incurred in 2015, 2014 and 2013 was $1.0 million, $0.7 million and $0.1 million, respectively.

(5)

The Esquisto BOK revolving credit facility and the Esquisto second lien were retired and terminated in January 2016 with borrowings from the newly increased Esquisto revolving credit facility, moving these obligations totaling $70 million from 2016 to 2020. We intend to use a portion of the net proceeds from this offering to fully repay and retire the Esquisto revolving credit facility. Please see “Use of Proceeds.”

(6)	We intend to use a portion of the net proceeds from this offering to fully repay and retire the Esquisto notes payable to members. Please see “Use of Proceeds.”

(7)

This table does not include borrowings incurred in connection with this offering, future commitment fees, amortization of deferred financing costs, interest expense or other fees on our new revolving credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future.

During the period from January 1, 2014 through November 7, 2016, the WTI spot price for oil has declined from a high of $107.95 per Bbl on June 20, 2014 to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. The prices we receive for our oil, natural gas and NGLs production depend on numerous factors beyond our control, some of which are discussed in “Risk Factors—Risks Related to Our Business—Oil, natural gas and NGL prices are volatile. A sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

A $1.00 per barrel change in our realized oil price would have resulted in a $3.1 million change in oil revenues for 2015. A $0.15 per Mcf change in our realized natural gas price would have resulted in a $2.5 million change in our natural gas revenues for 2015. A $1.00 per barrel change in NGL prices would have changed NGL revenue by $0.6 million for 2015. Oil sales contributed 76% of our total revenues for 2015. Natural gas sales contributed 20% and NGL sales contributed 4% of our total revenues for 2015. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

Due to this volatility, we have historically used, and we expect to continue to use, commodity derivative instruments, such as collars, puts and swaps, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices. Our new revolving credit facility to contains various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price hedges exceeding a certain percentage of production.

Pro Forma Commodity Derivative Activities

Our hedging activities are intended to support oil, natural gas and NGLs prices at targeted levels and to manage our exposure to oil, natural gas and NGL price fluctuations. Under swap contracts, the counterparty is required to make a payment to us for the difference between the swap price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the swap price. We are required to make a payment to the counterparty for the difference between the swap price and the settlement price if the swap price is below the settlement price. Under a collar, we will pay the counterparty if the settlement price is above the ceiling price and the counterparty will pay us if the settlement price is below the floor price.

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of a contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with seven different counterparties. As of December 31, 2015 and September 30, 2016, no one counterparty accounted for more than 35% of the net fair market value of our derivative assets. We believe our counterparties currently are acceptable credit risks. We are not required to provide credit support or collateral to our counterparties under current contracts, nor are they required to provide credit support or collateral to us. As of September 30, 2016 and December 31, 2015 and 2014, we did not have any past due receivables from counterparties.

The following tables provide a summary of the financial derivative contracts that our predecessor and Esquisto had in place as of November 1, 2016:


Commodity / Term	Contract Type		Average Monthly Volume (MMBtu)		Weighted Average Price per Unit
Natural Gas:
November 2016—December 2016		Swaps		740,000	$	2.880
January 2017—December 2017		Swaps		630,000	$	3.100
January 2018—December 2018		Swaps		170,000	$	2.945
November 2016—December 2016		Collars		460,000	$	2.620 – $2.940
January 2017—December 2017		Collars		460,000	$	3.000 – $3.362


Commodity / Term	Contract Type		Average Monthly Volume (Bbls)		Weighted Average Price per Unit
Crude Oil:
November 2016—December 2016		Swaps		75,200	$	46.430
January 2017—December 2017		Swaps		65,950	$	49.200
January 2018—December 2018		Swaps		47,000	$	51.040
January 2019—December 2019		Swap		5,000	$	55.050
November 2016—June 2018		Collar		4,900	$	50.000 – $62.100

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our derivative contracts currently in place have investment grade ratings.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas

receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rate Risk

At September 30, 2016, we had $243.1 million of debt outstanding, including $233.5 million of revolving credit facility debt, with an assumed weighted average interest rate of 2.90%. Interest is calculated under the terms of the WildHorse revolving credit facility is based on choosing from two interest rates: (i) the Eurodollar rate, which is based on London Interbank Offered Rate (“LIBOR”), plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 1.50% to 2.50%; and (ii) the Alternate Base Rate, which is based on the highest of (a) the U.S. Prime rate, (b) the Federal Funds Effective Rate in effect plus ¹ / ₂ of 1% and (c) Adjusted LIBOR plus 1%, plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 0.50% to 1.50%. From the inception of the credit agreement, predominately all our debt outstanding has been in the form of Eurodollar borrowings based on the Eurodollar rate. Interest is calculated under the terms of the Esquisto revolving credit facility, at the option of Esquisto, based on: (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, N.A. or the weighted average of the rates on overnight federal funds transactions with members of the federal reserve system during the last preceding business day plus 0.50% plus a defined alternate base rate spread margin or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin.

Assuming no change in the amount outstanding, the pro forma impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $2.3 million per year. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness but may enter into such derivative arrangements in the future. To the extent we enter into any such interest rate derivative arrangement, we would subject to risk for financial loss. For more information, please see “Risk Factors—Risks Related to Our Business—Our derivative activities could result in financial losses or could reduce our earnings.”

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon WildHorse’s consolidated and combined financial statements, which have been prepared in accordance with GAAP. The preparation of WildHorse’s financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

A complete list of WildHorse’s significant accounting policies are described in Note 2—Summary of Significant Accounting Policies in WildHorse’s audited financial statements for the year ended December 31, 2015 included elsewhere in this prospectus.

Use of Estimates in the Preparation of Financial Statements

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) environmental remediation costs; (7) valuation of derivative instruments and (8) 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.

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

Our oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, we capitalize lease acquisition costs, all development costs and successful exploration costs.

Proved Oil and Natural Gas Properties . Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil, natural gas and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells and service wells, including unsuccessful development wells, are capitalized.

Unproved Properties . Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Costs . Exploration costs, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic surveying expenditures, other geological and geophysical costs, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

Impairment of Oil and Natural Gas Properties

Our proved oil and natural gas properties are recorded at cost. We evaluate our properties for impairment when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future operating and capital expenditures, and discount rates.

If the carrying value of the oil and natural gas properties exceeds the undiscounted cash flows, we write down the carrying amount of such properties to fair value by discounting the net cash flows associated with proved developed producing reserve volumes by 10%, by discounting the cash flows associated with proved developed non-producing reserve volumes by 15% and by discounting the cash flows associated with proved undeveloped reserve volumes by 20%. We believe this is consistent with a rate a market participant would consider in evaluating the fair value of onshore domestic proved oil and natural gas reserves.

Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and natural gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.

Key assumptions used to determine the undiscounted future cash flows include estimates of future production, new wells on production, differentials, net estimated operating costs, anticipated capital expenditures, and future commodity prices. Operating costs assumptions are based on the previous 12 months of historical costs and are not escalated thereafter. Future commodity pricing for oil and NGLs is based on publicly available annual WTI strip prices for each of the first five years after year-end and were not escalated thereafter. The average price of oil decreased 32% from an average price of $62.16/Bbl at December 31, 2014 to an average price of $42.55/Bbl at December 31, 2015. Future commodity pricing for natural gas is based on publicly available annual Henry Hub strip prices for each of the first five years after year-end and are not escalated thereafter. The average price of gas decreased 26% from an average price of $3.51/MMBtu at December 31, 2014 to an average price of $2.61/MMBtu at December 31, 2015. Price assumptions were adjusted for location and quality differentials for each property.

Lower net undiscounted cash flows can result in the carrying amount of the oil and natural gas properties exceeding the net undiscounted cash flows, which results in an impairment expense. Changes in forward commodity prices and differentials, changes in capital and operating expenses, and changes in production amongst other items can result in lower net undiscounted cash flows. Forward commodity prices can change quickly and unexpectedly as, for example, a result of global supply fluctuations or warmer than anticipated weather, which can negatively impact forward commodity prices, which could significantly lower undiscounted net cash flows.

Similarly, differentials can change quickly and unexpectedly as a result of low demand for our commodities at one of our delivery points. If our differentials were to weaken against WTI and/or Henry Hub strip prices, we would receive a reduced price for our oil, natural gas and NGLs, which would also lower our net undiscounted cash flows. Future capital and lease operating costs are uncertain and can change quickly based on regional oil and natural gas drilling activity, steel and other raw material prices, transportation costs and regulatory requirements, amongst other factors. Increased capital and lease operating costs would result in lower net undiscounted cash flows. Production estimates are determined based on field activities and future drilling plans. Drilling and field activities require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. As such, actual results may materially differ from predicted results, which could lower production and net undiscounted cash flows.

As a result of lower commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and natural gas properties for impairment. At September 30, 2016, December 31, 2015 and December 31, 2014, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and natural gas properties by $167.5 million, $147.9 million and $384.3 million, respectively, or 60%, 51% or 177%, respectively.

We evaluated and concluded that we have more than adequate capital available to us to develop all our proved undeveloped reserves. We also concluded that price was the most sensitive component of our impairment assumptions. We prepared a sensitivity analysis of our reserve volumes to determine if our proved undeveloped reserves would become uneconomic at lower prices by reducing September 30, 2016 and December 31, 2015 strip pricing for oil, natural gas and NGLs by 10%. The resulting downward revision would have been 6% and 3% of proved undeveloped reserves as of September 30, 2016 and December 31, 2015, respectively. Similarly, we prepared a sensitivity analysis to determine if we would have an additional impairment expense by reducing September 30, 2016 and December 31, 2015 strip pricing for oil, natural gas and NGLs prices by 10%. No impairment expense would have resulted for the 10% reduction in September 30, 2016 strip pricing. The increase in impairment expense as a result of the 10% reduction to December 31, 2015 strip pricing would have been $0.8 million. As a result of our sensitivity analyses and other work performed, as of such dates, we concluded that there was not a significant amount of reserve exposure.

The sensitivity analyses were as of September 30, 2016 and December 31, 2015 and, accordingly, do not consider the results of drilling and completion activity, production, changes in oil, natural gas and NGL prices, and changes in development and operating costs occurring subsequent to such dates.

As part of our year-end reserves estimation process, we expect changes in the key assumptions used, which could be significant, including updates to future production estimates to align with our anticipated five-year drilling plan and changes in our differentials, capital costs and operating expense assumptions.

Unproved property costs consist of costs to acquire undeveloped leases. We evaluate unproved properties for impairment based on remaining lease term, nearby drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.

Oil and Natural Gas Reserve Quantities

The estimates of proved natural gas, crude oil 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 (“FASB”), 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.

Proved reserves are, with respect to WildHorse, prepared by WildHorse and audited by Cawley, its independent reserve engineer, and, with respect to Esquisto, prepared by Cawley, its independent reserve engineer.

The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.


	Year Ended December 31,
	2015			2014
	MBoe Change			MBoe Change
Revisions resulting from price changes		(3,410	)		517
Revisions resulting from production and performance		(4,040	)		4,419

		(7,450	)		4,936

Depreciation, Depletion and Amortization

Our DD&A rate is dependent upon our estimates of total proved and proved developed reserves, which incorporate various assumptions and future projections. If our estimates of total proved or proved developed 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.

Derivative Instruments

We utilize commodity derivative instruments, including swaps and collars, 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 the 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.

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 is the only method permitted under FASB ASC Topic 805, Business Combinations, and involves the use of significant judgment. In connection with a business combination, the acquiring company must allocate the cost of the acquisition to assets

acquired and liabilities assumed based on fair values as of the acquisition date. 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 impact net income as accretion expense. 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 the 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 one to three

months after delivery. 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, 2015 and 2014 revenue accrual would have impacted total operating revenues by approximately $0.6 million and $0.7 million for the years ended December 31, 2015 and 2014, respectively.

Incentive Units

The governing documents of WildHorse provide for the issuance of incentive units. The incentive units are subject to performance conditions that affect their vesting. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date.

WildHorse made no special distributions in 2015 and 2014. Therefore, it recorded no compensation costs associated with its incentive plan in 2015 and 2014.

WildHorse has granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units are entitled to distributions ranging from 20% to 40% when declared, but only after cumulative distribution thresholds (payouts) have been achieved. Payouts are generally triggered after the recovery of specified members’ capital contributions plus a rate of return. We do not expect this offering to result in the achievement of these distributions thresholds and, accordingly, we do not expect to incur any compensation expense in connection herewith. In connection with the Corporate Reorganization and this offering, the incentive units will be transferred to WildHorse Investment Holdings in exchange for substantially similar incentive units in WildHorse Investment Holdings, which will be responsible for making all payments, distributions and settlements relating to the exchanged incentive units. While any such payments, distributions and settlements will not involve any cash payments by us, we will recognize non-cash compensation expense within general and administrative expenses, which may be material, in the period in which the applicable performance conditions are probable of being satisfied. We will receive a deemed capital contribution with respect to such compensation expense.

Vesting of 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).

In connection with the Corporate Reorganization and this offering, it is anticipated that WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will grant certain officers and employees awards of incentive units in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The WildHorse Holdings incentive units, Esquisto Holdings incentive units and Acquisition Co. Holdings incentive units will each vest in three equal annual installments beginning on the first anniversary of the applicable date of grant. The incentive units will be entitled to a portion of future distributions by each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings in excess of the value of our common stock held by each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings based upon the initial public offering price of such common stock in this offering plus a 5% internal rate of return. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will be responsible for making all payments, distributions and settlements to all award recipients relating to the WildHorse Holdings incentive units, Esquisto Holdings incentive units and Acquisition Co. Holdings incentive units, respectively. While any such payments, distributions and settlements are not expected to involve any cash payment by us, we expect to recognize non-cash compensation expense within general and administrative expenses, which may be material, in the period in which the applicable performance conditions are probable of being satisfied. We will receive a deemed capital contribution with respect to such compensation expense. See “Executive Compensation—Narrative Disclosures—WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings Incentive Units,” for more information.

Recently Issued Accounting Pronouncements

Leases. In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently evaluating the standard and the impact on our financial statements and related footnote disclosures.

Balance Sheet Classification of Deferred Taxes . In November 2015, the FASB issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We do not expect the impact of adopting this guidance to be material to our financial statements and related disclosures.

Simplifying the Accounting for Measurement-Period Adjustments . In September 2015, the FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item, and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. We do not expect the impact of adopting this guidance to be material to our financial statements and related disclosures.

Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that the SEC would not object to debt issuance costs related to line-of-credit arrangements being deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. WildHorse did not elect to incorporate this presentation into its financial statements and footnote disclosures as of December 31, 2015 and 2014, while Esquisto did elect to incorporate this presentation into its financial statements and footnote disclosures as of December 31, 2015 and 2014.

Revenue from Contracts with Customers . In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to us beginning on January 1, 2018. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, if any.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on our consolidated financial statements and footnote disclosures.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 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.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2015 or 2014. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

Currently, neither we nor WildHorse nor Esquisto have off-balance sheet arrangements.

100

BUSINESS

In a number of places in this Business section, certain information regarding our assets and operations is presented for our North Louisiana Acreage and our Eagle Ford Acreage. Currently, WildHorse owns all of our North Louisiana Acreage and Esquisto owns all of our Eagle Ford Acreage. Further, unless indicated otherwise or the context otherwise requires, references to our acreage, drilling locations, working interest and well counts as of September 30, 2016 are adjusted to give effect to the Acquisitions described in “Prospectus Summary—Recent Developments.” Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro F orma Results of O perations and Operating Expense— Pro Forma Adjustments” for a description of the pro forma adjustments that we made for each period presented.

Overview

We are a growth-oriented, independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in Southeast Texas and North Louisiana with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. In Southeast Texas, we operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale, which is one of the most active shale trends in North America. In North Louisiana, we operate in and around the highly prolific Terryville Complex, where we primarily target the overpressured Cotton Valley play.

We were formed by our management and technical teams and affiliates of NGP, a family of energy-focused private equity investment funds. Prior to our formation, the founding members of our management and technical teams successfully built and sold multiple NGP-sponsored oil and natural gas assets in and around the location of our acreage. Our Chief Executive Officer, Jay C. Graham, our President, Anthony Bahr, and other members of our management team, have significant experience across our acreage. Messrs. Graham and Bahr co-founded one of the predecessors to, and Mr. Graham served as Chief Executive Officer of, MRD, which pioneered the horizontal redevelopment of the Terryville Complex, participating in the drilling of MRD’s initial 55 horizontal wells. Certain members of our technical team have also been actively involved in drilling in and around our Eagle Ford Acreage since 2008.

Since we commenced operations in 2013, our management and technical teams have successfully executed our development program, growing our acreage position to approximately 375,000 net acres. We have also grown our production from 4.5 MBoe/d for the three months ended March 31, 2014 to approximately 14.0 MBoe/d for the three months ended September 30, 2016, representing a CAGR of approximately 57%, and our production for the three months ended September 30, 2016 was 17.9 MBoe/d after giving pro forma effect to the Acquisitions.

101

horizontal drilling locations, we believe additional locations may also exist in additional Cotton Valley intervals across our North Louisiana Acreage.

The following chart provides information regarding our production growth since the first quarter of 2014:

LOGO

(1)	Includes production attributable to the Comstock Assets acquired in July 2015 for all periods presented.

(2)

Our Drilling Program and Completion Techniques

Our primary objective is to deliver shareholder value through accretive growth in reserves, production and cash flow by developing and expanding our significant portfolio of drilling locations. We believe that our recent well results demonstrate that many of our wells are capable of producing attractive single-well rates of return that are competitive with many of the top performing basins in the United States. We are focused on generating shareholder value by drilling wells with high rates of returns and increasing EURs while driving drilling, completion and operating efficiencies. Our technical expertise has resulted in cost efficiency gains as well as increased hydrocarbon recovery from our wells. For example, in our Eagle Ford Acreage, due to new drilling technologies and improved procedures, on average we were able to drill twice as many wells per rig during the nine months ended September 30, 2016 as we were able to drill during 2014. Additionally, due to improvements in well completions in our Eagle Ford Acreage, we have increased EURs by approximately 29% per completed lateral foot from an average of 76 Boe per foot for our wells completed using Generation 1 hydraulic fracturing design to 98 Boe per foot for our wells completed using Generation 3 hydraulic fracturing design. With respect to our Eagle Ford Acreage, (i) Generation 1 is a hybrid gel hydraulic fracturing design that uses 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

102

Bbls per minute; (ii) Generation 2 is a slickwater fracking technique using approximately 2,600 pounds per foot of sand and 53 Bbls per foot of fluid, with 200 foot stages and seven clusters per stage at 90 Bbl per minute; and (iii) Generation 3 is a slickwater hydraulic fracturing technique that uses approximately 3,700 pounds per foot of sand and 75 Bbls per foot of fluid, with 150 foot stages and seven clusters per stage at 90 Bbls per minute. With respect to our North Louisiana Acreage, (i) Generation 1 is a slickwater fracking technique using approximately 1,450 pounds per foot of sand, with 200 foot stages and one cluster per stage at 57 Bbl per minute; and (ii) Generation 2 is a slickwater fracking technique using approximately 1,600 pounds per foot of sand, with 200 foot stages and two clusters per stage at 55 Bbl per minute.

The tables below detail certain information on EURs and production for wells we have drilled to date. Please see “—Our Drilling Program” for more detail on our wells drilled in our Eagle Ford Acreage and North Louisiana Acreage.

Eagle Ford Wells(1):


All Wells	Formation		Completion Type(2)		Lateral Length (Feet)						First Pro- duction		Days Pro- ducing		Cumu- lative Prod. (MBoe)(4)		Gross Wellhead Flow Rates After Processing (Boe/d)(4)(5)								D&C ($MM)(6)		D&C ($/Lat Foot)(6)		% EUR Liq			% EUR Oil
Well Name	Formation		Completion Type(2)		Lateral Length (Feet)		EUR (Mboe)(3)		EUR (Mboe/ 1000’)(3)		First Pro- duction		Days Pro- ducing		Cumu- lative Prod. (MBoe)(4)		0-30		0-90		91-180		181-360		D&C ($MM)(6)		D&C ($/Lat Foot)(6)		% EUR Liq			% EUR Oil
M. Malazzo 1H		Eagle Ford		Gen 1		3,297		245		74		02/16/14		958		109		483		378		191		114		16.0		4,841		91	%		78	%
Snoe 1H		Eagle Ford		Gen 1		5,782		512		88		05/10/14		875		191		949		684		333		208		14.1		2,439		90	%		74	%
Smith 1H		Eagle Ford		Gen 1		8,309		675		81		08/07/14		786		235		1,176		886		468		212		13.5		1,624		83	%		60	%
Sebesta 1H		Eagle Ford		Gen 1		7,957		554		70		11/07/14		694		192		980		786		317		229		13.1		1,646		82	%		55	%
J. Malazzo B 1H		Eagle Ford		Gen 1		7,842		576		73		12/05/14		666		188		850		633		429		245		14.0		1,785		89	%		73	%
Jrg A 1H		Eagle Ford		Gen 1		1,915		195		102		01/25/15		615		53		228		171		109		78		13.7		7,144		91	%		75	%
J. Malazzo A 1H		Eagle Ford		Gen 1		8,474		343		40		03/03/15		578		115		547		438		229		155		10.4		1,227		92	%		83	%
Fojt 1H		Eagle Ford		Gen 2		7,980		633		79		03/21/15		560		177		819		679		329		248		9.6		1,208		84	%		61	%
Mcnair B 1H		Eagle Ford		Gen 2		5,570		497		89		04/28/15		522		144		727		570		313		213		6.9		1,233		81	%		53	%
Hensz B 1H		Eagle Ford		Gen 2		6,131		771		126		05/10/15		510		205		898		743		477		329		9.5		1,546		87	%		71	%
Mcnair A 1H		Eagle Ford		Gen 2		5,693		381		67		05/21/15		499		111		549		462		253		166		8.0		1,403		82	%		57	%
Jrg B 1H		Eagle Ford		Gen 2		6,255		477		76		08/13/15		415		123		530		458		328		223		6.9		1,100		84	%		59	%
Slovacek 1H		Eagle Ford		Gen 2		6,268		477		76		08/14/15		414		116		486		426		303		225		6.5		1,029		83	%		58	%
Mackey 1H		Eagle Ford		Gen 2		5,603		359		64		09/02/15		395		94		532		401		255		166		5.9		1,051		83	%		57	%
Tietjen 1H		Eagle Ford		Gen 2		5,562		327		59		09/03/15		394		89		518		406		228		154		6.0		1,070		82	%		57	%
Flencher B 1H		Eagle Ford		Gen 2		6,974		657		94		09/25/15		372		138		666		561		366				7.4		1,067		91	%		80	%
Flencher E 1H		Eagle Ford		Gen 2		6,112		611		100		10/04/15		363		123		652		544		347				6.5		1,059		92	%		81	%
Chmelar A 1H		Eagle Ford		Gen 2		6,174		558		90		10/16/15		351		126		621		549		334				6.2		1,009		94	%		83	%
Schoppe C 1H		Eagle Ford		Gen 2		7,756		665		86		11/10/15		326		115		753		604		380				7.7		998		91	%		79	%
Rfi A 1H		Eagle Ford		Gen 2		6,637		363		55		12/06/15		300		73		387		336		219				6.8		1,029		94	%		83	%
Rfi B 1H		Eagle Ford		Gen 2		6,624		446		67		12/07/15		299		78		374		326		263				6.3		956		92	%		80	%
Fort Apache 1H		Eagle Ford		Gen 2		7,361		630		86		12/13/15		293		123		657		562		382				6.7		910		90	%		75	%
Chmelar B 1H		Eagle Ford		Gen 3		5,075		521		103		12/23/15		283		107		711		546		336				5.5		1,074		93	%		82	%
Snap H 1H		Eagle Ford		Gen 3		7,476		742		99		03/18/16		197		100		883		356		663				6.0		796		92	%		74	%
Snap G 1H		Eagle Ford		Gen 3		6,735		642		95		03/19/16		196		78		978		361		445				6.3		938		93	%		79	%
Snap B 1H		Eagle Ford		Gen 3		5,223		625		120		04/12/16		172		79		665		556						7.0		1,348		93	%		77	%
Wolbrueck 1H		Eagle Ford		Gen 3		6,878		746		108		04/26/16		158		84		680		602						6.2		900		92	%		77	%
Snap F 1H		Eagle Ford		Gen 3		6,517		593		91		06/15/16		108		55		651		528						5.7		879		94	%		80	%
Snap E 1H		Eagle Ford		Gen 3		7,872		560		71		06/15/16		108		50		619		492						6.5		824		93	%		78	%
Flencher A 2H		Eagle Ford		Gen 3		7,392		N/A		N/A		08/11/16		51		15		427
Candace 1H(7)		Eagle Ford		Gen 3		7,481		N/A		N/A		09/02/16		29		31		1,075

(1)	All wells drilled in our Eagle Ford Acreage have been located in our Burleson Main area.

(2)	For a description of the differences in completion techniques, please see “—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.”

(3)	EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report and cumulative sales from such location. EUR is shown on a combined basis for oil/condensate and gas.

(4)	Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.

103

(5)	The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.

(6)	Includes all wells drilled and completed as of September 30, 2016. D&C costs exclude land costs and title fees.

(7)	Candace 1H 0-30 production rate based on 29 days of production.


Average(1)	Well Count		Lateral Length (Feet)		EUR (Mboe)(2)		EUR Mboe/ 1000’(2)		Days Pro- ducing		Cumu- lative Prod. (MBoe)(3)		Gross Wellhead Flow Rates After Processing (Boe/ d)(3)(4)								D&C ($MM)(5)		D&C ($/Lat Foot)(5)		% EUR Liq			% EUR Oil
Completion Technique	Well Count		Lateral Length (Feet)		EUR (Mboe)(2)		EUR Mboe/ 1000’(2)		Days Pro- ducing		Cumu- lative Prod. (MBoe)(3)		0-30		0-90		91-180		181-360		D&C ($MM)(5)		D&C ($/Lat Foot)(5)		% EUR Liq			% EUR Oil
Generation 1		7		6,225		443		76		739		155		745		568		297		177		13.5		2,958		88	%		71	%
Generation 2		15		6,447		523		81		401		122		611		508		318		216		7.1		1,111		87	%		69	%
Generation 3		9		6,739		633		98		145		67		743		492		481				6.2		966		93	%		78	%

(1)

Information included in this table represents our average well results in our Eagle Ford Acreage for each of our Generation 1, Generation 2 and Generation 3 completion techniques. For a description of the differences in completion techniques, please see “—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.” All wells drilled in our Eagle Ford Acreage have been located in our Burleson Main area.

(2)	EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report as of June 30, 2016 and cumulative sales from such location as of such date. EUR is shown on a combined basis for oil/condensate and gas.

(3)	Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.

(4)	The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.

(5)	Includes all wells drilled and completed as of September 30, 2016. D&C costs exclude land costs and title fees.

North Louisiana Wells


Wells Drilled in Terryville Complex											First Pro- duction		Days Pro- ducing		Cumu- lative Prod. (Bcfe)(3)		Gross Wellhead Flow Rates (MMcfe/d)(3)(4)								D&C ($MM)(5)		D&C ($/Lat Foot)(5)		% EUR Gas
Well Name	Formation		Completion Type(1)		Lateral Length (Feet)		EUR (Bcfe)(2)		EUR (BCFE/ 1000’)(2)		First Pro- duction		Days Pro- ducing		Cumu- lative Prod. (Bcfe)(3)		0-30		0-90		91-180		181-360		D&C ($MM)(5)		D&C ($/Lat Foot)(5)		% EUR Gas
Taylor 13 12 H-1		Upper Red		Gen 1		6,796		20.4		3.0		3/6/2015		575		5.0		21.8		17.7		9.6		6.7		14.8		2,180		98	%
Pipes 14 11 HC-1		Upper Red		Gen 1		8,221		2.3		0.3		5/19/2015		501		0.9		5.4		4.0		2.1		1.2		18.3		2,220		97	%
Spillers 18 7 HC-1		Upper Red		Gen 1		8,884		16.6		1.9		7/13/2015		446		3.7		19.4		15.0		8.6		6.2		11.6		1,303		98	%
Rounsaville 21 16 HC-1		Upper Red		Gen 1		4,633		0.3		0.1		8/21/2015		407		0.4		1.5		1.3		1.1				11.3		2,443		99	%
Surline 13 12 HC-1		Lower Red		Gen 1		7,210		0.3		0.0		9/3/2015		394		0.4		1.6		1.3		1.1				12.9		1,789		98	%
Ates 18 7 HC-1		Upper Red		Gen 2		6,705		12.7		1.9		11/17/2015		319		2.5		16.0		12.4		7.2				11.2		1,677		98	%
Smelley 15 22 H-1		Upper Red		Gen 2		8,410		16.4		1.9		12/3/2015		303		2.8		17.0		13.6		7.8				12.9		1,536		97	%
Taylor 13 12 H-2		Upper Red		Gen 1		4,594		5.9		1.3		1/8/2016		267		1.1		8.6		6.2		3.3				8.3		1,814		98	%
Pruitt 16 21 HC-1		Upper Red		Gen 1		9,102		10.8		1.2		3/25/2016		190		1.3		10.4		8.6						11.9		1,304		98	%

(1)	For a description of the differences in completion techniques, please see “—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.”

(2)	EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report and cumulative sales from such location. EUR is shown on a combined basis for oil/condensate and gas.

(3)	Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.

(4)	The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.

(5)	Includes wells drilled and completed as of September 30, 2016 in the Terryville Complex. D&C costs exclude land costs and title fees.

Please see “—Our Drilling Program” for more detail on our wells drilled in our Eagle Ford Acreage and North Louisiana Acreage.


Average(1)	WellCount		Lateral Length (Feet)						Days Pro- ducing		Cumu- lative Prod. (Bcfe)(3)		Gross Wellhead Flow Rates (MMcfe/d)(3)(4)								D&C ($MM)(5)		D&C ($/Lat Foot)(5)		% EUR Gas
Completion Technique	WellCount		Lateral Length (Feet)		EUR (Bcfe)(2)		EUR BCFE/ 1000’(2)		Days Pro- ducing		Cumu- lative Prod. (Bcfe)(3)		0-30		0-90		91-180		181-360		D&C ($MM)(5)		D&C ($/Lat Foot)(5)		% EUR Gas
Generation 1		7		7,063		8.1		1.1		397		1.8		9.8		7.7		4.3		4.7		12.7		1,865		98	%
Generation 2		2		7,558		14.5		1.9		311		2.6		16.5		13.0		7.5				12.1		1,606		97	%

(1)

Information included in this table represents our average well results for wells drilled to date in the Terryville Complex in North Louisiana for each of our Generation 1 and Generation 2 completion techniques. For a description of the differences in completion techniques, please see “—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.”

(2)	EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report as of June 30, 2016 and cumulative sales from such location as of such date. EUR is shown on a combined basis for oil/condensate and gas.

(3)	Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.

(4)	The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.

(5)	Includes wells drilled and completed in the Terryville Complex as of September 30, 2016. D&C costs exclude land costs and title fees.

104

Our Acreage and Drilling Locations

The table below provides a summary of our net acreage, average working interest, average net revenue interest and horizontal drilling locations as of September 30, 2016:


	Acreage								Horizontal Drilling Locations(3)(4)
	Net Acreage		Average WI %(1)			Average NRI %(2)			Gross		Net
Eagle Ford		266,501		82	%		64	%		2,977		1,650
North Louisiana(5)		108,437		74	%		57	%		1,414		648

Total		374,938		79	%		62	%		4,391		2,298

(1)	Represents our weighted average working interest across our acreage position.

(2)	Represents our weighted average net revenue interest across our acreage position.

(3)

Please see “—Our Properties—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see “Risk Factors—Risks Related to Our Business—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.”

(4)

(5)	Includes acreage we have the right to lease pursuant to an oil and gas lease option agreement with affiliates of Weyerhaeuser Company. See “—Reserve Data—Acreage.”

105


	Net Horizontal Drilling Locations										Gross Horizontal Drilling Locations
	Proved		Probable		Possible		Management		Total		Total
Eagle Ford:
Burleson Main		103		165		295		68		631		1,331
Burleson North		—		—		—		670		670		670
Burleson West		6		23		26		5		60		225
Burleson South		2		4		16		38		59		292
Washington County		2		7		4		—		12		36
Lee County		6		12		120		81		218		423

Total Eagle Ford		117		211		461		862		1,650		2,977


North Louisiana:
RCT
Upper Red		7		15		108		31		161		308
Lower Red		—		—		72		94		166		319
Upper Deep Pink		—		—		45		122		167		320
Weyerhaeuser
Upper Red		—		—		36		27		64		205
Lower Red		—		—		36		27		64		205
Bear Creek		—		—		26		2		28		57

Total North Louisiana		7		15		323		303		648		1,414

106

Our Reserve Information

We believe we have substantial reserves. The following table summarizes the estimated net proved, probable and possible oil, natural gas and NGL reserves of WildHorse and Esquisto on a combined basis as of June 30, 2016 without giving effect to any of the Acquisitions. Cawley prepared Esquisto’s reserves estimates and audited WildHorse’s reserves estimates.


	Estimated Total Proved Reserves
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)		% Liquids			% Developed
Eagle Ford		49,003		26,518		7,269		60,692		93	%		21	%
North Louisiana		703		274,246		306		46,717		2	%		49	%

Total		49,706		300,764		7,575		107,409		53	%		33	%


	Estimated Total Probable Reserves
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)		% Liquids
Eagle Ford		60,675		26,758		7,439		72,574		94	%
North Louisiana		612		164,640		—		28,052		2	%

Total		61,287		191,398		7,439		100,626		68	%


	Estimated Total Possible Reserves
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)		% Liquids
Eagle Ford		105,989		46,761		12,887		126,669		94	%
North Louisiana		3,953		1,063,042		—		181,127		2	%

Total		109,942		1,109,803		12,887		307,796		40	%

Business Strategies

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

•

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

107

•

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.

108

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.

109

In addition, 52% and 48% of our production for the nine months ended September 30, 2016 on a pro forma basis was comprised of liquids and natural gas, respectively. As changes in the commodity price environment occur, we intend to adapt and manage our capital spending and production profile to benefit from these trends.

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 and North Louisiana. 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, 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, as shown below in “Prospectus Summary — Corporate Reorganization.” 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.

110

Our Properties

The map below depicts the location of our properties as of September 30, 2016, which include working interests in approximately 472,000 gross (375,000 net) surface acres, substantially all of which are located in Southeast Texas and North Louisiana.

LOGO

Note: Acreage position reflects all sections in which we own an interest and the assets acquired or to be acquired in the Acquisitions.

Eagle Ford Acreage

The 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 the second 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 is Cretaceous in age resting between the Austin Chalk and the Buda Lime at a depth of approximately 4,000 to 14,000 feet. As of September 20, 2016, there were approximately 34,100 producing wells in the Eagle Ford with total production of 2.1 MMBoe/d in August 2016.

We currently target a portion of the Eagle Ford Shale at depths between 7,000 feet and 12,200 feet in Burleson, Lee and Washington Counties, Texas. This portion of the Eagle Ford Shale averages 125 feet in thickness and contains 70% carbonate. We believe that the elevated carbonate percentages are in large part responsible for the brittleness of the Eagle Ford and successful completions which exhibit high productivity when fractured. The overall clay content of the Eagle Ford increases regionally as it continues northeast into Brazos, Grimes and Madison counties. Offset operators include Anadarko Petroleum Corporation, Apache Corporation, Clayton Williams Energy Inc., EnerVest, Ltd. and Halcon Resources Corporation and account for approximately 400 Eagle Ford wells drilled since 2013 near or adjacent to our acreage.

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

111

Trend have experienced drilling and production success in these four horizons 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 in these four intervals throughout our leasehold.

We entered the Eagle Ford through a grassroots leasing effort in Burleson County, 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 divide our Burleson County acreage into sub-regions, which we refer to as Burleson Main, Burleson North, Burleson West and Burleson South, based on our assessment of depth and reservoir characteristics, such as gas to oil ratio, pressure and clay content. All of our drilling activity has historically been focused in our Burleson Main area. We have identified a substantial inventory of 2,977 gross drilling locations within our Eagle Ford Acreage, consisting of 2,518 gross drilling locations in Burleson County, Texas, 423 gross drilling locations in Lee County, Texas, and 36 gross drilling locations in Washington County, Texas. 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.

As of September 30, 2016, our Eagle Ford position included approximately 267,000 net acres. Also, as of September 30, 2016, approximately 46% of our Eagle Ford Acreage was then held by production, with an average working interest of 82%, and, as of June 30, 2016, 21% of our 61 MMBoe of proved reserves were developed, 93% of which were liquids. To date, we have drilled and completed 33 wells, acquired 388 wells, including the wells acquired in the Burleson North Acquisition, and participated in 25 wells resulting in total net production of approximately 10.6 MBoe/d (75% oil, 13% natural gas and 12% NGLs), including non-operated production. In 2016, we expect to dedicate $117.3 million to developing our Eagle Ford Acreage.

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. Over 23,000 vertical and horizontal wells have been completed throughout the trend. In 2005, operators started redeveloping the Cotton Valley using horizontal drilling and advanced hydraulic fracturing techniques. Through September 30, 2016, operators have drilled over 1,100 horizontal Cotton Valley wells. Some large, analogous redevelopment projects in the Terryville Complex include the Terryville play in Lincoln Parish, where over 110 horizontal wells have been drilled by Memorial Resource Development Corporation, the Nan-Su-Gail area in Freestone County, East Texas, where over 40 horizontal wells have been drilled by operators such as Devon Energy Corporation and Marathon Oil Corporation, and the Carthage Complex in Panola County, East Texas, where operators such as ExxonMobil Corporation, BP America, Memorial Production Partners LP and Anadarko Petroleum Corporation have drilled over 153 horizontal wells.

Our North Louisiana Acreage spans across the Webster, Claiborne, Bienville, Lincoln, Jackson and Ouachita Parishes, focusing on the Bear Creek and Athens fields 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. Our drilling activity is expected to focus on producing natural gas from the overpressured Cotton Valley formation in the Terryville Complex where we intend to target the Upper and Lower Red and Upper Deep Pink intervals.

As of September 30, 2016, our North Louisiana Acreage included approximately 108,000 net acres. Also, as of September 30, 2016, 46% of our acreage was then held by production, with an average working interest of 74%, and 49% of our 47 MMBoe of proved reserves were developed, 98% of which were natural gas. As of September 30,

112

2016, we had drilled and completed 13 wells, acquired 605 wells and participated in two wells resulting a total net production of approximately 8.1 MBoe/d (3% oil, 95% natural gas and 2% NGLs), including non-operated production. In 2016, we expect to dedicate $20.2 million to developing the North Louisiana Acreage.

Production Status

For the nine months ended September 30, 2016, our pro forma average net daily production was 18.7 MBoe/d (approximately 44% oil, 48% natural gas and 8% NGLs). During 2015, our pro forma average net daily production was 17.7 MBoe/d (approximately 48% oil and 43% natural gas and 9% NGLs). On a pro forma basis, as of September 30, 2016, we produced from 427 horizontal and 458 vertical wells, in each case, operated and non-operated.

Determination of Identified Drilling Locations

As of September 30, 2016, we identified 2,977 gross (1,650 net) and 1,414 gross (648 net) horizontal drilling locations on our Eagle Ford Acreage and our North Louisiana Acreage, respectively. In Burleson County, Texas, we identified 2,518 gross (1,420 net) locations based on an average completed lateral length of 6,600 feet with well spacing of 500 feet; in Lee County, Texas, we identified 423 gross (218 net) locations based on an average completed lateral length of 6,600 feet with well spacing of 1,000 feet; and in Washington County, Texas, we identified 36 gross (12 net) locations based on an average completed lateral length of 6,600 feet with well spacing of 1,500 feet. Further, in the RCT Area, we identified 947 gross (493 net) locations based on an average completed lateral length of 7,207 feet with well spacing of 1,000 feet; in the Weyerhaeuser Area, we identified 410 gross (127 net) locations based on an average completed lateral length of 7,500 feet with well spacing of 1,000 feet; and in our other North Louisiana Acreage, we identified 57 gross (28 net) locations based on an average completed lateral length of 7,000 feet with well spacing of 1,000 feet.

We define identified gross drilling locations as locations on operated and non-operated leasehold specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators across our acreage, combined with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of vertical wells that have penetrated our horizontal zones. In addition, to evaluate the prospectivity of our horizontal acreage, we have performed open-hole and mud log evaluations, core analysis and drill cuttings analysis. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant, such as easement restrictions and state and local regulations, are considered in determining such locations. The drilling locations for which we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors.

Reserve Data

The information with respect to our estimated reserves presented below has been prepared in accordance with the rules and regulations of the SEC.

Reserves Presentation

The estimated proved reserves of WildHorse, Esquisto and both companies on a combined basis as of December 31, 2015 and the estimated proved, probable and possible reserves of WildHorse, Esquisto and both companies on a combined basis as of June 30, 2016 presented below are based on evaluations, with respect to WildHorse, prepared by WildHorse and audited by Cawley, its independent reserve engineer, and, with respect to Esquisto, prepared by Cawley, its independent reserve engineer. Cawley has not prepared or audited any estimates of WildHorse’s probable or possible reserves as of any date prior to June 30, 2016. Accordingly, we have not presented our combined probable or possible reserves as of any date prior to June 30, 2016. Copies of the summary reports of our reserve engineers with respect to WildHorse’s and Esquisto’s reserves as of December 31, 2015 and June 30, 2016 are filed as exhibits to the registration statement of which this prospectus forms a part. Please see “—Preparation of Reserve Estimates” for definitions of proved reserves and the technologies and economic data used in their estimation.

113

The following table summarizes the estimated proved reserves of WildHorse, Esquisto and both companies on a combined basis at December 31, 2015 and the estimated proved, probable and possible reserves of WildHorse, Esquisto and both companies on a combined basis at June 30, 2016 based on SEC pricing without giving effect to any of the Acquisitions.


	At December 31, 2015(1)									At June 30, 2016(2)
	WildHorse			Esquisto			Combined			WildHorse			Esquisto			Combined
Estimated Proved Reserves:
Oil (MMBbls)		0.9			35.7			36.6			0.7			49.0			49.7
Natural gas (Bcf)		311.1			33.8			345.0			274.2			26.5			300.8
NGLs (MMBbls)		0.4			8.5			8.9			0.3			7.3			7.6

Total proved reserves (MMBoe)		53.2			49.9			103.0			46.7			60.7			107.4

Estimated Proved Developed Reserves:
Oil (MMBbls)		0.4			7.1			7.5			0.4			9.0			9.3
Natural gas (Bcf)		134.2			8.8			143.0			133.2			8.9			142.0
NGLs (MMBbls)		0.4			1.9			2.2			0.3			2.3			2.6

Total proved developed reserves (MMBoe)		23.2			10.4			33.6			22.9			12.7			35.6

Proved developed reserves as a percentage of total proved reserves		43.6	%		20.8	%		32.6	%		48.9	%		21.0	%		33.1	%

Estimated Proved Undeveloped Reserves:
Oil (MMBbls)		0.5			28.7			29.1			0.3			40.0			40.4
Natural gas (Bcf)		177.0			25.0			202.0			141.1			17.7			158.7
NGLs (MMBbls)		—			6.7			6.7			—			5.0			5.0

Total proved undeveloped reserves (MMBoe)		30.0			39.5			69.5			23.9			48.0			71.8

Proved undeveloped reserves as a percentage of total proved reserves		56.4	%		79.2	%		67.4	%		51.1	%		79.0	%		66.9	%

Estimated Probable Reserves:
Oil (MMBbls)											0.6			60.7			61.3
Natural gas (Bcf)											164.6			26.8			191.4
NGLs (MMBbls)											—			7.4			7.4

Total probable reserves (MMBoe)(3)											28.1			72.6			100.6

Estimated Possible Reserves:
Oil (MMBbls)											4.0			106.0			109.9
Natural gas (Bcf)											1,063.0			46.8			1,109.8
NGLs (MMBbls)											—			12.9			12.9

Total possible reserves (MMBoe)(3)											181.1			126.7			307.8

114

(1)

The estimated net proved reserves of WildHorse, Esquisto and both companies on a combined basis as of December 31, 2015 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 $50.28 per barrel as of December 31, 2015 was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.59 per MMBtu as of December 31, 2015 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 the WildHorse properties are $47.81 per barrel of oil, $14.79 per barrel of NGL and $2.70 per Mcf of natural gas as of December 31, 2015. The average adjusted product prices weighted by production over the remaining lives of the Esquisto properties are $49.78 per barrel of oil, $11.82 per barrel of NGL and $2.40 per Mcf of natural gas as of December 31, 2015.

(2)

The estimated net proved, probable and possible reserves of WildHorse, Esquisto and both companies on a combined basis as of June 30, 2016 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 $43.12 per barrel as of June 30, 2016 was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.24 per MMBtu as of June 30, 2016 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 the WildHorse properties are $39.78 per barrel of oil, $2.32 per Mcf of natural gas and $12.37 per barrel of NGL as of June 30, 2016. The average adjusted product prices weighted by production over the remaining lives of the Esquisto properties are $40.46 per barrel of oil, $1.35 per Mcf of natural gas and $10.35 per barrel of NGL as of June 30, 2016.

(3)	All of our estimated probable and possible reserves are classified as undeveloped.

Proved Undeveloped Reserves

The following table summarizes the changes in the estimated proved undeveloped reserves of WildHorse and Esquisto on a combined basis during 2015 and the six months ended June 30, 2016 (in MMBoe):


Proved undeveloped reserves at December 31, 2014	29.3
Conversions into proved developed reserves	(8.2	)
Extensions and discoveries	51.9
Acquisitions	—
Revisions	(3.6	)

Proved undeveloped reserves at December 31, 2015	69.5

Conversions into proved developed reserves	(1.0)
Extensions and discoveries	13.6
Acquisitions	—
Revisions	(10.3)

Proved undeveloped reserves at June 30, 2016	71.8

During the year ended December 31, 2015, we incurred costs of approximately $49.7 million to convert 8.2 MMBoe of proved undeveloped reserves to proved developed reserves.

During the year ended December 31, 2015, extensions were comprised of 12.4 MMBoe and 39.5 MMBoe from our North Louisiana and Eagle Ford Acreage, respectively. The increase was the result of drilling successful wells and booking PUD offsets to such wells.

During the year ended December 31, 2015, revisions were attributable to a decrease in commodity prices. This reduction in commodity prices decreased our proved undeveloped reserves by 1.9 MMBoe due to wells having a shorter economic life and further reduced our proved undeveloped reserves by an additional 1.7 MMBoe due to certain wells being uneconomic.

115

During the six months ended June 30, 2016, we incurred costs of approximately $8.5 million to convert 1.0 MMBoe of proved undeveloped reserves to proved developed reserves.

During the six months ended June 30, 2016, extensions were comprised of 6.5 MMBoe and 7.1 MMBoe from our North Louisiana and Eagle Ford Acreage, respectively. The increase was the result of drilling successful wells and booking PUD offsets to such wells.

During the six months ended June 30, 2016, revisions consisted of a decrease of 7.4 MMBoe due to lower commodity prices making certain wells uneconomic and a decrease of 4.7 MMBoe due to removing reserves associated with interests that are in dispute, both partially offset by a 1.8 MMBoe increase in reserves due to improved performance.

As of December 31, 2015 and June 30, 2016, we had no proved undeveloped reserves that had remained undeveloped for more than five years since initial booking.

Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2015 and June 30, 2016 are approximately $713.7 million and $675.0 million, respectively, over the next five years, which we expect to finance through cash flow from operations, borrowings under our new revolving credit facility and other sources of capital. All of our proved undeveloped reserves are expected to be developed within five years of initial booking. Please see “Risk Factors—Risks Related to Our Business—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.”

Preparation of Reserve Estimates

WildHorse’s reserve estimates as of December 31, 2015 and June 30, 2016 included in this prospectus are based on evaluations prepared by WildHorse’s management and audited by the independent petroleum engineering firm of Cawley, and Esquisto’s reserve estimates as of December 31, 2015 and June 30, 2016 included in this prospectus are based on evaluations prepared by the independent petroleum engineering firm of Cawley, each 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 expires, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probalistic methods are used for estimation. 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 probalistic 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 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). We have one proved undeveloped location, to which we have attributed 10.6 Bcf of estimated natural gas proved reserves, that is more than one offset from a proved developed well. We utilized reliable technologies, including log data, performance data, log cross sections, seismic data, core data and statistical analysis, to confirm the reserves associated with this location with reasonable certainty.

116

Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil, natural gas and NGLs that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserve where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir. Possible reserves also include incremental quantities associated with a greater percentage of recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and we believe that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

Internal Controls

Our internal staff of petroleum engineers and geoscience professionals works closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve auditing process. Periodically, our technical team meets with the 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,

117

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 “Risk Factors” appearing elsewhere in this prospectus.

For all of WildHorse’s properties, WildHorse’s internally prepared reserve estimates and related reports are reviewed and approved by WildHorse’s Vice President—Exploitation, Steve Eckerman. Mr. Eckerman has been with WildHorse since May 2010. Mr. Eckerman has approximately 23 years of experience in oil and gas operations, reservoir engineering, reserve management, unconventional reservoir characterization, strategic planning and finance.

Cawley performed audits of the internally prepared reserves estimates on the entirety of WildHorse’s reported proved reserve quantities on a Boe basis as of December 31, 2015 and proved, probable and possible reserves as of June 30, 2016. The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserves estimates. WildHorse’s proved reserves are, in the aggregate, reasonable and within the established audit tolerance guidelines of 10%. The reports of Cawley contain further discussion of the reserves estimates and its audit procedure.

For all of Esquisto’s properties, Esquisto’s internally and externally prepared reserve estimates and related reports are reviewed and approved by Esquisto’s Vice President—Engineering, Jason Pearce. Mr. Pearce has been with Esquisto since its inception on June 20, 2014. Mr. Pearce has approximately 18 years of experience in oil and gas operations, reservoir engineering, reserve management, unconventional reservoir characterization and strategic planning. The proved reserve estimates of Esquisto shown herein at December 31, 2015 and proved, probable and possible reserves as of June 30, 2016 have been independently prepared by Cawley.

Cawley was founded 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 WildHorse and Esquisto, was Robert D. Ravnaas. Mr. Ravnaas has been practicing consulting petroleum engineering at Cawley, Gillespie & Associates, Inc. since 1983. Mr. Ravnaas is a Registered Professional Engineer in the State of Texas (License No. 61304) and has over 35 years of practical experience in petroleum engineering, with over approximately 33 years of experience in the estimation and evaluation of reserves. Mr. Ravnaas received a B.S. with special honors in Chemical Engineering from the University of Colorado at Boulder, and a M.S. in Petroleum Engineering from the University of Texas at Austin. Mr. Ravnaas meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; Mr. Ravnaas is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

118

Production, Realized Prices and Production Costs

The following table sets forth production, realized prices and productions costs as follows:

•

WildHorse for the years ended December 31, 2014 and 2015 and the nine months ended September 30, 2016;

•

Esquisto for the years ended December 31, 2014 and 2015 and the nine months ended September 30, 2016;

•

Burleson North Assets for the year ended December 31, 2015 and the nine months ended September 30, 2016; and

•

us on a pro forma basis (i) without giving effect to the Burleson North Assets for the year ended December 31, 2014 and (ii) after giving effect to the Burleson North Assets for the year ended December 31, 2015 and the nine months ended September 30, 2016.

For additional information on price calculations, please see the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31,				Nine Months Ended September 30, 2016
	2015		2014		Nine Months Ended September 30, 2016
WildHorse:
Production data:
Oil (MBbls)		73.1		30.7		65.5
Natural gas (MMcf)		13,636.8		9,388.2		12,592.4
NGLs (MBbls)		103.3		41.4		49.1
Total production (MBoe)		2,449.2		1,636.8		2,213.3
Average daily production (MBoe/d)		6.7		4.5		8.1
Average sales prices:
Oil (per Bbl)	$	45.20	$	90.59	$	45.39
Natural gas (per Mcf)	$	2.24	$	4.02	$	2.01
NGLs (per Bbl)	$	14.05	$	23.90	$	13.42
Average sales prices before effects of settled derivatives (per MBoe)(1)	$	14.42	$	25.36	$	13.06
Average sales prices after effects of settled derivatives (per MBoe)(1)	$	18.94	$	23.70	$	14.80
Average costs per Boe:
Lease operating expenses	$	3.51	$	5.76	$	2.05
Gathering system operating expenses	$	0.37		—	$	0.04
Production and ad valorem taxes	$	1.09	$	1.58	$	0.83
Cost of oil sales		—	$	0.42		—
Depreciation, depletion and amortization	$	10.42	$	9.35	$	12.34
Impairment	$	3.80	$	15.10		—
General and administrative expenses	$	4.31	$	3.57	$	3.79
Exploration expenses	$	6.08	$	0.98	$	4.05
Esquisto(2):
Production data:
Oil (MBbls)		1,260.8		176.3		1,259.5
Natural gas (MMcf)		1,705.9		163.5		1,278.9
NGLs (MBbls)		355.8		48.0		286.9
Total production (MBoe)		1,900.9		251.6		1,759.5
Average daily production (MBoe/d)		5.2		0.7		6.4
Average sales prices:
Oil (per Bbl)	$	46.15	$	85.35	$	38.70
Natural gas (per Mcf)	$	2.42	$	3.69	$	1.94
NGLs (per Bbl)	$	11.41	$	26.97	$	10.32
Average sales prices before effects of settled derivatives (per Boe)(1)	$	34.92	$	67.36	$	30.79
Average sales prices after effects of settled derivatives (per Boe)(1)	$	35.38	$	67.36	$	31.80

119


	Year Ended December 31,				Nine Months Ended September 30, 2016
	2015		2014		Nine Months Ended September 30, 2016
Average costs per Boe:
Lease operating expenses	$	3.64	$	4.42	$	2.48
Gathering system operating expenses		—		—		—
Production and ad valorem taxes	$	2.03	$	3.26	$	1.82
Cost of oil sales		—		—		—
Depreciation, depletion and amortization	$	20.20	$	31.69	$	18.87
Impairment		—		—		—
General and administrative expenses	$	3.18	$	9.49	$	3.22
Exploration expenses	$	1.56	$	0.01		—
Burleson North Assets :
Production data:
Oil (MBbls)		1,767.0				922.0
Natural gas (MMcf)		1,424.0				895.0
NGLs (MBbls)		105.0				71.0
Total production (MBoe)		2,109.3				1,142.2
Average daily production (MBoe/d)		5.8				4.2
Average sales prices:
Oil (per Bbl)	$	45.91			$	37.50
Natural gas (per Mcf)	$	2.37			$	2.02
NGLs (per Bbl)	$	11.52			$	11.41
Average sales prices before effects of settled derivatives (per Boe)(1)	$	40.63			$	32.56
Average sales prices after effects of settled derivatives (per Boe)(1)	$	40.63			$	32.56
Average costs per Boe:
Lease operating expenses	$	9.39			$	11.35
Gathering system operating expenses		—				—
Production and ad valorem taxes	$	3.06			$	3.10
Cost of oil sales		—				—
Depreciation, depletion and amortization	$	16.63			$	16.65
Impairment		—				—
General and administrative expenses		—				—
Exploration expenses		—				—

Pro Forma:
Production data:
Oil (MBbls)		3,100.9		207.0		2,246.9
Natural gas (MMcf)		16,766.7		9,551.7		14,766.3
NGLs (MBbls)		564.1		89.4		407.0

Total production (MBoe)		6,459.5		1,888.4		5,114.9

Average daily production (MBoe/d)		17.7		5.2		18.7
Average sales prices:
Oil (per Bbl)	$	45.99	$	86.13	$	38.40
Natural gas (per Mcf)	$	2.27	$	4.01	$	2.00
NGLs (per Bbl)	$	11.92	$	25.55	$	10.88

Average sales prices before effects of settled derivatives (per Boe)(1)	$	29.01	$	30.96	$	23.51
Average sales prices after effects of settled derivatives (per Boe)(1)	$	30.86	$	29.52	$	24.62
Average costs per Boe:
Lease operating expenses	$	5.47	$	5.58	$	4.27
Gathering system operating expenses	$	0.14		—	$	0.02
Production and ad valorem taxes	$	2.01	$	1.80	$	1.68
Cost of oil sales		—	$	0.36		—
Depreciation, depletion and amortization	$	15.33	$	12.32	$	15.55
Impairment	$	1.44	$	13.09		—
General and administrative expenses	$	2.57	$	4.36	$	2.75
Exploration expenses	$	2.77	$	0.85	$	1.75

(1)	Average sales prices shown reflect both the before and after effects of our settled derivatives. Our calculation of such effects includes realized gains or losses on settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate them as hedges.

(2)	Includes results attributable to the Comstock Assets beginning on January 1, 2015.

120

The following tables set forth information on a field-level regarding our production, realized prices and production costs for the years ended December 31, 2015 and 2014 and the nine months ended September 30, 2016.


	Year Ended December 31, 2014
	Bear Creek		RCT		Other		Total
Production data:
Oil (MBbls)		25.3		1.3		4.1		30.7
Natural Gas (MMcf)		7,560.2		98.9		1,729.1		9,388.2
NGLs (MBbls)		1.3		2.6		37.5		41.4

Total Production (MBoe)		1,286.6		20.4		329.8		1,636.8

Average daily production (MBoe/d)		3.5		0.1		0.9		4.5
Average sales prices:
Oil (per Bbl)	$	93.99	$	77.23	$	73.56	$	90.59
Natural gas (per Mcf)	$	4.04	$	3.72	$	3.94	$	4.02
NGLs (per Bbl)	$	0.92	$	22.92	$	24.75	$	23.90

Average sales price before effects of settled derivatives (per MBoe)(1)	$	25.60	$	25.92	$	24.38	$	25.36
Average sales price after effects of settled derivatives (per MBoe)(1)	$	23.90	$	24.50	$	22.87	$	23.70
Average costs per Boe:
Lease operating expenses	$	5.22	$	5.44	$	7.90	$	5.76
Gathering system operating expenses		—		—		—		—
Production and ad valorem taxes	$	1.65	$	1.50	$	1.32	$	1.58
Cost of oil sales	$	0.49		—	$	0.15	$	0.42
Depreciation, depletion and amortization	$	7.32	$	26.09	$	16.19	$	9.35
Impairment		—		—	$	74.96	$	15.10
General and administrative expenses	$	2.32	$	33.91	$	6.56	$	3.57
Exploration expenses		—	$	78.35		—	$	0.98

(1)	Average sales prices shown reflect both the before and after effects of our settled derivatives. Our calculation of such effects includes realized gains or losses on settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate them as hedges.

121


	Year Ended December 31, 2015
	Bear Creek		RCT		Other		Total
Production data:
Oil (MBbls)		20.6		20.3		32.2		73.1
Natural Gas (MMcf)		6,899.0		4,169.0		2,568.8		13,636.8
NGLs (MBbls)		1.0		19.5		82.8		103.3

Total Production (MBoe)		1,171.4		734.6		543.1		2,449.2

Average daily production (MBoe/d)		3.2		2.0		1.5		6.7
Average sales prices:
Oil (per Bbl)	$	46.50	$	43.68	$	45.36	$	45.20
Natural gas (per Mcf)	$	2.25	$	2.11	$	2.43	$	2.24
NGLs (per Bbl)	$	0.50	$	15.53	$	13.86	$	14.05

Average sales price before effects of settled derivatives (per MBoe)(1)	$	14.07	$	13.57	$	16.32	$	14.42
Average sales price after effects of settled derivatives (per MBoe)(1)	$	18.83	$	18.18	$	20.23	$	18.94
Average costs per Boe:
Lease operating expenses	$	4.14	$	1.32	$	5.11	$	3.51
Gathering system operating expenses		—	$	1.24		—	$	0.37
Production and ad valorem taxes	$	1.67	$	0.26	$	0.96	$	1.09
Cost of oil sales		—		—		—		—
Depreciation, depletion and amortization	$	7.73	$	15.74	$	9.05	$	10.42
Impairment		—		—	$	17.15	$	3.80
General and administrative expenses	$	3.35	$	7.19	$	2.52	$	4.31
Exploration expenses		—	$	8.91	$	15.38	$	6.08

(1)	Average sales prices shown reflect both the before and after effects of our settled derivatives. Our calculation of such effects includes realized gains or losses on settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate them as hedges.


	Nine Months Ended September 30, 2016
	Bear Creek		RCT		Other		Total
Production data:
Oil (MBbls)		13.1		27.8		24.6		65.5
Natural Gas (MMcf)		4,421.5		6,090.7		2,080.2		12,592.4
NGLs (MBbls)		0.9		17.1		31.1		49.1

Total Production (MBoe)		750.9		1,060.0		402.4		2,213.3

Average daily production (MBoe/d)		2.7		3.9		1.5		8.1
Average sales prices:
Oil (per Bbl)	$	37.25	$	36.87	$	59.27	$	45.39
Natural gas (per Mcf)	$	1.78	$	1.93	$	2.72	$	2.01
NGLs (per Bbl)	$	0.35	$	16.14	$	12.27	$	13.42

Average sales price before effects of settled derivatives (per MBoe)(1)	$	11.13	$	12.31	$	18.62	$	13.06
Average sales price after effects of settled derivatives (per MBoe)(1)	$	12.94	$	14.07	$	20.20	$	14.80
Average costs per Boe:
Lease operating expenses	$	3.27	$	1.20	$	2.03	$	2.05
Gathering system operating expenses		—	$	0.09		—	$	0.04
Production and ad valorem taxes	$	1.75	$	0.02	$	1.26	$	0.83
Depreciation, depletion and amortization	$	9.08	$	16.35	$	7.83	$	12.34
General and administrative expenses	$	4.04	$	4.08	$	2.58	$	3.79
Exploration expenses		—	$	8.46		—	$	4.05

(1)	Average sales prices shown reflect both the before and after effects of our settled derivatives. Our calculation of such effects includes realized gains or losses on settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate them as hedges.

122

Productive Wells

The following table sets forth information regarding productive wells as of December 31, 2015 and September 30, 2016:


	As of December 31, 2015							As of September 30, 2016
	Productive Wells				Average Working Interest			Productive Wells				Average Working Interest
	Gross		Net		Average Working Interest			Gross		Net		Average Working Interest
Eagle Ford Acreage
Oil		393		329		84	%		407		339		83	%
Natural gas		37		29		78	%		40		31		77	%

Total		430		358		83	%		447		370		83	%

North Louisiana Acreage
Oil		—		—		—			—		—		—
Natural gas		526		330		63	%		526		330		63	%

Total		526		330		63	%		526		330		63	%

Combined total		956		688		72	%		973		700		72	%

Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of September 30, 2016. Approximately 46% of our net Eagle Ford Acreage and 46% of our net North Louisiana Acreage was held by production at September 30, 2016.


	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Eagle Ford Acreage		12,098		10,049		313,915		256,451		326,012		266,500
North Louisiana Acreage		64,757		38,563		80,885		69,874		145,642		108,437

Total		76,855		48,612		394,800		326,325		471,654		374,938

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.

123

Undeveloped Acreage Expirations

The following table sets forth the number of total net undeveloped acres as of September 30, 2016 across our Eagle Ford and North Louisiana Acreage that will expire in 2016, 2017, 2018, 2019 and 2020, after giving effect to the Rosewood Acquisition, 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.


	2016		2017		2018		2019		2020+
Eagle Ford Acreage:
Gross		5,562		32,301		36,893		18,135	3,635
Net		2,824		22,773		24,420		12,203	3,534
North Louisiana Acreage:
Gross		13,107		35,166		13,854		2,105	1,472
Net		13,083		31,443		11,325		1,797	1,203

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 25,597 net acres expiring in 2016 and 2017 across our Eagle Ford Acreage, we have the option to extend or renew the leases covering 5,932 net acres, and we have budgeted approximately $12.0 million in 2016 and $11.3 million in 2017 to execute extensions and renewals. With respect to the remaining 19,664 net acres for which we do not have an option to extend or renew in the Eagle Ford, 3,381 net acres are associated 25 gross (10.7 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 19,664 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 44,526 net acres expiring in 2016 and 2017 across our North Louisiana Acreage, we have the option to extend 22,762 of the 26,643 net acres in the RCT and Weyerhaeuser Areas, and we have budgeted approximately $2.3 million in 2016 and $10.3 million in 2017 to execute such extensions and renewals. In October 2016, we executed a second amendment to an option for an oil and gas lease agreement with affiliates of Weyerhaeuser Company to extend our option to lease approximately 12,848 net acres to October 2017, which we refer to in this prospectus as our “Weyerhaeuser Area.” Upon notice and payment of the applicable lease bonus payment, we can enter into a three-year lease covering all such acreage. With respect to the remaining 3,881 net acres for which we do not have an option to extend or renew, we have not assigned any proved undeveloped reserves to such locations, although we intend to retain substantially all such acreage by negotiating lease extensions or renewals or drilling wells. We also have 17,883 net acres in our North Louisiana Acreage expiring in 2016 and 2017 in our Other area. We plan to extend or renew approximately 1,100 net acres for an estimated cost of approximately $0.7 million and intend to let the remainder of this acreage expire. Accordingly, we have not assigned any drilling locations to such acreage. Please see “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 of the leases are renewed.”

124

Drilling Activity

The following describes the development and exploratory wells drilled on our acreage by WildHorse and Esquisto on a combined basis during the years ended December 31, 2014 and 2015:


	Wells Drilled
	Gross		Net
Year Ended December 31, 2014:
Eagle Ford Acreage:
Development		5		4.62
Exploratory		—		—

Total		5		4.62

North Louisiana Acreage:
Development		3		2.95
Exploratory		—		—

Total		3		2.95

Combined Total		8		7.57

Year Ended December 31, 2015:
Eagle Ford Acreage:
Development		18		17.84
Exploratory		—		—

Total		18		17.84

North Louisiana Acreage:
Development		6		4.51
Exploratory		3		2.70

Total		9		7.21

Combined Total		27		25.05

All wells drilled were productive wells, except for one development well drilled in our North Louisiana Acreage during the year ended December 31, 2014 and one exploratory well drilled in our North Louisiana Acreage during the year ended December 31, 2015, each of which was not productive.

In July 2015, we reduced our drilling program in our North Louisiana Acreage to one rig in response to low commodity prices and continued operating a one-rig drilling program through February 2016. Similarly, in early October 2015, we reduced our drilling program in our Eagle Ford Acreage to one rig, which we ran until February 2016, at which point we ceased drilling due to the commodity price environment. We are currently running a one-rig program in our Eagle Ford Acreage, which we are utilizing on a well-to-well basis. We are not currently a party to any long-term drilling rig contracts.

Our Operations

General

We have leased or acquired approximately 375,000 net acres where we had a weighted-average working interest of approximately 79%, as of September 30, 2016. 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.

125

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, which 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.

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 our own salt water disposal well, which currently receives the majority of our associated water production. We have purchased a site for an additional disposal well and intend to construct the second facility as needed to support our development program.

Marketing and Customers

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.

We normally sell production to a relatively small number of customers, as is customary in our business. For the year ended December 31, 2015, Sunoco Partners & Terminals, L.P., Cima Energy LTD and affiliates of Royal Dutch Shell plc accounted for 34%, 16% and 20%, respectively, of WildHorse’s and Esquisto’s total revenue on a combined basis. For the year ended December 31, 2014, affiliates of Royal Dutch Shell plc and BP Corporation North America accounted for 46% and 21%, respectively, of WildHorse’s and Esquisto’s total revenue on a combined basis. During such years, no other purchaser accounted for 10% or more of WildHorse’s and Esquisto’s revenue on a combined basis. The loss of any such purchaser could adversely affect our revenues in the short term. However, based on the current demand for oil and natural gas 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 oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to

126

acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

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.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. 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 prospectus.

127

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from approximately 20% to 30%.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, 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, FERC, EPA, BLM, the Department of Transportation (“DOT”), other federal 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, Texas imposes 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.

128

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: (i) 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, 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.

129

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.

130

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 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. 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, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the 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, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or

131

prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier 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.

The following is a summary of the more 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.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability 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 companies 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.

The Resource 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, from time to time various environmental groups have challenged the EPA’s exemption of certain oil and gas wastes from RCRA. 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. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste 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.

We currently own, lease or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe that we 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 properties have been operated by third parties or by previous owners or

132

operators whose treatment and disposal 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.

Water Discharges

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. 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. The rule has been challenged in court on the grounds that it unlawfully expands the reach of the Clean Water Act, and implementation of the rule has been stayed pending resolution of the court challenge. 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.

Pursuant 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. We are currently undertaking a review of recently acquired oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be material.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), 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 example, operators of certain oil and natural 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.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources (e.g., compressor stations), through the imposition of air emissions standards, construction and operating permitting programs and other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain 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.

133

State implementation 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.

In 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 compressors, and from pneumatic controllers and storage 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.

Regulation of GHG Emissions

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA 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 GHG emissions. Facilities required to obtain preconstruction permits for their GHG emissions 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 oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. In May 2016, the EPA finalized rules 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. The new rule will, and proposed rules could, result in increased compliance costs on our operations. The EPA has also announced that it intends to impose methane emission standards for existing sources but, to date, has not yet issued a proposal. And in 2015, EPA published a rule, known as the Clean Power Plan, to limit greenhouse gases from electric power plants. On February 9, 2016, the Supreme Court stayed the implementation of the Clean Power Plan while legal challenges to the rule proceed. Depending on the ultimate outcome of those challenges, and how various states choose to implement this rule, it may alter the power generation mix between natural gas, coal, oil, and alternative energy sources, which would ultimately affect the demand for natural gas and oil in electric generation.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. 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 was one of 175 countries to sign the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined

134

contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement is expected to enter into force in November 2016. The United States is one of over 70 nations that has indicated it intends to comply with the agreement. 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. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.

Certain governmental reviews are either underway or have been conducted that focus on the environmental aspects of hydraulic fracturing practices. For example, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report has preliminarily concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board, which is in progress. Other governmental agencies, including the White House Council on Environmental Quality, United States Department of Energy and the United States Department of the Interior, have or are evaluating various other aspects of hydraulic fracturing. These studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

135

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.

ESA and Migratory Birds

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that 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 Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land 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 2011, 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. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government in the past has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. 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. 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

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

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.

136

Employees

As of September 30, 2016, WildHorse had 61 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 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.

137

MANAGEMENT

The following table sets forth the names, ages and titles of our directors and executive officers.


Name	Age	Position
Jay C. Graham	46	Chief Executive Officer and Chairman
Anthony Bahr	47	President and Director
Andrew J. Cozby	49	Executive Vice President and Chief Financial Officer
Steve Habachy	38	Executive Vice President and Chief Operating Officer
Kyle N. Roane	37	Executive Vice President, General Counsel and Corporate Secretary
Richard D. Brannon	57	Director
Scott A. Gieselman	53	Director
David W. Hayes	42	Director
Tony R. Weber	54	Director
Jonathan M. Clarkson	66	Director Nominee

Jay C. Graham has served as our Chief Executive Officer and as Chairman of our board of directors since September 2016. Previously, Mr. Graham served as Chief Executive Officer and as a member of the board of directors of MRD from January 2016 until it was acquired by Range Resources Corporation in September 2016. Previously, Mr. Graham served as Co-CEO and Co-Founder of WildHorse from June 2013 to January 2016 and President of WildHorse Resources Management Company (“WHRM”) since its formation in October 2012 to January 2016. Prior to MRD’s initial public offering in June 2014, Mr. Graham served as President of WildHorse Resources, LLC, one of the predecessors of MRD, from August 2007 to June 2014. From 1993 to 2007, Mr. Graham held a variety of positions of increasing responsibility in Halliburton, Devon Energy and Anadarko Petroleum Corporation. Further, Mr. Graham currently serves on the Petroleum Industry Board and the College of Engineering Advisory Council at Texas A&M University, is a co-founder and advisor of the Texas A&M Petroleum Ventures Program educational collaboration between the Mays Business School and Department of Petroleum Engineering and is also a member of the Petroleum Engineering Academy of Distinguished Graduates.

The board of directors believes that Mr. Graham’s degree and experience in petroleum engineering, as well as his history of operating oil and natural gas companies, bring valuable strategic, managerial and leadership skills to the board of directors and us.

Anthony Bahr has served as our President and a member of our board of directors since our formation in August 2016. Previously, Mr. Bahr was a Co-Founder and served as the Co-Chief Executive Officer of WildHorse since WildHorse’s formation in June 2013 and Chief Executive Officer of WHRM since its formation in October 2012. Additionally, Mr. Bahr was a Co-Founder and served as Chief Executive Officer of WildHorse Resources, LLC, one of the predecessors of MRD, since its formation in 2007. Prior to 2007, Mr. Bahr held various management and engineering roles with Hilcorp Energy, Devon Energy, Ocean Energy, Berry Petroleum and Unocal Corporation. Further, Mr. Bahr currently serves on the Dean’s Council of the Mays Business School at Texas A&M University, is a co-founder and advisor of the Texas A&M Petroleum Ventures Program educational collaboration between the Mays Business School and Department of Petroleum Engineering and is also a member of the Petroleum Engineering Academy of Distinguished Graduates. Mr. Bahr is a registered petroleum engineer in California.

The board of directors believes that Mr. Bahr’s degree and experience in petroleum engineering, as well as his history of operating oil and natural gas companies, bring valuable strategic, managerial and analytical skills to the board of directors and us.

Andrew J. Cozby has served as our Executive Vice President and Chief Financial Officer since September 2016. Previously, Mr. Cozby served as Senior Vice President and Chief Financial Officer of MRD from November 2014 until it was acquired by Range Resources Corporation in September 2016, Vice President and Chief Financial Officer of MRD from April 2014 to November 2014 and Vice President, Finance of MRD’s predecessor (“MRD LLC”) from April 2011 to June 2014. Mr. Cozby also served as the Vice President and Chief

138

Financial Officer of Memorial Production Partners GP LLC (“MEMP GP”) from February 2012 to July 2014. From February 2011 to April 2011, Mr. Cozby served as Senior Vice President and Chief Financial Officer of Energy Maintenance Services. Prior to that, he was Chief Financial Officer of Greystone Oil & Gas LLP and Greystone Drilling LP from May 2006 to December 2010. From 2000 to May 2006, Mr. Cozby was Director of Finance for Enterprise Products Partners LP and held various corporate finance positions with its affiliates GulfTerra Energy Partners, LP and El Paso Energy Partners, LP. Prior to that, Mr. Cozby held positions with J.P. Morgan from 1998 to 2000.

Steve Habachy has served as our Executive Vice President and Chief Operating Officer since September 2016. Mr. Habachy joined WildHorse Resources, LLC in 2010, where he served as Vice President, Operations from May 2010 to December 2012. Since January 2013, Mr. Habachy has served as Vice President Operations for WHRM. From March 2007 to April 2010, Mr. Habachy was a partner of Winter Ridge Energy LLC where he served as Vice President of Engineering and Operations. Prior to 2007, Mr. Habachy served in a wide variety of technical engineering and management roles in Louisiana, East Texas and the Gulf Coast with Anadarko Petroleum and Hilcorp Energy Company. Further, Mr. Habachy currently serves on the External Advisory Committee for the Department of Petroleum and Geosystems Engineering at the University of Texas at Austin.

Kyle N. Roane has served as our Executive Vice President, General Counsel and Corporate Secretary since September 2016. Previously, Mr. Roane served as Senior Vice President, General Counsel and Corporate Secretary of MRD from November 2014 until it was acquired by Range Resources Corporation in September 2016, Vice President, General Counsel and Corporate Secretary of MRD from January 2014 to November 2014, Vice President, General Counsel and Corporate Secretary of MRD LLC from January 2014 to June 2014, and General Counsel and Corporate Secretary of MRD LLC from February 2012 through December 2013. Mr. Roane served as Senior Vice President, Compliance and Administration of MEMP GP from July 2015 to April 2016, Senior Vice President, General Counsel and Corporate Secretary of MEMP GP from November 2014 to July 2015, Vice President, General Counsel and Corporate Secretary of MEMP GP from January 2014 to November 2014, and General Counsel and Corporate Secretary of MEMP GP from February 2012 through December 2013. From 2005 to February 2012, Mr. Roane practiced corporate and securities law at Akin Gump Strauss Hauer & Feld L.L.P.

Richard D. Brannon has served as a member of our board of directors since September 2016. Since June 2014, Mr. Brannon has been Chairman and CEO of Esquisto and, since 2007, President of certain CH4 Energy entities, all companies focused on horizontal development of oil & gas reserves in the Eagle Ford formation. Mr. Brannon serves on the Board of Directors of the general partner of Energy Transfer Equity, L.P., and is currently Chairman of the Audit Committee, and previously served on the boards of Sunoco LP, Regency Energy Partners LP, OEC Compression Corporation and Cornerstone Natural Gas, Inc. Mr. Brannon has over 35 years in the energy business starting his career in 1981 with TXO Production Corp. Further, Mr. Brannon is a Certified Registered Professional Engineer in the State of Texas.

The board of directors believes that Mr. Brannon’s extensive experience in the energy industry, including his past experiences as an executive with various energy companies, brings important and valuable skills to the board of directors and us.

Scott A. Gieselman has served as a member of our board of directors since September 2016. Mr. Gieselman has served as a Partner for NGP since April 2007. Prior to joining NGP, Mr. Gieselman worked in various positions in the investment banking energy group of Goldman, Sachs & Co., where he became a partner in 2002. Mr. Gieselman has served as a member of the board of directors of Rice Energy, Inc. since January 2014 and was a member of the board of directors of MRD from its formation until it was acquired by Range Resources Corporation in September 2016. In addition, Mr. Gieselman served as a member of the board of directors of MEMP GP from December 2011 until March 2016.

The board of directors believes that Mr. Gieselman’s considerable financial and energy investment banking experience, as well as his experience on the boards of several energy companies bring important and valuable skills to the board of directors and us.

139

David W. Hayes has served as a member of our board of directors since September 2016. Mr. Hayes has served as a Partner for NGP since 2008. Prior to joining NGP, Mr. Hayes was a member of Merrill Lynch’s Energy Investment Banking group in Houston, Texas, where he focused on mergers and acquisitions and financing in the exploration and production and natural gas pipeline industries. Mr. Hayes previously served on the board of directors of the general partner of Eagle Rock Energy Partners, L.P. from June 2011 until its sale to Vanguard Natural Resources LLC in October 2015 and the board of directors for the general partner of PennTex Midstream Partners, LP (“PennTex”) from June 2015 until NGP sold its interest in PennTex in November 2016.

The board of directors believes that Mr. Hayes’s considerable financial and energy investment banking experience, as well as his experience on the boards of several energy companies bring important and valuable skills to the board of directors and us.

Tony R. Weber has served as a member of our board of directors since September 2016. Mr. Weber currently serves as Managing Partner and Chairman of the Executive Committee for NGP. Prior to joining NGP in December 2003, Mr. Weber was the Chief Financial Officer of Merit Energy Company from April 1998 to December 2003. Prior to that, he was Senior Vice President and Manager of Union Bank of California’s Energy Division in Dallas, Texas from 1987 to 1998. Mr. Weber served as Chairman of the board of directors of MRD from its formation in January 2014 until MRD was acquired by Range Resources Corporation in September 2016. In addition, Mr. Weber served as a member of the board of directors of MEMP GP from December 2011 to March 2016. Further, in his role at NGP, Mr. Weber serves on numerous private company boards as well as industry groups, IPAA Capital Markets Committee and Dallas Wildcat Committee. He currently serves on the Dean’s Council of the Mays Business School at Texas A&M University and was a founding member of the Mays Business Fellows Program.

The board of directors believes that Mr. Weber’s extensive corporate finance, banking and private equity experience bring substantial leadership skill and experience to the board of directors and us.

Jonathan M. Clarkson has been nominated to serve on our board of directors, effective concurrently with this offering. Since 2011, Mr. Clarkson has served on the board of directors and as a member of the audit committee of MEMP GP. Mr. Clarkson is also serving in the capacity of non-executive Chairman of MEMP GP, which was effective September 2016. Mr. Clarkson recently retired as Chief Financial Officer for Matrix Oil Corporation effective January 1, 2016. He had served in that capacity since May 2012. Mr. Clarkson served as Chairman of the Houston Region of Texas Capital Bank from May 2009 until his retirement in December 2011. From 2003 to May 2009, he served as President and CEO of the Houston Region of Texas Capital Bank. From May 2001 to October 2002, Mr. Clarkson served as President, Chief Financial Officer and a director of Mission Resources Corp., an independent oil and gas exploration and production company. From 1999 through 2001, Mr. Clarkson served as President and Chief Operating Officer of Bargo Energy Company, a private company engaged in the acquisition and exploitation of onshore oil and natural gas properties, which merged with Mission Resources in May 2001. From 1987 to 1999, Mr. Clarkson served as Executive Vice President and Chief Financial Officer for Ocean Energy Corp. and its predecessor company United Meridian Corporation. From October 2006 until December 2009, Mr. Clarkson served on the board of directors, was chairman of the audit committee, and was a member of the compensation committee of Edge Petroleum Corp., an oil and gas exploration and production company. Mr. Clarkson currently serves on the board of directors, is chairman of the audit committee, and is a member of the corporate governance committee, of Parker Drilling Company. This service began in January 2012. Since September 2010, Mr. Clarkson has served on the advisory board of Rivington Capital Advisors, LLC, an investment banking firm focused on upstream energy sector investments.

The board of directors believes that Mr. Clarkson’s over 40 years of experience in the oil and gas industry, his service in multiple Chief Financial Officer positions with both private and public companies and his experience as Audit Chair for three public companies bring extensive financial expertise and proven leadership to the board of directors and us.

140

There are no family relationships among any of our directors or executive officers.

Board Composition

Upon the closing of this offering, it is anticipated that we will have seven directors.

Our board of directors has determined that Messrs. Clarkson, Gieselman, Hayes and Weber are independent under NYSE listing standards.

In connection with this offering, we will enter into a stockholders’ agreement with WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The stockholders’ agreement is expected to provide WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings with the right to designate a certain number of nominees to our board of directors so long as they and their affiliates collectively beneficially own more than 5% of the outstanding shares of our common stock.

Initially, our board of directors will consist of a single class of directors each serving one year terms. After the Sponsor Group no longer collectively beneficially owns or controls more than 50% of the voting power of our outstanding common stock, our board of directors will be divided into three classes of directors, with each class as equal in number as possible, serving staggered three-year terms, and such directors will be removable only for “cause.”

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board of directors’ ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board of directors to fulfill their duties. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.

Status as a Controlled Company

Because NGP, through WildHorse Holdings and Esquisto Holdings, will beneficially own a majority of our outstanding common stock following the completion of this offering, we expect to be a controlled company under the NYSE corporate governance standards. A controlled company need not comply with the applicable corporate governance rules that require its board of directors to have a majority of independent directors and independent compensation and nominating and governance committees. Notwithstanding our status as a controlled company, we will remain subject to the applicable corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, we must have at least one independent director on our audit committee by the date our common stock is listed on the NYSE, a majority of independent directors on our audit committee within 90 days of the listing date and all independent directors on our audit committee within one year of the listing date.

Because we are a controlled company, we will not be required to, and do not currently expect to have, a compensation committee or a nominating and corporate governance committee. If at any time we cease to be a controlled company, we will take all action necessary to comply with the NYSE listing rules, including appointing a majority of independent directors to our board of directors and ensuring we have a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to a permitted “phase-in” period. We will cease to qualify as a controlled company once NGP, through WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, ceases to control a majority of our voting stock.

141

Committees of the Board of Directors

Upon the conclusion of this offering, we intend to have an audit committee of our board of directors, and may have such other committees as the board of directors shall determine from time to time. We anticipate that each standing committee of the board of directors will have the composition and responsibilities described below.

Audit Committee

We will establish an audit committee prior to the completion of this offering. Messrs. Clarkson, Gieselman and Weber will serve as the members of our audit committee. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors within one year of the listing date. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. Mr. Clarkson will satisfy the definition of “audit committee financial expert.”

The audit committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including the selection of our independent accountants, the scope of our annual audits, the fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. We expect to adopt an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and the NYSE.

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

142

EXECUTIVE COMPENSATION

We are currently considered an “emerging growth company,” within the meaning of the Securities Act, for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year-End table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Further, our reporting obligations extend only to our “named executive officers,” who are the individuals who served as our principal executive officer and our two other most highly compensated officers who served as executive officers during the last completed fiscal year. WildHorse Development, the issuer of common stock in this offering, was formed in August 2016. As a result, we are presenting executive compensation information for the individuals who we expect to serve as named executive officers of WildHorse Development following this offering. Our named executive officers are:


Name	Principal Position
Jay C. Graham		Chief Executive Officer
Anthony Bahr		President
Steve Habachy		Executive Vice President and Chief Operating Officer

2015 Summary Compensation Table

The following table summarizes, with respect to our named executive officers, information relating to compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2015.


Name and Principal Position	Year		Salary ($)		All Other Compensation ($)(1)		Total ($)
Jay C. Graham		2015	$	266,667	$	15,540	$	282,207
(Chief Executive Officer and Director)
Anthony Bahr		2015	$	266,667	$	15,519	$	282,186
(President and Director)
Steve Habachy		2015	$	258,334	$	15,603	$	273,937
(Executive Vice President and Chief Operating Officer)

(1)

Amounts in this column reflect (a) matching contributions to the 401(k) Plan (as defined below) made on behalf of our named executive officers for 2015 and (b) life insurance premiums paid for the benefit of our named executive officers for 2015. See “—Narrative Disclosures—Retirement Benefits” below for more information on matching contributions to the 401(k) Plan.

143

Outstanding Equity Awards at 2015 Fiscal Year-End

The following table reflects information regarding outstanding incentive units held by our named executive officers as of December 31, 2015. WildHorse is currently responsible for making all payments, distributions and settlements to all award recipients relating to the incentive units and following the consummation of this offering, WildHorse Investment Holdings will be responsible for making all payments, distributions and settlements to all award recipients relating to such incentive units. See “—Narrative Disclosures—Incentive Units” for more information on such incentive units prior to and following the consummation of this offering.

Option Awards(1)

Name

Number of
Securities
Underlying
Unexercised
Options,
Exercisable
(#)

Number of
Securities
Underlying
Unexercised
Options,
Unexercisable
(#)

Option Exercise
Price ($)

Option
Expiration Date

Jay C. Graham

Tier I Units

73,333

126,667

N/A

Tier II Units

73,333

126,667

N/A

Tier III Units

200,000

N/A

Tier IV Units

200,000

N/A

Tier V Units

200,000

N/A

Anthony Bahr

Tier I Units

73,333

126,667

N/A

Tier II Units

73,333

126,667

N/A

Tier III Units

200,000

N/A

Tier IV Units

200,000

N/A

Tier V Units

200,000

N/A

Steve Habachy

Tier I Units

25,667

44,333

N/A

Tier II Units

25,667

44,333

N/A

Tier III Units

70,000

N/A

Tier IV Units

70,000

N/A

Tier V Units

70,000

N/A

(1)

The incentive units are intended to constitute “profits interests” and represent actual (non-voting) equity interests that have no liquidation value for U.S. federal income tax purposes on the date of grant but are designed to gain value only after the underlying assets have realized a certain level of growth and return to those persons who hold certain other classes of equity. We believe that, despite the fact that the incentive units do not require the payment of an exercise price, these awards are most similar economically to stock options and, as such, they are properly classified as “options” for purposes of the SEC’s executive compensation disclosure rules under the definition provided in Item 402(m)(5)(i) of Regulation S-K since these awards have “option-like features.” The incentive units are divided into five tiers, and each tier has a separate distribution threshold and vesting schedule. Awards reflected as “Exercisable” are incentive units that have vested, and awards reflected as “Unexercisable” are incentive units that have not yet vested. For a description of how and when the incentive units could become vested and when such awards could begin to receive payments, see “—Narrative Disclosures—Incentive Units” below.

144

Narrative Disclosures

Base Salary

Each named executive officer’s base salary is a fixed component of compensation for each year for performing specific job duties and functions. Historically, the board of managers of WildHorse established the annualized base salary for each of the named executive officers at a level necessary to retain such named executive officer’s services and reviewed such annualized base salary at the end of each year, with adjustments implemented at the beginning of the next year. The establishment and adjustment of the annualized base salary for each named executive officer has generally been based on factors including but not limited to: (i) any increase or decrease in the named executive officer’s responsibility, (ii) the named executive officer’s job performance and (iii) the level of compensation paid to executives of other companies with which we compete for executive talent, as estimated based on publicly available information and the prior experience of the board of managers of WildHorse. See “—Narrative Disclosures—Compensation Following This Offering” for more information on how we expect the compensation (including annualized base salary) of our named executive officers will be determined following the consummation of this offering.

Employment, Severance or Change in Control Agreements

We historically have not maintained any employment, severance or change in control agreements with our named executive officers. In addition, our named executive officers are not currently entitled to any payments or other benefits in connection with a termination of employment or a change in control, other than with respect to incentive units as described below under “—Incentive Units.” See “—Narrative Disclosures—Compensation Following This Offering—Change in Control Plan” for more information on the change in control plan that we expect to adopt in connection with the consummation of this offering.

Retirement Benefits

We have not maintained, and do not currently intend to maintain, a defined benefit pension plan or nonqualified deferred compensation plan. Instead, our employees, including our named executive officers, may participate in a retirement plan sponsored by WildHorse Resources Management Company, our wholly owned subsidiary, intended to provide benefits under section 401(k) of the Code (the “401(k) Plan”) pursuant to which employees are allowed to contribute a portion of their base compensation to a tax-qualified retirement account. We provide matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the 401(k) Plan up to a statutory limit, which was $18,000 for the calendar year 2015. Employees are immediately 100% vested in the matching contributions made to their 401(k) Plan account and are always 100% vested in the employee contributions they make to their 401(k) Plan account. Employees may generally receive a distribution of the vested portion of their 401(k) Plan account upon (i) a termination of employment, (ii) normal retirement, (iii) disability or (iv) death.

Incentive Units

WildHorse Incentive Units

In 2014, Messrs. Graham, Bahr and Habachy received an award of incentive units in WildHorse pursuant to the Limited Liability Company Agreement of WildHorse Resources II, LLC (the “WildHorse LLC Agreement”), which are profits interests that represent actual (non-voting) equity interests in WildHorse (the “WildHorse Incentive Units”), in order to provide Messrs. Graham, Bahr and Habachy with the ability to benefit from the growth in our operations and business. The WildHorse Incentive Units are divided into five tiers, with each tier currently comprised of one tranche. A potential payout for each tranche will occur when a certain specified level of cumulative cash distributions has been received by the capital interest holding members of WildHorse. Tier I units and Tier II units each vest in five equal annual installments beginning on the first anniversary of the applicable date of grant (with vesting between such anniversaries occurring pro rata each month), although such

145

vesting will be fully accelerated upon the occurrence of either (i) (a) with respect to the Tier I units, satisfaction of the payment threshold established for the Tier I units or (b) with respect to the Tier II units, satisfaction of the payment threshold established for the Tier II units or (ii) with respect to both Tier I and Tier II units, a “Fundamental Change” (as defined below). Tier III, Tier IV and Tier V units each only vest upon satisfaction of the payment threshold established for the applicable tier. All WildHorse incentive units that have not yet vested according to their applicable vesting requirements will automatically be forfeited and become null and void at the time a grantee’s employment is terminated for any reason other due to death or disability. If a grantee’s employment is terminated due to death or disability, any Tier I or Tier II units that would have become vested within 12 months of such termination shall automatically vest upon such termination. If a grantee’s employment is terminated for “cause” (as defined below) or such grantee resigns or terminates the service relationship early other than due to death or disability (each, a “voluntary termination”), all vested WildHorse Incentive Units will be forfeited at the time of termination. In the event that a grantee’s employment is terminated other than (i) for cause or (ii) due to a voluntary termination, such grantee will retain all vested WildHorse Incentive Units following such termination. For purposes of the foregoing, a grantee’s termination of employment means the termination of a grantee’s employment with WildHorse, its subsidiaries and affiliates, including us.

The Tier I units entitle Tier I unitholders to 20% of future distributions only after all of the members in WildHorse that have made capital contributions to WildHorse have received cumulative cash distributions in respect of their membership interests equal to their cumulative capital contributions multiplied by (1.08) ⁿ , where “n” is equal to the “Weighted Average Capital Contribution Factor” (as defined below) determined as of the date of such distribution. The Tier II units entitle Tier II unitholders to 5% of future distributions only after all of the members in WildHorse that have made capital contributions to WildHorse have received cumulative cash distributions in respect of their membership interests equal to their cumulative capital contributions multiplied by (1.20) ⁿ , where “n” is equal to the Weighted Average Capital Contribution Factor determined as of the date of such distribution. The Tier III units entitle Tier III unitholders to 5% of future distributions only after all of the members in WildHorse that have made capital contributions to WildHorse have received cumulative cash distributions in respect of their membership interests equal to two (2) times their cumulative capital contributions. The Tier IV units entitle Tier IV unitholders to 5% of future distributions only after all of the members in WildHorse that have made capital contributions to WildHorse have received cumulative cash distributions in respect of their membership interests equal to two and one-half (2.5) times their cumulative capital contributions. The Tier V units entitle Tier V unitholders to 5% of future distributions only after all of the members in WildHorse that have made capital contributions to WildHorse have received cumulative cash distributions in respect of their membership interests equal to three (3) times their cumulative capital contributions. References to “members” above refer to members of our predecessor, WildHorse (as opposed to a stockholder of us). As used above, “Weighted Average Capital Contribution Factor” is, as of any date of calculation, a weighted average equal to the sum of the amounts determined for each date on which capital contributions have been funded calculated as the product of (a) the percentage of the total capital commitments funded on each date, times (b) the number of years from the date of each capital contribution until the date of such calculation (with a partial year being expressed as a decimal determined by dividing the number of days which have passed since the most recent anniversary by 365).

Under the WildHorse LLC Agreement, a “Fundamental Change” is generally the occurrence of any of the following events: (i) (a) WildHorse merges or consolidates with or into, or enters into any similar transaction with, any person other than one of WildHorse’s affiliates, members or certain of its other related parties; (b) WildHorse’s outstanding interests are sold or exchanged in a single transaction, or a series of related transactions, to any person other than one of WildHorse’s affiliates, members or certain of its other related parties; or (c) WildHorse sells, leases, licenses or exchanges, or agrees to sell, lease, license or exchange, all or substantially all of WildHorse’s assets to a person that is not one of WildHorse’s affiliates, members or certain of its other related parties, provided that in the case of any such transaction described in (a), (b) or (c), the individuals that served as members of WildHorse’s board of managers before the consummation of such transaction cease to constitute at least a majority of the members of the board or analogous managing body of the surviving or acquiring entity immediately following completion of such transaction; (ii) any person or group

146

(other than one of WildHorse’s affiliates, members or certain of its other related parties) purchases or otherwise acquires the right to vote or dispose of securities of WildHorse representing 50% or more of the total voting power of all outstanding voting securities of WildHorse, unless the transaction was approved WildHorse’s board of managers (provided that, no capital contributions made by NGP or its successors and assigns shall cause a Fundamental Change); or (iii) WildHorse is dissolved and liquidated. All of the transactions occurring in connection with the Corporate Reorganization involve one of WildHorse’s affiliates, members or its other related parties, and no interests of WildHorse or WildHorse Investment Holdings are being offered by us in this offering. As a result, neither the Corporate Reorganization nor this offering constitutes a Fundamental Change under the WildHorse LLC Agreement.

Under the WildHorse LLC Agreement, a termination for “cause” generally occurs upon an individual’s: (i) conviction of, or plea of nolo contendere to, any felony or crime causing substantial harm to WildHorse or its affiliates or involving acts of theft, fraud, embezzlement, moral turpitude, or similar conduct; (ii) repeated intoxication by alcohol or drugs during the performance of the individual’s duties in a manner that materially and adversely affects the performance of such duties; (iii) malfeasance in the conduct of the individual’s duties, including but not limited to (a) misuse or diversion of funds of WildHorse or its affiliates, (b) embezzlement or (c) material misrepresentations or concealments on any written reports submitted to WildHorse or its affiliates; (iv) material violation of the Voting and Transfer Restriction Agreement among WildHorse and its members or the individual’s confidentiality and noncompete agreement; or (v) material failure to perform the duties of the individual’s employment relationship with WildHorse or its affiliates (including us), or material failure to follow or comply with the reasonable and lawful written directives of our board of directors, WildHorse’s board of managers or the board of an affiliate of WildHorse by which the individual is employed, in either case, after the individual shall have been informed, in writing, of such material failure and given a period of not less than 60 days to remedy the failure.

As of the date of this filing, no tier of WildHorse Incentive Units has received a payout. Prior to the Corporate Reorganization and this offering, WildHorse is responsible for making all payments, distributions and settlements to all award recipients relating to the WildHorse Incentive Units as the WildHorse Incentive Units are equity interests in WildHorse. In connection with the Corporate Reorganization and this offering, Messrs. Graham, Bahr and Habachy (and other WildHorse Incentive Unit holders) will transfer their WildHorse Incentive Units to WildHorse Investment Holdings in exchange for substantially similar incentive units in WildHorse Investment Holdings (the “Exchanged Incentive Units”). As a result, following the Corporate Reorganization and this offering, WildHorse Investment Holdings will be responsible for making all payments, distributions and settlements to all award recipients relating to the Exchanged Incentive Units as the Exchanged Incentive Units will be equity interests in WildHorse Investment Holdings. In other words, the burden of the WildHorse Incentive Units currently attributable to WildHorse will be replicated with respect to the Exchanged Incentive Units under the limited liability company agreement of WildHorse Investment Holdings. The Exchanged Incentive Units are profits interests that will represent actual (non-voting) equity interests in WildHorse Investment Holdings, in order to provide holders thereof with the ability to benefit from the growth in WildHorse Investment Holdings’ operations and business. A potential payout for each tranche will occur when a specified level of cumulative cash distributions has been received by the capital interest holding members of WildHorse Investment Holdings. We expect that the assets of WildHorse Investment Holdings will consist only of the equity interests in WildHorse Holdings that it receives in connection with the Corporate Reorganization and this offering (which represent all outstanding equity interests other than certain “WildHorse Holdings Incentive Units,” which are described further under “—Compensation Following This Offering—WildHorse Holdings and Esquisto Holdings Incentive Units,” to be issued by WildHorse Holdings in connection with this offering). Further, we expect that the assets of WildHorse Holdings will consist only of the shares of our common stock that it receives in connection with the Corporate Reorganization and this offering. Accordingly, we expect that the only events that would cause cash distributions to the capital interest holding members of WildHorse Investment Holdings would either be (i) sales of our common stock by WildHorse Holdings or (ii) in-kind distributions of shares of our common stock by WildHorse Holdings to its members (including WildHorse Investment Holdings). While any payments, distributions and settlements made by WildHorse Investment

147

Holdings with respect to the Exchanged Incentive Units will not involve any cash payment by us, we will recognize non-cash compensation expense within general and administrative expenses, which may be material, in the period in which the applicable performance conditions are probable of being satisfied. We will receive a deemed capital contribution with respect to such compensation expense. Because we will not be a party to the limited liability company agreement of WildHorse Investment Holdings, we cannot be certain that the terms of the Exchanged Incentive Units, as applicable, will remain the same in the future.

Compensation Following This Offering

We expect to employ a compensation philosophy that will emphasize pay-for-performance, which is expected to be based on a combination of our performance and the individual’s impact on our performance and is expected to place the majority of each named executive officer’s compensation at risk. We expect that the future compensation of our executive and non-executive officers will include a significant component of incentive compensation based on our performance. The performance metrics governing such incentive compensation is not expected to be tied in any way to the performance of entities other than us. We believe this pay-for-performance approach will generally align the interests of our executive officers with that of our stockholders, and at the same time enable us to maintain a lower level of base overhead in the event our operating and financial performance fails to meet expectations.

We will design our executive compensation program to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our stockholders, and to reward success in reaching such goals. We expect that we will use three primary elements of compensation to fulfill that design—base salary, cash bonuses and long-term equity incentive awards. Cash bonuses and long-term equity incentive awards (as opposed to base salary) represent the performance driven elements. They are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals’ cash bonuses reflects their relative contribution to achieving or exceeding annual goals, and the determination of specific individuals’ long-term equity incentive awards is based on their expected contribution in respect of longer term performance objectives.

We do not intend to establish a defined benefit or pension plan for our executive officers because we believe such plans primarily reward longevity rather than performance. We will provide a basic benefits package generally to all employees, which includes the 401(k) Plan and health, disability and life insurance.

Following the consummation of this offering, we expect that the following individuals are the executive officers who may qualify as our named executive officers for the year ended December 31, 2016:


Name		Principal Position
Jay C. Graham		Chief Executive Officer
Anthony Bahr		President
Andrew J. Cozby		Executive Vice President and Chief Financial Officer
Steve Habachy		Executive Vice President and Chief Operating Officer
Kyle N. Roane		Executive Vice President, General Counsel and Corporate Secretary

However, the actual determination of our named executive officers for the year ended December 31, 2016 will depend on who serves as our principal executive officer and our two other most highly compensated officers who serve as executive officers during 2016.

148

The following table sets forth the expected annualized base salary and expected annual target bonus opportunity for each of our potential named executive officers for 2017:


Name	2017 Base Salary		2017 Target Bonus Opportunity (% of Base Salary)
Jay C. Graham	$	450,000		100	%
Anthony Bahr	$	450,000		100	%
Andrew J. Cozby	$	350,000		80	%
Steve Habachy	$	350,000		80	%
Kyle N. Roane	$	350,000		80	%

IPO Bonuses

We intend to grant certain potential named executive officers bonuses in connection with the consummation of this offering. The bonuses are expected to be granted to such employees in the form of restricted stock awards that will be governed by our LTIP. It is anticipated that the restricted stock awards will be granted following the closing of this offering and will be subject to a three-year graded vesting schedule. We expect that these bonuses will consist of an aggregate of shares of restricted stock for all employees (including our named executive officers), which represents approximately $ million (assuming the value of each restricted share is equal to $ (which represents the midpoint of the price range set forth on the cover of this prospectus with respect to a share of our common stock)). We expect that certain of our potential named executive officers will receive the following awards of restricted stock as bonuses following the closing of this offering: Mr. Cozby: shares and Mr. Roane: shares. However, our LTIP has not yet been adopted and such awards have not yet been granted. As a result, the foregoing remains subject to change and is qualified in its entirety by reference to the final awards once granted.

WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings Incentive Units

In connection with the Corporate Reorganization and this offering, it is anticipated that WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will grant certain employees, including our potential named executive officers, awards of incentive units in WildHorse Holdings (the “WildHorse Holdings Incentive Units”), Esquisto Holdings (the “Esquisto Holdings Incentive Units”) and Acquisition Co. Holdings (the “Acquisition Co. Holdings Incentive Units”) pursuant to the limited liability company agreements of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units and Acquisition Co. Holdings Incentive Units are expected to represent actual (non-voting) equity interests in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units and Acquisition Co. Holdings Incentive Units are expected to be divided into two tiers, with each tier comprised of one tranche. Tier I incentive units and Tier II incentive units would each vest in three equal annual installments beginning on the first anniversary of the applicable date of grant. Tier I incentive units would entitle Tier I incentive unitholders to 10% of future distributions by each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings in excess of the value of our common stock held by each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings based upon the initial public offering price of such common stock in this offering plus a 5% internal rate of return until such time as total distributions from WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings to the Tier I incentive unitholders equals $50 million in the aggregate. Tier II incentive units would then entitle the Tier II incentive unitholders to 10% of all subsequent distributions by each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will be responsible for making all payments, distributions and settlements to all award recipients relating to the WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units and Acquisition Co. Holdings Incentive Units, respectively, as the WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units and Acquisition Co. Holdings Incentive Units will represent equity interests in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively. A potential payout for each tranche of

149

WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units or Acquisition Co. Holdings Incentive Units, as applicable, will occur when a specified level of cumulative cash distributions has been received by the capital interest holding members of WildHorse Holdings, Esquisto Holdings or Acquisition Co. Holdings, respectively. We expect that the assets of each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will consist only of the shares of our common stock that each receives in connection with the Corporate Reorganization and this offering. Accordingly, we expect that the only event that would cause cash distributions to the capital interest holding members of WildHorse Holdings, Esquisto Holdings or Acquisition Co. Holdings, as applicable, would be the sale of our common stock by WildHorse Holdings, Esquisto Holdings or Acquisition Co. Holdings, respectively. While any payments, distributions and settlements made by WildHorse Holdings, Esquisto Holdings or Acquisition Co. Holdings with respect to the WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units or Acquisition Co. Holdings Incentive Units, as applicable, is not expected to involve any cash payment by us, we expect to recognize non-cash compensation expense within general and administrative expenses, which may be material, in the period in which the applicable performance conditions are probable of being satisfied. We will receive a deemed capital contribution with respect to such compensation expense.

We expect that our potential named executive officers will receive the following awards of WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units and Acquisition Co. Holdings Incentive Units in connection with the consummation of this offering:

WildHorse Holdings

Units

Esquisto Holdings

Units

Acquisition Co. Holdings

Units

Name

Tier I

Tier II

Tier I

Tier II

Tier I

Tier II

Jay C. Graham

50,000 units

275,000 units

50,000 units

275,000 units

50,000 units

275,000 units

Anthony Bahr

50,000 units

275,000 units

50,000 units

275,000 units

50,000 units

275,000 units

Andrew J. Cozby

150,000 units

75,000 units

150,000 units

75,000 units

150,000 units

75,000 units

Steve Habachy

150,000 units

75,000 units

150,000 units

75,000 units

150,000 units

75,000 units

Kyle N. Roane

150,000 units

75,000 units

150,000 units

75,000 units

150,000 units

75,000 units

Because we will not be a party to the limited liability company agreement of WildHorse Holdings, Esquisto Holdings or Acquisition Co. Holdings, we cannot be certain that the terms of the WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units or Acquisition Co. Holding Incentive Units, as applicable, will remain the same in the future.

Change in Control Plan

We believe that it is important to provide our named executive officers with certain severance and change in control payments or benefits in order to establish a stable work environment for the individuals responsible for our day to day management. We historically have not maintained any employment, severance or change in control agreements with any of our named executive officers. However, in order to better assist us in our above-stated goal, we expect to adopt the Executive Change in Control and Severance Plan (the “CIC Plan”), which will cover our named executive officers and certain other executives. The following description of the CIC Plan is based on the form we anticipate adopting, but the CIC Plan has not yet been adopted and the provisions discussed below remain subject to change. As a result, the following description is qualified in its entirety by reference to the final CIC Plan once adopted.

The CIC Plan provides certain severance and change in control benefits to our named executive officers and certain other executives who are selected by our board of directors, or a committee thereof (as applicable, the “Committee”). Upon the occurrence of a “change in control” (as defined below), all outstanding unvested equity awards held by a participant will immediately become fully vested. Further, if a participant’s employment with us is terminated:

•

Due to death or “disability” (as defined in the CIC Plan), the participant is entitled to receive (i) an amount equal to the participant’s annualized base salary, paid in a lump sum, (ii) continued health benefits for 18 months, (iii) a pro-rated annual bonus for the calendar year in which the participant’s termination date occurs and (iv) all unpaid salary and other outstanding amounts owed to the participant.

150

•

By us without “cause” or by the participant for “good reason” (as such quoted terms are defined in the CIC Plan), the participant is entitled to receive (i) a lump sum payment in an amount equal to one (1.0) times (or (x) one and one-half (1.5) times in the case of one of our Executive Vice Presidents or (y) two (2) times in the case of our CEO or President) the sum of (a) the participant’s annualized base salary plus (b) the greater of the participant’s average annual performance bonus for the preceding two calendar years or the participant’s target annual performance bonus for the calendar year in which the termination occurs, (ii) continued health benefits for 12 months (or (x) 18 months in the case of one of our Executive Vice Presidents or (y) 24 months in the case of our CEO or President), (iii) a pro-rated annual bonus for the calendar year in which the participant’s termination date occurs, (iv) all unpaid salary and other outstanding amounts owed to the participant and (v) accelerated vesting of all outstanding unvested equity awards.

•

By us without cause or by the participant for good reason, in either case, within two years following the occurrence of a change in control, the participant is entitled to receive (i) a lump sum payment in an amount equal to two (2) times (or (x) two and one-half (2.5) times in the case of one of our Executive Vice Presidents or (y) three (3) times in the case of our CEO or President) the sum of (a) the participant’s annualized base salary plus (b) the greater of the participant’s average annual performance bonus for the preceding two calendar years or the participant’s target annual performance bonus for the calendar year in which the termination occurs, (ii) continued health benefits for 24 months (or (x) 30 months in the case of one of our Executive Vice Presidents or (y) 36 months in the case of our CEO or President), (iii) a pro-rated annual bonus for the calendar year in which the participant’s termination date occurs and (iv) all unpaid salary and other outstanding amounts owed to the participant.

For purposes of the CIC Plan, a “change in control” generally means the occurrence of any of the following events:

•

the acquisition of 50% or more of either (i) the outstanding shares of our common stock or (ii) the combined voting power of the outstanding voting securities of WildHorse Development;

•

a majority of the members of our board of directors are replaced by directors whose appointment or election is not endorsed by a majority of the members of our board of directors prior to the date of the appointment or election;

•

consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of WildHorse Development; or

•

approval by our stockholders of a complete liquidation or dissolution of WildHorse Development.

The CIC Plan does not provide a tax gross-up provision for federal excise taxes that may be imposed under section 4999 of the Code. Instead, the CIC Plan includes a modified cutback provision, which states that, if amounts payable to a plan participant under the CIC Plan (together with any other amounts that are payable by us as a result of a change in control (the “Payments”) exceed the amount allowed under section 280G of the Code for such participant, thereby subjecting the participant to an excise tax under section 4999 of the Code, then the Payments will either be: (i) reduced to the level at which no excise tax applies, such that the full amount of the Payments would be equal to $1 less than three times the participant’s “base amount,” which is generally the average W-2 earnings for the five calendar years immediately preceding the date of termination, or (ii) paid in full, which would subject the participant to the excise tax. We will determine, in good faith, which alternative produces the best net after tax position for a participant.

The CIC Plan may be amended or terminated by resolution of two-thirds of our board of directors, except that (i) no amendment adopted within one year prior to a change in control may adversely affect any participant without his or her consent, (ii) no amendment may be made at the request of a third party that takes steps to effectuate a change in control or otherwise in connection with a change in control and (iii) no amendment may be made within two years following the occurrence of a change in control that would adversely affect any individual who is a participant on the change in control date.

151

Director Compensation

WildHorse Development, the issuer of common stock in this offering, was formed in August 2016. No obligations with respect to compensation for directors have been accrued or paid for any periods prior to such formation date or following such formation date during fiscal year 2015 or to date in 2016. Individuals serving on the board of managers of WildHorse and Esquisto did not receive any compensation for their services on such boards of managers during fiscal year 2015.

Going forward, we believe that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance of our company. We also believe that a significant portion of the total compensation package for our non-employee directors should be equity-based to align the interest of directors with our stockholders.

Following the completion of this offering, we expect to provide our non-employee directors (other than directors who are employees of NGP) with an annual compensation package comprised of a cash element and an equity-based award element. Under such compensation package, our non-employee directors (other than directors who are employees of NGP) are expected to each receive the following:

•

An annual cash retainer of $150,000; and

•

An annual restricted stock award equal in value to approximately $150,000 (determined as of the applicable date of grant), which award vests in full on the first anniversary of such date of grant.

We also expect that all members of our board of directors will be reimbursed for certain reasonable expenses in connection with their services to us.

Directors who are also our employees or employees of NGP will not receive any additional compensation for their service on our board of directors.

2016 Long-Term Incentive Plan

Prior to the completion of this offering, we anticipate that our board of directors will adopt a long-term incentive plan pursuant to which our employees, consultants and directors (and those of our subsidiaries), including our named executive officers, will be eligible to receive awards. We anticipate that our LTIP will provide for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards, and performance awards intended to align the interests of participants with those of our stockholders. The following description of our LTIP is based on the form we anticipate adopting, but our LTIP has not yet been adopted and the provisions discussed below remain subject to change. As a result, the following description is qualified in its entirety by reference to the final LTIP once adopted.

Administration . We anticipate that our LTIP will be administered by our board of directors, or a committee thereof (as applicable, the “Plan Administrator”). The Plan Administrator will have the authority to, among other things, designate eligible persons as participants under our LTIP, determine the type or types of awards to be granted to eligible persons, determine the number of shares of our common stock to be covered by awards, determine the terms and conditions applicable to awards and interpret and administer our LTIP. The Plan Administrator may terminate or amend our LTIP at any time with respect to any shares of our common stock for which a grant has not yet been made. The Plan Administrator also has the right to alter or amend our LTIP or any part of our LTIP from time to time, including increasing the number of shares of our common stock that may be granted, subject to stockholder approval as required by any exchange upon which our common stock is listed at that time. However, no change to any outstanding award may be made that would materially and adversely affect the rights of the participant under the award without the consent of the participant.

152

Number of Shares. Subject to adjustment in the event of any distribution, recapitalization, split, merger, consolidation or similar corporate event, we anticipate that the number of shares available for delivery pursuant to awards granted under our LTIP will not exceed shares of our common stock. There is no limit on the number of awards that may be granted and paid in cash. Shares subject to awards under our LTIP that are canceled, forfeited, exchanged, settled in cash or otherwise terminated, including shares withheld to satisfy exercise prices or tax withholding obligations, will again be available for awards under our LTIP. The shares of our common stock to be delivered under our LTIP will be made available from authorized but unissued shares, shares held in treasury, or previously issued shares reacquired by us, including by purchase on the open market.

Stock Options. A stock option, or option, is a right to purchase shares of our common stock at a specified price during specified time periods. It is anticipated that options will have an exercise price that may not be less than the fair market value of our common stock on the date of grant. Options granted under our LTIP can be either incentive options (within the meaning of section 422 of the Code), which have certain tax advantages for recipients, or non-qualified options. No option will have a term that exceeds ten years.

Stock Appreciation Rights. A stock appreciation right is an award that, upon exercise, entitles a participant to receive the excess of the fair market value of our common stock on the exercise date over the grant price established for the stock appreciation right on the date of grant. Such excess will be paid in cash or in common stock, or a combination thereof. It is anticipated that stock appreciation rights will have a grant price that may not be less than the fair market value of our common stock on the date of grant.

Restricted Stock. A restricted stock grant is an award of common stock that vests over a period of time and, during such time, is subject to transfer limitations, a risk of forfeiture and other restrictions imposed by the Plan Administrator, in its discretion. During the restricted period, a participant will have rights as a stockholder, including the right to vote the common stock subject to the award and to receive cash dividends thereon (which may, if required by the Plan Administrator, be subjected to the same vesting terms that apply to the underlying award of restricted stock).

Restricted Stock Units. A restricted stock unit is a notional share that entitles the grantee to receive shares of our common stock, cash or a combination thereof, as determined by the Plan Administrator, following a specified period.

Stock Awards. A stock award is a transfer of unrestricted shares of our common stock on terms and conditions determined by the Plan Administrator.

Dividend Equivalents. Dividend equivalents entitle a participant to receive cash, common stock, other awards or other property equal in value to dividends paid with respect to a specified number of shares of our common stock, or other periodic payments at the discretion of the Plan Administrator. Dividend equivalents may be granted on a free-standing basis or in connection with another award (other than an award of restricted stock or a stock award).

Other Stock-Based Awards. Other stock-based awards are awards denominated or payable in, valued in whole or in part by reference to, or otherwise based on or related to, the value of our common stock.

Cash Awards. Cash awards may be granted on a free-standing basis, as an element of or a supplement to, or in lieu of any other award.

Substitute Awards. Awards may be granted in substitution or exchange for any other award granted under our LTIP or under another equity incentive plan or any other right of an eligible person to receive payment from us. Awards may also be granted under our LTIP in substitution for similar awards held for individuals who become eligible persons as a result of a merger, consolidation or acquisition of another entity by or with us or one of our affiliates.

153

Performance Awards. A performance award is a right to receive all or part of an award granted under our LTIP based upon performance conditions specified by the Plan Administrator. The Plan Administrator will determine the period over which certain specified company or individual goals or objectives must be met. The performance award may be paid in cash, common stock, other awards or other property, in the discretion of the Plan Administrator.

Tax Withholding. The Plan Administrator will determine, in its sole discretion, the form of payment acceptable to satisfy a participant’s obligations with respect to withholding taxes and other tax obligations relating to an award, including, without limitation, the delivery of cash or cash equivalents, common stock (including previously owned shares, net settlement, broker-assisted sale or other cashless withholding or reduction of the amount of shares of our common stock otherwise issuable or delivered pursuant to the award), other property or any other legal consideration that the Plan Administrator deems appropriate.

Change in Control. Upon a “change in control” (as defined in our LTIP), the Plan Administrator may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the Plan Administrator deems appropriate to reflect the change in control.

Other Adjustments. In the case of (i) a subdivision or consolidation of our common stock (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification, or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange or other relevant change in capitalization of our equity, then a corresponding and proportionate adjustment shall be made in accordance with the terms of our LTIP, as appropriate, with respect to the maximum number of shares available under our LTIP, the number of shares that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.

Termination of Employment or Service. The consequences of the termination of a participant’s employment, consulting arrangement, or membership on the board of directors will be determined by the Plan Administrator in the terms of the relevant award agreement.

Awards To Be Granted Following This Offering. Following the closing of this offering, we expect that the Plan Administrator will grant awards under our LTIP consisting of an aggregate of shares of restricted stock to certain of our executive officers, as further described in “—Narrative Disclosures—Compensation Following This Offering—IPO Bonuses.” Other than such awards, we do not currently anticipate that the Plan Administrator will grant additional awards under our LTIP during the remainder of 2016.

154

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common stock that, upon the consummation of the Corporate Reorganization and this offering, will be owned by:

•

each person known to us to beneficially own more than 5% of any class of our outstanding common stock;

•

each director, director nominee and named executive officer; and

•

all of our directors, director nominees and named executive officers as a group.

Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective 5% or more stockholders, directors, director nominees or named executive officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o 9805 Katy Freeway, Suite 400, Houston, TX 77024.

WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings were created in connection with this offering to serve as holding companies for the direct or indirect interests of the Existing Owners following our Corporate Reorganization. Each of the members of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, including our executive officers, will have an indirect interest in the shares of common stock sold by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. Prior to the completion of our Corporate Reorganization, the direct or indirect ownership interests of our directors and executive officers were represented by limited liability company interests in WildHorse and Esquisto.

The underwriters have an option to purchase a maximum of shares from us to cover over-allotments of shares. The table below assumes no exercise of such option unless otherwise indicated.


Name of Beneficial Owner	Shares Beneficially Owned
Name of Beneficial Owner	Number	Percentage
5% Stockholders:
WHR Holdings, LLC(1)
Esquisto Holdings, LLC(2)
WHE AcqCo. Holdings, LLC(3)
Directors, Director Nominees and Named Executive Officers:
Jay C. Graham
Anthony Bahr
Steve Habachy
Richard D. Brannon
Scott A. Gieselman
David W. Hayes
Tony R. Weber
Jonathan M. Clarkson
Directors, Director Nominees and Named Executive Officers as a Group (8 Persons)

(1)

The board of managers of WildHorse Holdings has voting and dispositive power over these shares. The board of managers of WildHorse Holdings consists of Jay C. Graham (our Chief Executive Officer and Chairman of our board of directors), Anthony Bahr (our President and one of our directors), and Scott A. Gieselman, David W. Hayes and Tony R. Weber (each of which is one of our directors). None of such persons individually has voting and dispositive power over these shares, and the board of managers of WildHorse Holdings acts by majority vote and thus each such person is not deemed to beneficially own the shares held by WildHorse Holdings. Immediately following consummation of the

155

Corporate Reorganization, (i) WildHorse Investment Holdings will own 100% of the capital interests in WildHorse Holdings and (ii) NGP X US Holdings, L.P. (“NGP X US Holdings”) will own 90.3% of WildHorse Investment Holdings, and certain members of our management team will own the remaining 9.7%. As a result, NGP X US Holdings may be deemed to indirectly beneficially own the shares held by WildHorse Holdings. NGP X US Holdings disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. NGP X Holdings GP, L.L.C. (the sole general partner of NGP X US Holdings), NGP Natural Resources X, L.P. (the sole member of NGP X Holdings GP, L.L.C.), G.F.W. Energy X, L.P. (the sole general partner of NGP Natural Resources X, L.P.) and GFW X, L.L.C. (the sole general partner of G.F.W. Energy X, L.P.) may each be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares. GFW X, L.L.C. has delegated full power and authority to manage NGP X US Holdings to NGP Energy Capital Management, L.L.C. (“NGP ECM”) and accordingly, NGP ECM may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Tony R. Weber and Chris Carter are the managing partners of NGP ECM. In addition, Craig Glick and Christopher Ray are Partners of NGP ECM. Although none of Messrs. Carter, Weber, Glick or Ray individually has voting or dispositive power over these shares, such individual may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Each of Messrs. Carter, Weber, Glick and Ray disclaims beneficial ownership of these shares except to the extent of his respective pecuniary interest therein. The number of shares reflected in the table above as beneficially owned by WildHorse Holdings does not include shares held by Esquisto Holdings or Acquisition Co. Holdings that are subject to the terms of the stockholders’ agreement. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.”

(2)

The board of managers of Esquisto Holdings has voting and dispositive power over these shares. The board of managers of Esquisto Holdings consists of Jay C. Graham (our Chief Executive Officer and Chairman of our board of directors), Anthony Bahr (our President and one of our directors), and Scott A. Gieselman, David W. Hayes and Tony R. Weber (each of which is one of our directors). None of such persons individually has voting and dispositive power over these shares, and the board of managers of Esquisto Holdings acts by majority vote and thus each such person is not deemed to beneficially own the shares held by Esquisto Holdings. Immediately following consummation of the Corporate Reorganization, (i) Esquisto Investment Holdings will own 100% of the capital interests in Esquisto Holdings, and the board of managers of Esquisto Investment Holding consists of Richard Brannon (one of our directors), Mike Hoover, Bruce Selkirk, Brian Minnehan, Mr. Hayes, David R. Albin and Craig Glick, and (ii) NGP IX US Holdings, L.P. (“NGP IX US Holdings”) and NGP XI US Holdings, L.P. (“NGP XI US Holdings”) directly and indirectly will own 27.6% and 62.4% of Esquisto Investment Holdings, respectively, and certain members of Esquisto’s management team will own the remaining 10.0%. As a result, NGP IX US Holdings and NGP XI US Holdings may be deemed to indirectly beneficially own the shares held by Esquisto Holdings. Each of NGP IX US Holdings and NGP XI US Holdings disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. NGP IX Holdings GP, L.L.C. (the sole general partner of NGP IX US Holdings), NGP XI Holdings GP, L.L.C. (the sole general partner of NGP XI US Holdings), NGP Natural Resources IX, L.P. (the sole member of NGP IX Holdings GP, L.L.C.), NGP Natural Resources XI, L.P. (the sole member of NGP XI Holdings GP, L.L.C.), G.F.W. Energy IX, L.P. (the sole general partner of NGP Natural Resources IX, L.P.), G.F.W. Energy XI, L.P. (the sole general partner of NGP Natural Resources XI, L.P.), GFW IX, L.L.C. (the sole general partner of G.F.W. Energy IX, L.P.) and GFW XI, L.L.C. (the sole general partner of G.F.W. Energy XI, L.P.) may each be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares. GFW IX, L.L.C. and GFW XI, L.L.C. have delegated full power and authority to manage NGP IX US Holdings and NGP XI US Holdings to NGP ECM and accordingly, NGP ECM may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Mr. Weber and Chris Carter are the managing partners of NGP ECM. In addition, Craig Glick and Christopher Ray are Partners of NGP ECM. Although none of Messrs. Carter, Weber, Glick or Ray has voting or dispositive power over these shares, such individual may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of

156

these shares. Each of Messrs. Carter, Weber, Glick and Ray disclaims beneficial ownership of these shares except to the extent of his respective pecuniary interest therein. The number of shares reflected in the table above as beneficially owned by Esquisto Holdings does not include shares held by WildHorse Holdings or Acquisition Co. Holdings that are subject to the terms of the stockholders’ agreement. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.”

(3)

The board of managers of Acquisition Co. Holdings has voting and dispositive power over these shares. The board of managers of Acquisition Co. Holdings consists of Jay C. Graham (our Chief Executive Officer and Chairman of our board of directors), Anthony Bahr (our President and one of our directors), and Scott A. Gieselman, David W. Hayes and Tony R. Weber (each of which is one of our directors). None of such persons individually has voting and dispositive power over these shares, and the board of managers of Acquisition Co. Holdings acts by majority vote and thus each such person is not deemed to beneficially own the shares held by Acquisition Co. Holdings. NGP XI US Holdings may be deemed to indirectly beneficially own the shares held by Acquisition Co. Holdings. NGP XI US Holdings disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. NGP XI Holdings GP, L.L.C. (the sole general partner of NGP XI US Holdings), NGP Natural Resources XI, L.P. (the sole member of NGP XI Holdings GP, L.L.C.), G.F.W. Energy XI, L.P. (the sole general partner of NGP Natural Resources XI, L.P.) and GFW XI, L.L.C. (the sole general partner of G.F.W. Energy XI, L.P.) may each be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares. GFW XI, L.L.C. has delegated full power and authority to manage NGP XI US Holdings to NGP ECM and accordingly, NGP ECM may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Mr. Weber and Chris Carter are the managing partners of NGP ECM. In addition, Craig Glick and Christopher Ray are Partners of NGP ECM. Although none of Messrs. Carter, Weber, Glick or Ray has voting or dispositive power over these shares, such individual may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Each of Messrs. Carter, Weber, Glick and Ray disclaims beneficial ownership of these shares except to the extent of his respective pecuniary interest therein. The number of shares reflected in the table above as beneficially owned by Acquisition Co. Holdings does not include shares held by WildHorse Holdings or Esquisto Holdings that are subject to the terms of the stockholders’ agreement. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.”

157

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Historical Transactions with Affiliates

Corporate Reorganization

As described in “Prospectus Summary—Corporate Reorganization,” in connection with this offering, we will complete certain reorganization transactions pursuant to which we will acquire all of the interests in WildHorse, Esquisto and Acquisition Co. owned by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively, in exchange for shares, shares and shares, respectively, of our common stock.

Related Party Transactions prior to the Corporate Reorganization

WildHorse . During 2014 and 2015, WildHorse issued promissory notes in favor of WildHorse’s management to fund future capital commitments. As of December 31, 2015 and 2014, promissory note advances outstanding to WildHorse’s management were $2.4 million and $1.7 million, respectively. Promissory note advances carry an interest rate of 2.5%. In 2015 and 2014 $0.1 million and $0.2 million in interest was accrued to the promissory notes, respectively. In 2015 and 2014, management paid $0.1 million and $0.3 million of promissory note interest, respectively. These promissory notes have been repaid and terminated.

WildHorse and WildHorse Resources, LLC (“WHR”), an entity formerly under common control with WildHorse, entered into a Management Agreement in August 2013 pursuant to which WHR provided certain administrative and land services to WildHorse. Further, on August 8, 2013, WildHorse and WHR entered into an Asset and Cost Sharing Agreement where, among other things, WildHorse and WHR agreed to share certain general and administrative costs. As a result of these agreements, WildHorse made net payments of $5.0 million to WHR in 2014.

On June 18, 2014, (i) the Management Agreement and the Asset Cost Sharing Agreement were terminated, (ii) WildHorse purchased WHRM from WHR for $0.2 million and (iii) WildHorse, through WHRM, began providing accounting and operating transition services to WHR, including administrative and land services, pursuant to the Management Services Agreement.

As a result of the Management Services Agreement, WildHorse made $57.6 million in net payments to WHR in 2015 but received net payments of $53.0 million from WHR and its affiliates in 2014. WildHorse was owed $0.0 million and $1.6 million, net, as of December 31, 2015 and 2014, respectively. On February 25, 2015, the Management Services Agreement was terminated effective March 1, 2015.

During the year ended December 31, 2015, WildHorse made payments of $1.0 million to Cretic Energy Services, LLC, a NGP affiliated company, for services related to drilling and completion activities.

Esquisto . During 2015 and 2014, Esquisto accrued $4.3 million and $2.1 million, respectively, as general and administrative expenses payable to its members, who historically have managed Esquisto. These liabilities have been recorded on the accompanying balance sheets as long-term notes payable to members. They will accrue interest at the Applicable Federal Rate beginning in 2017 if not paid in full and be subordinate to all other bank debt.

Esquisto paid Petromax Operating Company, Inc. (“Petromax”), who served as the named operator of, and provided certain operational services for, the majority of Esquisto’s wells, $981,000 and $218,000 during 2015 and 2014, respectively, 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. Petromax is owned 33% by Mike Hoover, the Chief Operating Officer of Esquisto, who also owns indirectly approximately 6% of Esquisto.

158

Esquisto paid Calbri Energy, Inc. $380,000 and $49,000 in 2015 and 2014, respectively, for completion consulting services. Calbri Energy, Inc. owned a less than 1% membership interest in Esquisto as of December 31, 2015.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement with WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

Demand Rights

At any time after the 180 day lock-up period, as described in “Underwriting (Conflicts of Interest),” and subject to the limitations set forth below, each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (or their permitted transferees) will have the right to require us by written notice to prepare and file a registration statement registering the offer and sale of a certain number of their shares of our common stock. Generally, we are required to provide notice of the request to certain other holders of our common stock who may, in certain circumstances, participate in the registration. Subject to certain exceptions, we will not be obligated to effect a demand registration within 90 days after the closing of any underwritten offering of shares of our common stock. Further, we are not obligated to effect more than a total of four demand registrations for each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings.

We will also not be obligated to effect any demand registration in which the anticipated aggregate offering price for our common stock included in such offering is less than $30 million. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. We will be required to use reasonable best efforts to maintain the effectiveness of any such registration statement until the earlier of (i) 180 days (or two years in the case of a shelf registration statement) after the effective date thereof or (ii) the date on which all shares covered by such registration statement have been sold (subject to certain extensions).

In addition, each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (or their permitted transferees) will have the right to require us, subject to certain limitations, to effect a distribution of any or all of their shares of our common stock by means of an underwritten offering. In general, any demand for an underwritten offering (other than the first requested underwritten offering made in respect of a prior demand registration and other than a requested underwritten offering made concurrently with a demand registration) shall constitute a demand request subject to the limitations set forth above.

Piggyback Rights

Subject to certain exceptions, if at any time we propose to register an offering of common stock or conduct an underwritten offering, whether or not for our own account, then we must notify WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (or their permitted transferees) of such proposal to allow them to include a specified number of their shares of our common stock in that registration statement or underwritten offering, as applicable.

Conditions and Limitations; Expenses

These registration rights will be subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.

159

Stockholders’ Agreement

In connection with this offering, we will enter into a stockholders’ agreement with WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. Among other things, the stockholders’ agreement will provide the right to designate nominees to our board of directors as follows:

•

so long as WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings collectively own greater than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate up to three nominees to our board of directors

•

so long as WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings collectively own greater than 35% of our common stock but less than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate two nominees to our board of directors;

•

so long as WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings collectively own greater than 15% of our common stock but less than 35% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors and can nominate a third nominee by agreement between them;

•

so long as WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings collectively own greater than 5% but less than 15% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors; and

•

once WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings collectively own less 5% of our common stock, WildHorse Holdings and Esquisto Holdings will not have any board designation rights.

Pursuant to the stockholders’ agreement we, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will be required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by WildHorse Holdings and Esquisto Holdings.

In addition, the stockholders’ agreement will provide that for so long as WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings and their affiliates own at least 15% of the outstanding shares of our common stock, WildHorse Holdings and Esquisto Holdings will have the right to cause any committee of our board of directors to include in its membership at least one director designated by WildHorse Holdings or Esquisto Holdings, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to WildHorse Holdings and Esquisto Holdings to designate directors are additive to and not intended to limit in any way the rights that WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings or any of their affiliates may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the DGCL.

Transition Services Agreement

Upon the closing of this offering, we will enter into a transition services agreement with CH4 Energy IV, LLC, PetroMax Operating Co., Inc. and Crossing Rocks Energy, LLC (affiliates of Esquisto and, collectively, the “Service Providers”), pursuant to which the Service Providers will provide certain engineering, land, operating and financial services to us for six months relating to our Eagle Ford Acreage. In exchange for such services, we will pay a monthly management fee to the Service Providers.

The Service Providers do not have a termination right under the transition services agreement. We may terminate the transition services agreement at any time by providing 30-days prior written notice to the Service Providers. The transition services agreement may only be assigned by a party with each other party’s consent. NGP and certain former management members of Esquisto own the Service Providers.

160

Procedures for Approval of Related Party Transactions

Prior to the closing of this offering, we have not maintained a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

•

any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

•

any person who is known by us to be the beneficial owner of more than 5% of our common stock;

•

any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and

•

any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

We anticipate that our board of directors will adopt a related party transactions policy prior to the completion of this offering. The policy and procedures for reviewing related party transactions will not be formally stated, but will be derived from the Code of Business Conduct and Ethics and the charter of the Audit Committee. Under its charter, the Audit Committee will be responsible for reviewing all material facts of all related party transactions, including transactions for which disclosure would be required under Item 404(a) of Regulation S-K.

161

DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering, the authorized capital stock of WildHorse Development will consist of 500,000,000 shares of common stock, $0.01 par value per share, of which shares will be issued and outstanding, and 50,000,000 shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

The following summary of the capital stock and amended and restated certificate of incorporation and amended and restated bylaws of WildHorse Development does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our amended and restated certificate of incorporation and amended and restated bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.

Common Stock

Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of common stock are not entitled to vote on any amendment to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to our amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the DGCL. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably in proportion to the shares of common stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable.

The holders of common stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to common stock. In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets in proportion to the shares of common stock held by them that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock, if any.

Preferred Stock

Our amended and restated certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. Each class or series of preferred stock will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law

Some provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that could make the following transactions more difficult: acquisitions of us

162

by means of a tender offer, a proxy contest or otherwise or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

Section 203 of the DGCL prohibits a Delaware corporation, including those whose securities are listed for trading on the NYSE or the NASDAQ, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

•

the transaction is approved by the board of directors before the date the interested stockholder attained that status;

•

upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

•

on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

Under our amended and restated certificate of incorporation, we have elected not to be subject to the provisions of Section 203 of the DGCL.

Our Amended and Restated Certificate of Incorporation and Our Amended and Restated Bylaws

Provisions of our amended and restated certificate of incorporation and our amended and restated bylaws, which will become effective upon the closing of this offering, may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests. Therefore, these provisions could adversely affect the price of our common stock.

Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:

•

establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our amended and restated bylaws specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;

163

•

provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

•

provide that the authorized number of directors may be changed only by resolution of the board of directors;

•

provide that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

•

provide that our bylaws can be amended by the board of directors; and

•

at any time after the Sponsor Group no longer collectively owns or controls the voting of more than 50% of the outstanding shares of our common stock,

•

provide that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, 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);

•

provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);

•

provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding common stock (prior to such time, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding common stock);

•

provide that special meetings of our stockholders may only be called 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);

•

provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, other than directors which may be elected by holders of preferred stock, if any. This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for stockholders to replace a majority of the directors; and

•

provide that the affirmative vote of the holders of at least 75% of the voting power of all then outstanding common stock entitled to vote generally in the election of directors, voting together as a single class, shall be required to remove any or all of the directors from office and such removal may only be for cause.

164

Corporate Opportunity

Under our amended and restated certificate of incorporation, to the extent permitted by law:

•

NGP and its affiliates have the right to, and have no duty to abstain from, exercising such right to, conduct business with any business that is competitive or in the same line of business as us, do business with any of our clients or customers, or invest or own any interest publicly or privately in, or develop a business relationship with, any business that is competitive or in the same line of business as us;

•

if NGP or its affiliates acquire knowledge of a potential transaction that could be a corporate opportunity, it has no duty to offer such corporate opportunity to us; and

•

we have renounced any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities.

Forum Selection

Our amended and restated certificate of incorporation will provide 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:

•

any derivative action or proceeding brought on our behalf;

•

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;

•

any action asserting a claim against us arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws; or

•

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.

Our amended and restated certificate of incorporation will also provide that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and to have consented to, this forum selection provision. Although we believe these provisions will benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. The enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that this provision in our amended and restated certificate of incorporation is inapplicable or unenforceable.

Limitation of Liability and Indemnification Matters

Our amended and restated certificate of incorporation will limit the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

•

for any breach of their duty of loyalty to us or our stockholders;

•

for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

•

for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

•

for any transaction from which the director derived an improper personal benefit.

165

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our amended and restated bylaws will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated bylaws also will permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision that will be in our amended and restated certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

For a description of registration rights with respect to our common stock, see “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is Wells Fargo Shareowner Services.

Listing

We have been approved to list our common stock on the NYSE under the symbol “WRD.”

166

SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. Future sales of our common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our common stock prevailing from time to time. As described below, only a limited number of shares will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price of our common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

Upon the closing of this offering, we will have outstanding an aggregate of shares of common stock. Of these shares, all of the shares of common stock to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of common stock held by existing stockholders and the shares of common stock issued to the third-party sellers in the Rosewood Acquisition (based on the midpoint of the price range set forth on the cover page of this prospectus) will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our common stock (excluding the shares to be sold in this offering) that will be available for sale in the public market are as follows:

•

shares to be issued in connection with the Rosewood Acquisition (based on the midpoint of the price range set forth on the cover page of this prospectus) will be eligible for sale on the date of this prospectus or prior to 180 days after the date of this prospectus; and

•

shares will be eligible for sale upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus (subject to extension) and when permitted under Rule 144 or Rule 701.

Lock-up Agreements

We, all of our directors and executive officers and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings have agreed or will agree that, subject to certain exceptions and under certain conditions, for a period of 180 days after the date of this prospectus, we and they will not, without the prior written consent of Barclays Capital Inc., dispose of or hedge any shares or any securities convertible into or exchangeable for shares of our capital stock. See “Underwriting (Conflicts of Interest)” for a description of these lock-up provisions.

Rule 144

In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least sixth months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

167

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Rule 701

In general, under Rule 701 under the Securities Act, any of our employees, directors, officers, consultants or advisors who purchase or otherwise receive shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering are entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register shares issuable under our LTIP. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement may be made available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above. Following the completion of this offering, we expect to grant awards under our LTIP consisting of an aggregate of shares of restricted stock to certain officers. See “Executive Compensation—Narrative Disclosures—Compensation Following This Offering—IPO Bonuses.”

168

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

The following is a summary of the material U.S. federal income tax considerations related to the purchase, ownership and disposition of our common stock by a non-U.S. holder (as defined below), that holds our common stock as a “capital asset” (generally property held for investment). This summary is based on the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations, administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service (the “IRS”) with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.

This summary does not address all aspects of U.S. federal income taxation that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal gift or estate tax laws, any state, local or non-U.S. tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as (without limitation):

•

banks, insurance companies or other financial institutions;

•

tax-exempt or governmental organizations;

•

qualified foreign pension funds (or any entities all of the interests of which are held by a qualified foreign pension fund);

•

dealers in securities or foreign currencies;

•

traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;

•

persons subject to the alternative minimum tax;

•

partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein;

•

persons deemed to sell our common stock under the constructive sale provisions of the Code;

•

persons that acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

•

certain former citizens or long-term residents of the United States;

•

real estate investment trusts or regulated investment companies; and

•

persons that hold our common stock as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction.

PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR COMMON STOCK ARISING UNDER THE U.S. FEDERAL GIFT OR ESTATE TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.

Non-U.S. Holder Defined

For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our common stock that is not for U.S. federal income tax purposes a partnership or any of the following:

•

an individual who is a citizen or resident of the United States;

169

•

a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

•

an estate the income of which is subject to U.S. federal income tax regardless of its source; or

•

a trust (i) the administration of which is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person.

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, upon the activities of the partnership and upon certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our common stock to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership and disposition of our common stock by such partnership.

Distributions

We do not plan to make any distributions on our common stock for the foreseeable future. However, in the event we do make distributions of cash or property on our common stock, such distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See “—Gain on Disposition of Common Stock.” Subject to the withholding requirements under FATCA (as defined below) and with respect to effectively connected dividends, each of which is discussed below, any distribution made to a non-U.S. holder with respect to our common stock generally will be subject to U.S. withholding tax at a rate of 30% of the gross amount of the distribution unless an applicable income tax treaty provides for a lower rate. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide the applicable withholding agent with an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate.

Dividends paid to a non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a non-U.S. corporation, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.

Gain on Disposition of Common Stock

Subject to the discussion below under “—Additional Withholding Requirements under FATCA,” a non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

•

the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met;

170

•

the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or

•

our common stock constitutes a United States real property interest by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes.

A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.

A non-U.S. holder whose gain is described in the second bullet point above or, subject to the exceptions described in the next paragraph, the third bullet point above, generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include the gain described in the second bullet point above.

Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our common stock continues to be regularly traded on an established securities market, only a non-U.S. holder that actually or constructively owns, or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the common stock, more than 5% of our common stock will be taxable on gain realized on the disposition of our common stock as a result of our status as a USRPHC. If our common stock were not considered to be regularly traded on an established securities market during the calendar year in which the relevant disposition by a non-U.S. holder occurs, such holder (regardless of the percentage of stock owned) would be subject to U.S. federal income tax on a taxable disposition of our common stock (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from such disposition.

Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our common stock.

Backup Withholding and Information Reporting

Any dividends paid to a non-U.S. holder must be reported annually to the IRS and to the non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Payments of dividends to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN, IRS Form W-8BEN-E or other appropriate version of IRS Form W-8.

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN, IRS Form W-8BEN-E or other appropriate version of IRS Form W-8 and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our common stock effected outside the United States by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the holder is not a United States person and certain other conditions are met, or the non-U.S. holder

171

otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our common stock effected outside the United States by such a broker if it has certain relationships within the United States.

Backup withholding is not an additional tax. Rather, the U.S. income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Additional Withholding Requirements under FATCA

Sections 1471 through 1474 of the Code, and the Treasury regulations and administrative guidance issued thereunder (“FATCA”), impose a 30% withholding tax on any dividends paid on our common stock and on the gross proceeds from a disposition of our common stock (if such disposition occurs after December 31, 2018), in each case if paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are non-U.S. entities with U.S. owners); (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification identifying the direct and indirect substantial United States owners of the entity (in either case, generally on an IRS Form W-8BEN-E); or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes.

INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL GIFT AND ESTATE TAX LAWS AND ANY STATE, LOCAL OR NON-U.S. TAX LAWS AND TAX TREATIES.

172

INVESTMENT IN WILDHORSE RESOURCE DEVELOPMENT CORPORATION BY

EMPLOYEE BENEFIT PLANS

An investment in our common stock by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, restrictions imposed by Section 4975 of the Internal Revenue Code of 1986, as amended, or the Code, and/or provisions under certain other federal, state, local, and non-U.S. laws or regulations that are similar to such provisions of ERISA or the Code (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” may include, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities (“IRAs”) and entities whose underlying assets are considered to include “plan assets” of such plans, accounts or arrangements. Among other things, consideration should be given to:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws; and

•

whether, in making the investment, the employee benefit plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in our common stock is authorized by the appropriate governing instruments and is a proper investment for the employee benefit plan.

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the employee benefit plan. Certain statutory or administrative exemptions from the prohibited transaction rules under ERISA and the Code may be available to an employee benefit plan that is directly or indirectly purchasing our common stock.

In addition to considering whether the purchase of our common stock is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in our common stock, be deemed to own an undivided interest in our assets, with the result that our general partner may also be a fiduciary of the plan and our operations may be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under certain circumstances. Under these regulations, an entity’s underlying assets generally would not be considered to be “plan assets” if, among other things:

(1)

the equity interests acquired by the employee benefit plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are “freely transferable” (as defined in the applicable Department of Labor regulations) and are either registered pursuant to certain provisions of the federal securities laws or sold to the plan as part of a public offering under certain conditions;

(2)

the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(3)

there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any person or entity who has discretionary authority or control over our assets or who provides investment advice for any direct or indirect fee with respect to our assets, is held by the employee benefit plans referred to above (but not including governmental plans, foreign plans and certain church plans, in each case, as defined under ERISA).

173

The foregoing discussion is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. Plan fiduciaries contemplating a purchase of our common stock should consult with their own counsel regarding the consequences under ERISA, the Code and Similar Laws in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

174

UNDERWRITING (CONFLICTS OF INTEREST)

Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and BMO Capital Markets Corp. are acting as representatives of the underwriters and the book-running managers of this offering. Under the terms of an underwriting agreement, by and among us and the representatives, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the number of common stock shown opposite its name below:


Underwriters		Number of Shares
Barclays Capital Inc.
Merrill Lynch, Pierce, Fenner & Smith Incorporated
BMO Capital Markets Corp.
Citigroup Global Markets Inc.
Wells Fargo Securities, LLC
Guggenheim Securities, LLC
J.P. Morgan Securities LLC
Raymond James & Associates, Inc.
Piper Jaffray & Co.
Tudor, Pickering, Holt & Co. Securities, Inc.
Capital One Securities, Inc.
Comerica Securities, Inc.
Scotia Capital (USA) Inc.
Wunderlich Securities, Inc.

Total

The underwriting agreement provides that the underwriters’ obligation to purchase shares of common stock depends on the satisfaction of the conditions contained in the underwriting agreement including:

•

the obligation to purchase all of the shares of common stock offered hereby (other than those shares of common stock covered by their option to purchase additional shares as described below), if any of the shares are purchased;

•

the representations and warranties made by us to the underwriters are true;

•

there is no material change in our business or the financial markets; and

•

we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the shares.


	No Exercise	Full Exercise
Per Share	$	$
Total	$	$

We have agreed to reimburse the underwriters for fees and expenses related to any required review by the FINRA in an amount not greater than $15,000.

175

The representatives have advised us that the underwriters propose to offer the shares of common stock directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per share. After the offering, the representatives may change the offering price and other selling terms. Sales of shares outside of the United States may be made by affiliates of the underwriters.

The expenses of the offering that are payable by us are estimated to be approximately $ (excluding underwriting discounts and commissions).

Option to Purchase Additional Shares

We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement to purchase, from time to time, in whole or in part, up to an aggregate of shares from us at the public offering price less underwriting discounts and commissions. This option may be exercised to the extent the underwriters sell more than shares in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting Section.

Lock-Up Agreements

We, all of our directors and executive officers, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings have agreed that, for a period of 180 days after the date of this prospectus subject to certain limited exceptions as described below, we and they will not directly or indirectly, without the prior written consent of Barclays Capital Inc. (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of common stock (including, without limitation, shares of common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and shares of common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common stock (other than the stock and shares issued pursuant to employee benefit plans, qualified stock option plans, or other employee compensation plans existing on the date of this prospectus), or sell or grant options, rights or warrants with respect to any shares of common stock or securities convertible into or exchangeable for common stock, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of shares of common stock, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of common stock or other securities, in cash or otherwise, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of common stock or securities convertible, exercisable or exchangeable into common stock or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing. These restrictions do not apply to, among other things, the sale of the shares pursuant to the underwriting agreement.

Barclays Capital Inc., in its sole discretion, may release the common stock and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release common stock and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of shares of common stock and other securities for which the release is being requested and market conditions at the time. At least three business days before the effectiveness of any release or waiver of any of the restrictions described above with respect to an officer or director of the Company, Barclays Capital Inc. will notify us of the impending release or waiver and we have agreed to announce the impending release or waiver by press release through a major news service at least two business days before the effective date of the release or waiver, except where the release or waiver is effected solely to permit a transfer of common stock that is not for consideration and where the transferee has agreed in writing to be bound by the same terms as the lock-up agreements described above to the extent and for the duration that such terms remain in effect at the time of transfer.

176

Offering Price Determination

Prior to this offering, there has been no public market for our common stock. The initial public offering price was negotiated between the representatives and us. In determining the initial public offering price of our common stock, the representatives considered:

•

the history and prospects for the industry in which we compete;

•

our financial information;

•

the ability of our management and our business potential and earning prospects;

•

the prevailing securities markets at the time of this offering; and

•

the recent market prices of, and the demand for, publicly traded shares of generally comparable companies.

Neither we nor the underwriters can assure investors that an active trading market will develop for the shares, or that the shares will trade in the public market at or above the initial offering price.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common stock, in accordance with Regulation M under the Exchange Act:

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•

A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by either exercising their option to purchase additional shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

•

Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions.

•

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

177

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result, the price of the common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common stock. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Listing on the NYSE

We have been approved to list our common stock on the NYSE under the symbol “WRD.”

Stamp Taxes

If you purchase shares of common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Conflicts of Interest

An affiliate of each of Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and Comerica Securities, Inc. is a lender under the WildHorse revolving credit facility and/or the Esquisto revolving credit facility and will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings under such credit facilities. Therefore, each of Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and Comerica Securities, Inc. is deemed to have a conflict of interest within the meaning of FINRA Rule 5121. Accordingly, this offering is being conducted in accordance with Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus. Barclays Capital Inc. has agreed to act as a qualified independent underwriter for this offering and to undertake the legal responsibilities and liabilities of an underwriter under the Securities Act, specifically including those inherent in Section 11 thereof. Barclays Capital Inc. will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify Barclays Capital Inc. against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act.

178

Pursuant to Rule 5121, each of Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and Comerica Securities, Inc. will not confirm any sales to any account over which it exercises discretionary authority without the specific written approval of the account holder. See “Use of Proceeds” for additional information.

Other Relationships

The underwriters and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for the issuer and its affiliates, for which they received or may in the future receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and certain of their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of the issuer or its affiliates. If the underwriters or their affiliates have a lending relationship with us, certain of those underwriters or their affiliates routinely hedge, and certain other of those underwriters or their affiliates may hedge, their credit exposure to us consistent with their customary risk management policies. Typically, the underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities or the securities of our affiliates, including potentially the shares of common stock offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the shares of common stock offered hereby. The underwriters and certain of their affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments. Affiliates of certain of the underwriters act as lenders and/or agents under the Esquisto revolving credit facility and the WildHorse revolving credit facility. Affiliates of the underwriters who are lenders under the Esquisto revolving credit facility and/or the WildHorse revolving credit facility may receive a portion of the net proceeds from this offering.

Selling Restrictions

This prospectus does not constitute an offer to sell to, or a solicitation of an offer to buy from, anyone in any country or jurisdiction (i) in which such an offer or solicitation is not authorized, (ii) in which any person making such offer or solicitation is not qualified to do so or (iii) in which any such offer or solicitation would otherwise be unlawful. No action has been taken that would, or is intended to, permit a public offer of the shares of common stock or possession or distribution of this prospectus or any other offering or publicity material relating to the shares of common stock in any country or jurisdiction (other than the United States) where any such action for that purpose is required. Accordingly, each underwriter has undertaken that it will not, directly or indirectly, offer or sell any shares of common stock or have in its possession, distribute or publish any prospectus, form of application, advertisement or other document or information in any country or jurisdiction except under circumstances that will, to the best of its knowledge and belief, result in compliance with any applicable laws and regulations and all offers and sales of shares of common stock by it will be made on the same terms.

European Economic Area

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”) an offer to the public of any common stock which are the subject of the offering contemplated herein may not be made in that Relevant Member State, except that an offer to the

179

public in that Relevant Member State of any common stock may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:

•

to legal entities which are qualified investors as defined under the Prospectus Directive;

•

by the underwriters to fewer than 100, or, if the Relevant Member State has implemented the relevant provisions of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the representatives of the underwriters for any such offer; or

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of common stock shall result in a requirement for us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive.

Each person in a Relevant Member State who receives any communication in respect of, or who acquires any common stock under, the offers contemplated here in this prospectus will be deemed to have represented, warranted and agreed to and with each underwriter and us that:

•

it is a qualified investor as defined under the Prospectus Directive; and

•

in the case of any common stock acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (i) the common stock acquired by it in the offering have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than qualified investors, as that term is defined in the Prospectus Directive, or in the circumstances in which the prior consent of the representatives of the underwriters has been given to the offer or resale or (ii) where common stock have been acquired by it on behalf of persons in any Relevant Member State other than qualified investors, the offer of such common stock to it is not treated under the Prospectus Directive as having been made to such persons.

For the purposes of this representation and the provision above, the expression an “offer of common stock to the public” in relation to any common stock in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any common stock to be offered so as to enable an investor to decide to purchase or subscribe for the common stock, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State, the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in each Relevant Member State and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.

United Kingdom

This prospectus has only been communicated or caused to have been communicated and will only be communicated or caused to be communicated as an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act of 2000 (the “FSMA”)) as received in connection with the issue or sale of the common stock in circumstances in which Section 21(1) of the FSMA does not apply to us. All applicable provisions of the FSMA will be complied with in respect to anything done in relation to the common stock in, from or otherwise involving the United Kingdom.

Notice to Canadian Residents

This prospectus constitutes an “exempt offering document” as defined in and for the purposes of applicable Canadian securities laws. No prospectus has been filed with any securities commission or similar regulatory authority in Canada in connection with the offer and sale of shares of our common stock. No securities

180

commission or similar regulatory authority in Canada has reviewed or in any way passed upon this prospectus or on the merits of shares of our common stock and any representation to the contrary is an offence.

Canadian investors are advised that this prospectus has been prepared in reliance on section 3A.3 of National Instrument 33-105 Underwriting Conflicts (“NI 33-105”). Pursuant to section 3A.3 of NI 33-105, this prospectus is exempt from the requirement to provide investors with certain conflicts of interest disclosure pertaining to “connected issuer” and/or “related issuer” relationships as would otherwise be required pursuant to subsection 2.1(1) of NI 33-105.

Resale Restrictions

The offer and sale of shares of our common stock in Canada is being made on a private placement basis only and is exempt from the requirement to prepare and file a prospectus under applicable Canadian securities laws. Any resale of shares of our common stock acquired by a Canadian investor in this offering must be made in accordance with applicable Canadian securities laws, which may vary depending on the relevant jurisdiction, and which may require resales to be made in accordance with Canadian prospectus requirements, a statutory exemption from the prospectus requirements, in a transaction exempt from the prospectus requirements or otherwise under a discretionary exemption from the prospectus requirements granted by the applicable local Canadian securities regulatory authority. These resale restrictions may under certain circumstances apply to resales of shares of our common stock outside of Canada.

Representations of Purchasers

Each Canadian investor who purchases shares of our common stock will be deemed to have represented to us and to each dealer from whom a purchase confirmation is received, as applicable, that the investor (i) is purchasing as principal, or is deemed to be purchasing as principal in accordance with applicable Canadian securities laws, for investment only and not with a view to resale or redistribution; (ii) is an “accredited investor” as such term is defined in section 1.1 of National Instrument 45-106 Prospectus Exemptions (“NI 45-106”) or, in Ontario, as such term is defined in section 73.3(1) of the Securities Act (Ontario); and (iii) is a “permitted client” as such term is defined in section 1.1 of National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations .

Taxation and Eligibility for Investment

Any discussion of taxation and related matters contained in this prospectus does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a Canadian investor when deciding to purchase shares of our common stock and, in particular, does not address any Canadian tax considerations. No representation or warranty is hereby made as to the tax consequences to a resident, or deemed resident, of Canada of an investment in shares of our common stock or with respect to the eligibility of shares of our common stock for investment by such investor under relevant Canadian federal and provincial legislation and regulations.

Rights of Action for Damages or Rescission

Securities legislation in certain of the Canadian jurisdictions provides certain purchasers of securities pursuant to an offering memorandum, including where the distribution involves an “eligible foreign security” as such term is defined in Ontario Securities Commission Rule 45-501 Ontario Prospectus and Registration Exemptions and in Multilateral Instrument 45-107 Listing Representation and Statutory Rights of Action Disclosure Exemptions , as applicable, with a remedy for damages or rescission, or both, in addition to any other rights they may have at law, where the offering memorandum, or other offering document that constitutes an offering memorandum, and any amendment thereto, contains a “misrepresentation” as defined under applicable Canadian securities laws. These remedies, or notice with respect to these remedies, must be exercised or

181

delivered, as the case may be, by the purchaser within the time limits prescribed under, and are subject to limitations and defences under, applicable Canadian securities legislation. In addition, these remedies are in addition to and without derogation from any other right or remedy available at law to the investor.

Language of Documents

Upon receipt of this prospectus, each Canadian investor hereby confirms that it has expressly requested that all documents evidencing or relating in any way to the sale of shares of our common stock described herein (including for greater certainty any purchase confirmation or any notice) be drawn up in the English language only. Par la réception de ce document, chaque investisseur canadien confirme par les présentes qu’il a expressément exigé que tous les documents faisant foi ou se rapportant de quelque manière que ce soit à la vente des valeurs mobilières décrites aux présentes (incluant, pour plus de certitude, toute confirmation d’achat ou tout avis) soient rédigés en anglais seulement.

182

LEGAL MATTERS

The validity of our common stock offered by this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The consolidated financial statements of WildHorse Resources II, LLC as of December 31, 2015 and 2014, and for the years then ended, have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Esquisto Resources II, LLC at December 31, 2015 and 2014, and for the year ended December 31, 2015 and the period from June 20, 2014 (Inception) to December 31, 2014, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses, which comprise the revenues and direct operating expenses of certain oil and gas properties of the members of Esquisto Resources II, LLC prior to formation of and contribution to Esquisto (the “Pre-Esquisto Properties working interest”) for the period from January 1, 2014 to June 20, 2014, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses, which comprise the revenues and direct operating expenses of certain oil and gas properties of Comstock Resources, Inc. acquired by Esquisto Resources II, LLC (the “Comstock Properties working interest”) for the seven month period ended July 31, 2015 and the year ended December 31, 2014, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses, which comprise the revenues and direct operating expenses of certain oil and gas properties of Clayton Williams Energy, Inc. under contract to be acquired by WHE AcqCo., LLC for the nine months ended September 30, 2016 and the years ended December 31, 2015 and 2014, appearing in this prospectus and registration statement have been audited by KPMG LLP, independent auditors, as set forth in its report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Estimates of WildHorse’s oil and natural gas reserves and related future net cash flows related to WildHorse’s properties as of December 31, 2014, December 31, 2015 and June 30, 2016 included herein and elsewhere in the registration statement were based the proved reserves estimates prepared by WildHorse and audited by independent petroleum engineers, Cawley, Gillespie & Associates. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

Estimates of Esquisto’s oil and natural gas reserves and related future net cash flows related to Esquisto’s properties as of December 31, 2014, December 31, 2015 and June 30, 2016 included herein and elsewhere in the registration statement were based upon reserve reports prepared by independent petroleum engineers, Cawley, Gillespie & Associates. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

183

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov .

As a result of this offering, we will become subject to full information requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.

184

INDEX TO FINANCIAL STATEMENTS


	Page
WildHorse Resource Development Corporation
Unaudited Pro Forma Combined Financial Statements
Introduction		F-3
Unaudited Pro Forma Combined Balance Sheet as of September 30, 2016		F-6
Unaudited Pro Forma Combined Statement of Operations for the Nine Months Ended September 30, 2016		F-7
Unaudited Pro Forma Combined Statement of Operations for the Nine Months Ended September 30, 2015		F-8
Unaudited Pro Forma Combined Statement of Operations for the Years Ended December 31, 2015		F-9
Unaudited Pro Forma Combined Statement of Operations for the Years Ended December 31, 2014		F-10
Notes to Unaudited Pro Forma Combined Financial Statements		F-11
Audited Balance Sheet
Report of Independent Registered Public Accounting Firm		F-25
Balance Sheet as of August 4, 2016		F-26
Notes to Balance Sheet		F-27

WildHorse Resources II, LLC (Predecessor)
Audited Consolidated Financial Statements
Independent Auditors Report		F-28
Consolidated Balance Sheets as of December 31, 2015 and 2014		F-29
Consolidated Statements of Operations for the Year Ended December 31, 2015 and 2014		F-30
Consolidated Statements of Changes in Members’ Equity for the Year Ended December 31, 2015 and 2014		F-31
Consolidated Statements of Cash Flows for the Year Ended December 31, 2015 and 2014		F-32
Notes to Consolidated Financial Statements		F-33
Unaudited Consolidated Financial Statements
Unaudited Consolidated Balance Sheets as of December 31, 2015 and September 30, 2016		F-54
Unaudited Consolidated Statements of Operations for the Nine Months Ended September 30, 2016 and 2015		F-55
Unaudited Consolidated Statements of Members’ Equity for the period from December 31, 2015 to September 30, 2016		F-56
Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2016 and 2015		F-57
Notes to Consolidated Financial Statements		F-58

Esquisto Resources II, LLC
Audited Consolidated Financial Statements
Report of Independent Auditors		F-66
Consolidated Balance Sheets as of December 31, 2015 and 2014		F-67
Consolidated Statements of Operations for the Year Ended December 31, 2015 and the period from June 20, 2014 (Inception) to December 31, 2014		F-68
Consolidated Statements of Changes in Members’ Equity for the Year Ended December 31, 2015 and the period from June 20, 2014 (Inception) to December 31, 2014		F-69
Consolidated Statements of Cash Flows for the Year Ended December 31, 2015 and the period from June 20, 2014 (Inception) to December 31, 2014		F-70
Notes to Consolidated Financial Statements		F-71

F-1


	Page
Unaudited Consolidated Financial Statements
Audited Consolidated Balance Sheet as of December 31, 2015 and Unaudited Consolidated Balance Sheet as of September 30, 2016		F-94
Unaudited Consolidated Statements of Operations for the Nine Months Ended September 30, 2016 and 2015		F-95
Unaudited Consolidated Statement of Changes in Members’ Equity for the Nine Months Ended September 30, 2016 and Audited Combined Statement of Changes in Members’ Equity for the Year Ended December 31, 2015		F-96
Unaudited Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2016 and 2015		F-97
Notes to Consolidated Financial Statements		F-98

Initial Esquisto Assets
Audited Statement of Revenues and Direct Operating Expenses
Report of Independent Auditors		F-108
Statement of Revenues and Direct Operating Expenses for the period from January 1, 2014 through June 19, 2014		F-109
Notes to Statement of Revenues and Direct Operating Expenses		F-110

Comstock Assets
Audited Statements of Revenues and Direct Operating Expenses
Report of Independent Auditors		F-114
Statements of Revenues and Direct Operating Expenses for the Year Ended December 31, 2014 and the period from January 1, 2015 through July 31, 2015		F-115
Notes to Statements of Revenues and Direct Operating Expenses		F-116

Burleson North Assets
Audited Statements of Revenues and Direct Operating Expenses
Independent Auditors’ Report		F-121
Statements of Revenues and Direct Operating Expenses for the Nine Month Period Ended September 30, 2016 and the Years Ended December 31, 2015 and 2014		F-123
Notes to Statements of Revenues and Direct Operating Expenses		F-124

F-2

WildHorse Resource Development Corporation

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Introduction

WildHorse Resource Development Corporation (the “Company”) is a newly formed Delaware corporation that will be a holding company for WildHorse Resources II, LLC (“WildHorse” or the “Predecessor”), Esquisto Resources, LLC (“Esquisto”) and WHE Acq Co., LLC (“Acquisition Co.”), which will acquire the Burleson North Assets (as defined below) prior to or contemporaneously with the closing of this offering. The Company will be a growth-oriented, independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. The Company’s assets are characterized by concentrated acreage positions in Southeast Texas and North Louisiana with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. The unaudited pro forma combined statements of operations of the Company include pro forma adjustments to give effect to the following as if they had occurred on the dates indicated:

•

For the year ended December 31, 2014, the Corporate Reorganization and the contribution to Esquisto of the Initial Esquisto Assets (each as described below) as if they had been completed as of January 1, 2014;

•

For the nine months ended September 30, 2015, (i) the Corporate Reorganization, (ii) the Comstock Acquisition (as described below), (iii) the Burleson North Acquisition (as described below) and (iv) the Offering (as described below) and the application of the net proceeds therefrom as described in “Use of Proceeds” as if they had been completed as of January 1, 2015; and

•

For the year ended December 31, 2015, (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) the Offering and the application of the net proceeds therefrom as described in “Use of Proceeds” as if they had been completed as of January 1, 2015.

•

For the nine months ended September 30, 2016, (i) the Corporate Reorganization, (ii) the Burleson North Acquisition and (iii) the Offering and the application of the net proceeds therefrom as described in “Use of Proceeds” as if they had been completed as of January 1, 2015.

The unaudited pro forma combined balance sheet of the Company was prepared as of September 30, 2016 and includes pro forma adjustments to give effect to the Corporate Reorganization, the Offering and the Burleson North Acquisition, as if they had occurred on September 30, 2016. The pro forma combined statements of operations and balance sheet of the Company do not give any effect to (i) the Company’s acquisition from a third party of approximately 7,500 net acres, consisting primarily of additional working interests in the Company’s Lee County acreage contemporaneously with the Offering, and (ii) Esquisto’s acquisition of approximately 4,900 net acres in Burleson County in November 2016.

The Contribution of Initial Esquisto Assets . On June 20, 2014, oil and natural gas properties were contributed to Esquisto Resources, LLC in connection with the formation of Esquisto Resources, LLC (the “Initial Esquisto Assets”).

The Comstock Acquisition . On July 31, 2015, Esquisto Resources II, LLC acquired certain producing properties, undeveloped acreage and water assets from a wholly owned subsidiary of Comstock Resources, Inc. (the “Comstock Assets”).

The Burleson North Acquisition . In October 2016, Acquisition Co. entered into a purchase agreement with Clayton Williams Energy, Inc. to acquire 158,000 net acres of oil and gas properties located in the Eagle Ford Shale (the “Burleson North Assets”). Acquisition Co. expects to close the Burleson North Acquisition prior to or contemporaneously with the closing of this offering, using a portion of the proceeds from this offering to fund the purchase price.

F-3

The Corporate Reorganization . Contemporaneously with the closing of the Offering, (i) the current owners of WildHorse will exchange all of their interests in WildHorse for equivalent interests in WildHorse Investment Holdings, LLC (“WildHorse Investment Holdings”) and the current owners of Esquisto will exchange all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, LLC (“Esquisto Investment Holdings”), (ii) WildHorse Investment Holdings will contribute all of its interests in WildHorse to WHR Holdings, LLC (“WildHorse Holdings”), Esquisto Investment Holdings will contribute all of its interests in Esquisto to Esquisto Holdings, LLC (“Esquisto Holdings”) and the current owner of Acquisition Co. will contribute all of its interests in Acquisition Co. to Acquisition Co. Holdings, LLC (“Acquisition Co. Holdings”), (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will issue management incentive units to certain of our officers and employees and (iv) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will contribute all of the interests in WildHorse, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock (the “Corporate Reorganization”), which will be accounted for as a business combination of entities under common control. As a result of the Corporate Reorganization, WildHorse, Esquisto and Acquisition Co. Holdings will become direct, wholly owned subsidiaries of the Company. The unaudited pro forma combined financial statements have been prepared on the basis that, as a corporation, the Company will be subject to Subchapter C of the Internal Revenue Code of 1986, as amended, and, as a result, will be subject to U.S. federal and state income taxes at the entity level.

The Offering . In the offering contemplated by this prospectus (the “Offering”), the Company will issue and sell to the public million shares of common stock and apply the net proceeds from such issuance as described in “Use of Proceeds.” The gross proceeds from the sale of the common stock are expected to be $ million (based on an assumed initial public offering price of $ , the midpoint of the range set forth on the cover of this prospectus), net of underwriting discounts of $ million, other offering costs of $ million and $ million of debt issuance costs related to the establishment of the Company’s new revolving credit facility. In preparing the unaudited pro forma combined financial statements, the gross and net proceeds from the offering are assumed to be $650 million and $610.2 million, respectively.

The unaudited pro forma combined statements of operations of the Company were prepared based on (i) the 2015 and 2014 audited financial statements of the Predecessor and Esquisto, as included elsewhere in this prospectus; (ii) the September 30, 2016 and the September 30, 2015 unaudited financial statements of the Predecessor and Esquisto, as included elsewhere in this prospectus; (iii) the audited historical statements of revenues and direct operating expenses of the Initial Esquisto Assets, as included elsewhere in this prospectus; (iv) the audited historical statements of revenues and direct operating expenses of the Comstock Assets as included elsewhere in this prospectus; (v) the audited historical statements of revenues and direct operating expenses of the Burleson North Assets as included elsewhere in this prospectus; and (vi) certain pro forma adjustments reflected in the following pro forma financial statements.

The September 30, 2016 unaudited pro forma combined balance sheet of the Company was prepared based on the unaudited financial statements of the Predecessor and Esquisto as of September 30, 2016 and certain pro forma adjustments reflected in the following pro forma financial statements.

The pro forma data presented reflects events directly attributable to the above described transactions and certain assumptions that the Company believes are reasonable. The pro forma adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the pro forma assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma combined financial statements.

The unaudited pro forma combined financial statements and related notes are presented for illustrative purposes only. If the Offering and other transactions contemplated herein had occurred in the past, the Company’s operating results might have been materially different from those presented in the unaudited pro forma combined financial statements. The unaudited pro forma combined financial statements should not be

F-4

relied upon as an indication of operating results that the Company would have achieved if the Offering and other transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma statements of operations and should not be relied on as an indication of the future results the Company will have after the completion of the Offering and the other transactions contemplated by these unaudited pro forma combined financial statements.

The unaudited pro forma combined financial statements should be read in conjunction with the notes thereto and with the audited historical consolidated financial statements and related notes of the Predecessor and the audited combined historical financial statements of Esquisto, as well as the other audited historical statements of revenues and direct operating expenses, included elsewhere in this prospectus.

F-5

Unaudited Pro Forma Combined Balance Sheet

As of September 30, 2016

(in thousands)


	WildHorse Resources II, LLC Historical			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC			Burleson North Acquisition			Corporate Reorganization			Offering			Pro Forma
Assets
CURRENT ASSETS:
Cash and cash equivalents	$	1,336		$	115		$	(355,000	)(1)	$	—		$	610,200	(2)	$	11,226
														(233,500	)(3)
														(1,800	)(5)
														(9,625	)(3)
														(500	)(7)
Accounts receivable		11,564			11,570			—			—			—			23,134
Derivative instruments		571			—			—			—			—			571
Prepaid expenses		323			43			—			—			—			366
Deferred IPO Costs		587			1,044			—			—			(1,631	)(2)		—

Total current assets		14,381			12,772			(355,000	)		—			363,144			35,297
Property and equipment
Oil and natural gas properties		450,337			589,698			401,189	(1)		—			—			1,441,224
Other property and equipment		30,523			—			—			—			—			30,523
Accumulated depreciation, depletion and amortization		(105,754	)		(72,721	)		—			—			—			(178,475	)

Total property and equipment, net		375,106			516,977			401,189			—			—			1,293,272
Other noncurrent assets
Debt issuance costs		470			—			—			942	(4)		(1,412	)(5)		1,800
														1,800	(5)
Derivative instruments		148			—			—			—			—			148
Restricted cash		636			—			—			—			—			636
Water assets		—			1,188			—			(1,188	)(4)		—			—
Other noncurrent assets		249			—			—			1,188	(4)		—			1,437
Deferred income tax		—			—			—			—			—			—

Total other noncurrent assets		1,503			1,188			—			942			388			4,021

Total assets	$	390,990		$	530,937		$	46,189		$	942		$	363,532		$	1,332,590

Liabilities and members’ equity
Current liabilities
Accounts payable	$	8,081		$	23,202		$	—		$	—		$	—		$	31,283
Accounts payable—related party		—			—			—			—			—			—
Accrued liabilities		3,342			11,595			—			—			(1,631	)(2)		13,306
Derivative instruments		1,490			1,946			—			—			—			3,436
Asset retirement obligations		90			—			—			—			—			90

Total current liabilities		13,003			36,743			—			—			(1,631	)		48,115
Noncurrent liabilities
Long-term debt		108,500			124,058			—			942	(4)		(233,500	)(3)		—
Notes payable to members		—			9,625			—			—			(9,625	)(3)		—
Asset retirement obligations		6,940			300			1,189	(1)		—			—			8,429
Derivative instruments		332			2,159			—			—			—			2,491
Other noncurrent liabilities		1,619			—			—			—			—			1,619
Deferred income tax		—			1,509			—			130,602	(6)		(565	)(5)		131,546

Total noncurrent liabilities		117,391			137,651			1,189			131,544			(243,690	)		144,085

Total liabilities		130,394			174,394			1,189			131,544			(245,321	)		192,200

Accumulated deficit		(77,378	)		—			—			(2,262	)(4)		(847	)(5)		(80,487	)
Members’ equity		337,974			356,543			45,000	(1)		(130,602	)(6)		610,200	(2)		1,220,877
											2,262	(4)		(500	)(7)

Total liabilities and members’ equity	$	390,990		$	530,937		$	46,189		$	942		$	363,532		$	1,332,590

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

F-6

Unaudited Pro Forma Combined Statement of Operations

For the Nine Months Ended September 30, 2016

(in thousands)


	WildHorse Resources II, LLC Historical			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC			Burleson North Acquisition			Corporate Reorganization			Offering			Pro Forma
Operating revenues
Natural gas	$	25,273		$	2,475		$	1,812		$	—		$	—		$	29,560
Crude oil		2,971			48,737			34,571			—			—			86,279
Natural gas liquids		658			2,960			810			—			—			4,428
Gathering System Income		1,158			—			—			—			—			1,158

Total operating revenues		30,060			54,172			37,193			—			—			121,425

Operating expenses
Lease operating expenses		4,543			5,038			12,966			(682	)(1)		—			21,865
Gathering system operating expenses		99			—			—			—			—			99
Production and ad valorem taxes		1,843			2,529			3,546			682	(1)		—			8,600
Depreciation, depletion and amortization		27,305			33,197			19,017	(2)		—			—			79,519
Impairment of proved oil and gas properties		—			—			—			—			—			—
General and administrative		8,399			5,659			—			—			—			14,058
Exploration expense		8,973			2			—			—			—			8,975
(Gain) loss from derivative financial instruments		—			5,800			—			(5,800	)(1)		—			—

Total operating expenses		51,162			52,225			35,529			(5,800	)		—			133,116

(Loss) gain from operations		(21,102	)		1,947			1,664			5,800			—			(11,691	)

Other income (expense)
Interest expense		(2,732	)		(2,879	)		—			—			5,611	(3)		(1,539	)
														(270	)(3)
														(1,269	)(3)
Other income (expense)		(76	)		(353	)		—			—			—			(429	)
State deferred tax expense		—			(435	)		—			435	(1)		—			—
Gain (loss) on derivative instruments		(2,894	)		—			—			(5,800	)(1)		—			(8,694	)

Total other (expense) income		(5,702	)		(3,667	)		—			(5,365	)		4,072			(10,662	)

Net (loss) income before income taxes		(26,804	)		(1,720	)		1,664			435			4,072			(22,353	)

Income tax benefit (expense)		(15	)		—			(599	)(4)		11,634	(4)		(1,629	)(4)		8,956
											(435	)(1)

Net (loss) income	$	(26,819	)	$	(1,720	)	$	1,065		$	11,634		$	2,443		$	(13,397	)

Net (loss) income per common share (5)
Basic																$
Diluted																$
Weighted average common shares outstanding (5)
Basic
Diluted

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

F-7

Unaudited Pro Forma Combined Statement of Operations

For the Nine Months Ended September 30, 2015

(in thousands)


	WildHorse Resources II, LLC Historical			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC			Comstock Acquisition					Burleson North Acquisition					Corporate Reorganization					Offering					Pro Forma
Operating revenues
Natural gas	$	23,381		$	2,041		$	1,156				$	2,621				$	—				$	—				$	29,199
Crude oil		2,240			26,723			15,810					67,314					—					—					112,087
Natural gas liquids		1,100			1,938			1,069					962					—					—					5,069
Gathering System Income		—			—			—					—					—					—					—

Total operating revenues		26,721			30,702			18,035					70,897					—					—					146,355

Operating expenses
Lease operating expenses		6,178			4,304			1,118					15,205					(533	)	(1	)		—					26,272
Gathering system operating expenses		317			—			—					—					—					—					317
Production and ad valorem taxes		1,891			1,456			881					5,154					533		(1	)		—					9,915
Depreciation, depletion and amortization		17,516			20,653			6,083		(2	)		27,582		(2	)		—					—					71,834
Impairment of proved oil and gas properties		8,032			—			—					—					—					—					8,032
General and administrative		7,475			4,232			—					—					—					—					11,707
Exploration expense		14,306			206			—					—					—					—					14,512
(Gain) loss from derivative financial instruments		—			(1,116	)		—					—					1,116		(1	)		—					—

Total operating expenses		55,715			29,735			8,082					47,941					1,116					—					142,589

(Loss) gain from operations		(28,994	)		967			9,953					22,956					(1,116	)				—					3,766

Other income (expense)
Interest expense		(2,249	)		(3,074	)		(930	)	(6	)		—					—					6,253		(7	)		(1,539	)
																							(270	)	(7	)
																							(1,269	)	(7	)
Other income (expense)		9			(481	)		—					—					—					—					(472	)
State deferred tax expense		—			(478	)		—					—					478		(1	)		—					—
Gain on derivative instruments		6,063			—			—					—					1,116		(1	)		—					7,179

Total other gain (expense)		3,823			(4,033	)		(930	)				—					1,594					4,714					5,168

Net (loss) gain before income taxes		(25,171	)		(3,066	)		9,023					22,956					478					4,714					8,934

Income tax benefit (expense)		82			—			(3,248	)	(4	)		(8,264	)	(4	)		11,396		(4	)		(1,886	)	(4	)		(2,398	)
																		(478	)	(1	)
Net (loss) gain	$	(25,089	)	$	(3,066	)	$	5,775				$	14,692				$	11,396				$	2,828				$	6,536

Net (loss) income per common share (5)
Basic																											$
Diluted																											$
Weighted average common shares outstanding (5)
Basic
Diluted

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

F-8

Unaudited Pro Forma Combined Statement of Operations

For the Year Ended December 31, 2015

(in thousands, except per share data)


	WildHorse Resources II, LLC Historical			Esquisto Resources II, LLC			Comstock Acquisition				Burleson North Acquisition					Corporate Reorganization				Offering				Pro Forma
Operating revenues
Natural gas	$	30,556		$	2,975		$	1,156			$	3,376				$	—			$	—			$	38,063
Crude oil		3,305			42,376			15,810				81,123					—				—				142,614
Natural gas liquids		1,451			2,992			1,069				1,210					—				—				6,722
Gathering system income		314			—			—				—					—				—				314

Total operating revenues		35,626			48,343			18,035				85,709					—				—				187,713

Operating expenses
Lease operating expenses		8,606			6,509			1,118				19,817					(711	)	(1)		—				35,339
Gathering system operating expenses		914			—			—				—					—				—				914
Production and ad valorem taxes		2,666			2,275			881				6,458					711		(1)		—				12,991
Depreciation, depletion and amortization		25,526			32,312			6,083		(2)		35,088		(2	)		—				—				99,009
Impairment of proved oil and gas properties		9,312			—			—				—					—				—				9,312
General and administrative		10,567			5,671			—				—					373		(1)		—				16,611
Exploration expense		14,896			2,967			—				—					—				—				17,863
(Gain) loss from derivative financial instruments		—			(4,344	)		—				—					4,344		(1)		—				—

Total operating expenses		72,487			45,390			8,082				61,363					4,717				—				192,039

(Loss) income from operations		(36,861	)		2,953			9,953				24,346					(4,717	)			—				(4,326	)

Other income (expense)
Interest (expense) income		(2,576	)		(4,693	)		(930	)	(6)		—					—				8,199		(8)		(2,048	)
																					(360	)	(8)
																					(1,688	)	(8)
Other (expense) income		(45	)		(478	)		—				—					373		(1)		—				(150	)
State deferred tax expense		—			(691	)		—				—					691		(1)		—				—
Gain (loss) on derivative instruments		9,510			—			—				—					4,344		(1)		—				13,854

Total other income (expense)		6,889			(5,862	)		(930	)			—					5,408				6,151				11,656

Net (loss) income before income taxes		(29,972	)		(2,909	)		9,023				24,346					691				6,151				7,330

Income tax benefit (expense)		17			—			(3,248	)	(4)		(8,765	)	(4	)		13,461		(4)		(2,460	)	(4)		(1,686	)
																	(691	)	(1)

Net (loss) income	$	(29,955	)	$	(2,909	)	$	5,775			$	15,581				$	13,461			$	3,691			$	5,644

Net (loss) income per common share(5)
Basic																								$
Diluted																								$
Weighted average common shares outstanding(5)
Basic
Diluted

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

F-9

Unaudited Pro Forma Combined Statement of Operations

For the Year Ended December 31, 2014

(in thousands, except per share data)


	WildHorse Resources II, LLC Historical			Esquisto Resources II, LLC			Initial Esquisto Assets				Corporate Reorganization				Pro Forma
Operating revenues
Natural gas	$	37,741		$	575		$	29			$	—			$	38,345
Crude oil		2,780			13,352			1,694				—				17,826
Natural gas liquids		989			1,210			86				—				2,285

Total operating revenues		41,510			15,137			1,809				—				58,456

Operating expenses
Lease operating expenses		9,428			998			114				—				10,540
Production and ad valorem taxes		2,584			735			86				—				3,405
Cost of oil sales		687			—			—				—				687
Depreciation, depletion and amortization		15,297			7,332			640		(9)		—				23,269
Impairment of proved oil and gas properties		24,721			—			—				—				24,721
General and administrative		5,838			2,388			—				—				8,226
Exploration expense		1,597			2			—				—				1,599

Total operating expenses		60,152			11,455			840				—				72,447

(Loss) income from operations		(18,642	)		3,682			969				—				(13,991	)

Other income (expense)
Interest expense		(2,680	)		(606	)		—				—				(3,286	)
Other income (expense)		213			(333	)		—				—				(120	)
State deferred tax expense		—			(383	)		—				383		(1)		—
Gain on derivative instruments		6,514			—			—				—				6,514

Total other income (expense)		4,047			(1,322	)		—				383				3,108

Net (loss) income before income taxes		(14,595	)		2,360			969				383				(10,883	)

Income tax benefit (expense)		158			—			(349	)	(4)		5,076		(4)		4,502
												(383	)	(1)

Net (loss) income	$	(14,437	)	$	2,360		$	620			$	5,076			$	(6,381	)

Net (loss) income per common share(5)
Basic															$
Diluted															$
Weighted average common shares outstanding(5)
Basic
Diluted

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

F-10

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

1.	Basis of Presentation

The historical financial information is derived from the historical consolidated financial statements of WildHorse Resources II, LLC, (“WildHorse” or the “Predecessor”), included elsewhere in this prospectus. The unaudited pro forma combined balance sheet of the Company includes pro forma adjustments to give effect to the Corporate Reorganization, the Offering and the Burleson North Acquisition as if they had occurred on September 30, 2016. The unaudited pro forma combined statements of operations of the Company give pro forma effect to the following as if they had occurred on the dates indicated:

•

For the year ended December 31, 2014, the Corporate Reorganization and the contribution to Esquisto of the Initial Esquisto Assets as if they had been completed as of January 1, 2014;

•

For the nine months ended September 30, 2015, the (i) Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) the Offering and the application of the net proceeds therefrom as described in “Use of Proceeds” as if they had been completed as of January 1, 2015; and

•

For the year ended December 31, 2015 (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) the Offering and the application of the net proceeds therefrom as described in “Use of Proceeds” as if they had been completed as of January 1, 2015.

•

Contemporaneously with the closing of this offering, (i) the current owners of WildHorse will exchange all of their interests in WildHorse for equivalent interests in WildHorse Investment Holdings and the current owners of Esquisto will exchange all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings will contribute all of its interests in WildHorse to WildHorse Holdings, Esquisto Investment Holdings will contribute all of its interests in Esquisto to Esquisto Holdings and the current owner of Acquisition Co. will contribute all of its interests in Acquisition Co. to Acquisition Co. Holdings, (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will issue management incentive units to certain of our officers and employees and (iv) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will contribute all of the interests in WildHorse, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock (the “Corporate Reorganization”). As a result of the Corporate Reorganization, WildHorse, Esquisto and Acquisition Co. Holdings will become direct, wholly owned subsidiaries of the Company. The unaudited pro forma combined financial statements have been prepared on the basis that, as a corporation, the Company will be subject to Subchapter C of the Internal Revenue Code of 1986, as amended, and, as a result, will be subject to U.S. federal and state income taxes at the entity level.

Because WildHorse, Esquisto and Acquisition Co. Holdings are under the common control of NGP, the sale and contribution of the respective ownership interests are accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed will be recorded based on historical cost.

2.	Burleson North Acquisition

The Burleson North Acquisition is reflected in the unaudited pro forma financial statements as being accounted for under the acquisition method in accordance with ASC 805, Business Combinations (“ASC 805”). In accordance with ASC 805, the assets acquired and the liabilities assumed have been measured at fair value based on various estimates. These estimates are based on key assumptions related to the business combination, including reviews of publicly disclosed information for other acquisitions in the industry, historical experience of the companies, data that was available through the public domain and due diligence reviews of the acquiree businesses.

F-11

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)

For purposes of measuring the estimated fair value, where applicable, of the assets acquired and the liabilities assumed as reflected in the unaudited pro forma financial information, the Company has applied the guidance in ASC 820, Fair Value Measurements (“ASC 820”), which establishes a framework for measuring fair value. In accordance with ASC 820, fair value is an exit price and is defined as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.” Under ASC 805, acquisition-related transaction costs and acquisition-related restructuring charges are not included as components of consideration transferred but are accounted for as expenses in the period in which the costs are incurred. In addition, the unaudited pro forma financial statements do not reflect any cost savings, operating synergies or revenue enhancements that the consolidated company may achieve as a result of the business combination, the costs to integrate the operations of the companies or the costs necessary to achieve these cost savings, operating synergies and revenue enhancements.

The unaudited pro forma financial information includes various assumptions and estimates, including those related to the fair value of consideration transferred and the preliminary purchase price allocation of assets acquired and liabilities assumed in the transaction based on management’s best estimation of fair value as of the date of this prospectus. The preliminary purchase price allocation may be updated upon closing of the transaction. There are various factors that can change the preliminary purchase price allocation, including but not limited to changes in commodity strip prices, reserve estimates, market conditions and the Company’s discount rate.

The Burleson North Acquisition is expected to close prior to or contemporaneously with the closing of this Offering at an aggregate purchase price of $400.0 million in cash, subject to customary purchase price adjustments. Of the $400 million purchase price, Acquisition Co. previously paid $45.0 million, which was funded by a capital contribution from NGP XI, and will pay the remaining $355.0 million at closing out of the proceeds of the Offering. The following table shows the preliminary purchase price allocation for the Burleson North Acquisition (in thousands):


Preliminary Purchase Price
Consideration Given
Cash	$	400,000

Total consideration given(1)	$	400,000


Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	108,429
Unproved oil and gas properties		292,760

Total fair value of oil and gas properties acquired(2)		401,189
Asset retirement obligations		(1,189	)

Preliminary fair value of net assets acquired	$	400,000

(1)	Of the total consideration, $355.0 million is expected to be funded using a portion of the proceeds from the Offering.

(2)

Weighted average commodity prices utilized in the determination of the pro forma fair value of oil and gas properties was $49.88 per barrel of oil, $2.59 per Mcf of natural gas and $13.51 per barrel of oil equivalent of NGLs. The prices used were based upon commodity prices on October 5, 2016 using the NYMEX strip. When calculating the final purchase price allocation, the Company will use NYMEX strip as of the closing date, which could materially change the above preliminary purchase price allocation.

F-12

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)

The preliminary purchase price allocations have been used to prepare pro forma adjustments for the Burleson North Acquisition. The final purchase price allocations, contingent upon closing of the transaction, will be determined when the Company has completed the detailed valuations and necessary calculations. The final allocation could differ materially from the preliminary allocation used in these pro forma adjustments. The final allocation may result in changes in fair value of proved and unproved oil and gas properties.

3.	Pro Forma Adjustments

We made the following adjustments in the preparation of the Unaudited Pro Forma Combined Balance Sheet as of September 30, 2016:

(1)

Adjustments reflect the (i) the estimated remaining consideration to be paid in the Burleson North Acquisition, (ii) recording the estimated fair value of acquired assets and liabilities in accordance with the acquisition method of accounting as outlined in Note 2 to these unaudited pro forma combined financial statements and (iii) part of the $400 million aggregate consideration in the Burleson North Acquisition consisting of payment of $45.0 million by Acquisition Co., which was funded by a capital contribution from NGP XI, and payment of $355.0 million from the proceeds from the Offering. In connection with the Offering, Acquisition Co. Holdings will receive shares in exchange for contributing Acquisition Co. to the Company.

(2)

Adjustments reflect the Company’s receipt of the estimated gross proceeds of $610.2 million net of (i) underwriters’ discount of $36.6 million, (ii) offering expenses of $3.2 million from the issuance and sale of million shares of common stock at an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus) and the use of such proceeds to repay indebtedness outstanding prior to the Offering as described in “Use of Proceeds” and (iii) $ million of debt issuance costs related to the establishment of the Company’s new revolving credit facility. In preparing the unaudited pro forma combined financial statements, the gross and net proceeds from the offering are assumed to be $650 million and $610.2 million, respectively.

(3)

Adjustments reflect application of $233.5 million of the Offering proceeds to repay the WildHorse and Esquisto indebtedness and $9.6 million to repay notes payable to members, and borrowings under the new WildHorse revolving credit facility of $ million.

(4)

Adjustments reflect the reclassification of Esquisto consolidated balance sheet amounts to conform to the balance sheet presentation of the Predecessor related to (i) debt issuance costs; (ii) water assets; and (iii) the separate presentation of accumulated (deficit) earnings.

(5)

Adjustments reflect the write off of the $1.4 million of unamortized deferred financing costs upon the assumed repayment of debt of WildHorse and Esquisto, including estimated tax effects of $0.6 million using an estimated effective rate of 40%, and the incurrence of estimated deferred financing costs of $1.8 million related to establishment of the Company’s new revolving credit facility.

(6)

Adjustments reflect the estimated income tax effects as a result of the Company’s change in tax status to a Subchapter C corporation using an estimated effective rate of 40%.

(7)

Adjustment reflects estimated direct, incremental and non-recurring fees incurred in connection with the Burleson North Acquisition.

F-13

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)

We made the following adjustments in the preparation of the Unaudited Pro Forma Combined Statements of Operations:

(1)

Adjustments reflect the reclassification of Esquisto consolidated statement of operations amounts to conform to the statement of operations presentation of the Predecessor related to (i) ad valorem taxes; (ii) state deferred tax expense; (iii) gain from derivative financial instruments; and (iv) 2015 acquisition related costs.

(2)

Adjustments reflect the depletion, depreciation and amortization expense on property and equipment associated with the Comstock Assets for the year ended December 31, 2015 and the nine months ended September 30, 2015, and the Burleson North Assets for the year ended December 31, 2015 and the nine months ended September 30, 2016 and September 30, 2015.

(3)

Adjustments reflect (i) the $5.6 million reversal of interest expense recorded related to existing WildHorse and Esquisto indebtedness, (ii) the $0.3 million amortization of deferred financing costs over the Company’s new revolving credit facility’s five-year life, (iii) the $1.3 million in commitment fees related to such new facility and (iv) the $ million in interest expense related to borrowings under the new WildHorse revolving credit facility. A ¹ / ₈ % change in the interest rate on the new WildHorse revolving credit facility would change pro forma interest expense by $ million for the nine months ended September 30, 2016.

(4)

Adjustments reflect the estimated income tax effects as a result of (i) in the case of the Corporate Reorganization, the Company’s change in tax status to a Subchapter C corporation using an estimated effective rate of 40% and (ii) in the case of the contribution of the Initial Esquisto Assets, the Comstock Acquisition and the Burleson North Acquisition, the estimated income tax effects of the acquired assets at their respective historical tax rates.

(5)

Basic and diluted earnings per share is based on the issuance and sale of shares of common stock in the Offering.

(6)

Adjustments reflect the increase in interest expense resulting from $50.0 million of borrowings under the Esquisto revolving credit facility, which was used to finance a portion of the Comstock Acquisition. A ¹ / ₈ % change in the interest rate would change pro forma interest expense on this $50.0 million of borrowings by $0.04 million for the seven months ended July 31, 2015.

(7)

Adjustments reflect (i) the $6.3 million reversal of interest expense recorded related to WildHorse and Esquisto indebtedness, (ii) the $0.3 million amortization of deferred financing costs over the Company’s new revolving credit facility’s five-year life, (iii) the $1.3 million in commitment fees related to such new facility and (iv) the $ million in interest expense related to borrowings under the new WildHorse revolving credit facility. A ¹ / ₈ % change in the interest rate on the new WildHorse revolving credit facility would change pro forma interest expense by $ million for the nine months ended September 30, 2015.

(8)

Adjustments reflect (i) the $8.2 million reversal of interest expense recorded related to existing WildHorse and Esquisto indebtedness, (ii) the $0.4 million amortization of deferred financing costs over the Company’s new revolving credit facility’s five-year life, (iii) the $1.7 million in commitment fees related to such new facility and (iv) the $ million in interest expense related to borrowings under the new WildHorse revolving credit facility. A ¹ / ₈ % change in the interest rate on the new WildHorse revolving credit facility would change pro forma interest expense by $ million for the year ended December 31, 2015.

(9)

Adjustments to reflect the depletion, depreciation and amortization expense on property and equipment associated with the Initial Esquisto Assets.

F-14

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)

4.	Supplemental Disclosure of Oil and Natural Gas Operations

Net Proved Oil and Natural Gas Reserves

The historical pro forma supplemental oil, natural gas and NGL disclosure is derived from the consolidated financial statements of the Predecessor, the consolidated financial statements of Esquisto, and the respective statements of revenues and direct operating expenses of the Initial Esquisto Assets, the Comstock Assets and the Burleson North Assets, included elsewhere in this prospectus. The unaudited pro forma combined supplemental oil, natural gas and NGL disclosures of the Company reflect the historical results of WildHorse, on a pro forma basis to give effect to: (i) for the year ended December 31, 2014, the Corporate Reorganization and the contribution to Esquisto of the Initial Esquisto Assets as if they had been completed as of January 1, 2014 and (ii) for the year ended December 31, 2015, the Corporate Reorganization, the Comstock Acquisition, the Burleson North Acquisition, and the Offering and the application of the net proceeds therefrom as described in “Use of Proceeds” as if they had been completed as of January 1, 2015.

In accordance with SEC regulations, reserves at December 31, 2015 and December 31, 2014 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.

F-15

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)

An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the United States, is as follows for the years ended December 31, 2014, including the Initial Esquisto Assets as if the transaction occurred on January 1, 2014:


	Year Ended December 31, 2014 Proved Oil Reserves (MBbls)
	WildHorse Resources II, LLC			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II,			Initial Esquisto			Pro Forma Adjusted
Proved Developed and Undeveloped Reserves:
Beginning of Year		175			—			—			175
Purchase		17			154			(154	)		17
Revision of quantity estimates		(2	)		—			—			(2	)
Extensions, discoveries and additions		63			7,464			171			7,698
Production		(31	)		(159	)		(17	)		(207	)

End of Year		222			7,459			—			7,681


Proved Developed Reserves:
Beginning of Year		175			—			—			175
End of Year		222			1,436			—			1,658

Proved Undeveloped Reserves:
Beginning of Year		—			—			—			—
End of Year		—			6,023			—			6,023


	Year Ended December 31, 2014 Proved Natural Gas Reserves (MMcf)
	WildHorse Resources II, LLC			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC			Initial Esquisto			Pro Forma Adjusted
Proved Developed and Undeveloped Reserves:
Beginning of Year		210,293			—			—			210,293
Purchase		13,684			79			(79	)		13,684
Revision of quantity estimates		30,880			—			—			30,880
Extensions, discoveries and additions		4,318			6,315			86			10,719
Production		(9,388	)		(156	)		(7	)		(9,551	)

End of Year		249,787			6,238			—			256,025

Proved Developed Reserves:
Beginning of Year		97,734			—			—			97,734
End of Year		122,780			1,273			—			124,053

Proved Undeveloped Reserves:
Beginning of Year		112,559			—			—			112,559
End of Year		127,007			4,965			—			131,972

F-16

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)


	Year Ended December 31, 2014 Proved Natural Gas Liquids Reserves (MBbls)
	WildHorse Resources II, LLC			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC			Initial Esquisto			Pro Forma Adjusted
Proved Developed and Undeveloped Reserves:
Beginning of Year		—			—			—			—
Purchase		—			22			(22	)		—
Revision of quantity estimates		(208	)		—			—			(208	)
Extensions, discoveries and additions		573			1,674			24			2,271
Production		(41	)		(46	)		(2	)		(89	)

End of Year		324			1,650			—			1,974


Proved Developed Reserves:
Beginning of Year		—			—			—			—
End of Year		324			329			—			653

Proved Undeveloped Reserves:
Beginning of Year		—			—			—			—
End of Year		—			1,321			—			1,321

The following tables set forth our pro forma reserves for the year ended December 31, 2014:


	Year Ended December 31, 2014
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Equivalent (MBoe)
Proved Developed and Undeveloped Reserves:
Beginning of Year		175			210,293			—			35,224
Purchase		17			13,684			—			2,298
Revision of quantity estimates		(2	)		30,880			(208	)		4,937
Extensions, discoveries and additions		7,698			10,719			2,271			11,756
Production		(207	)		(9,551	)		(89	)		(1,888	)

End of Year		7,681			256,025			1,974			52,327


Proved Developed Reserves:
Beginning of Year		175			97,734			—			16,464
End of Year		1,658			124,053			653			22,987

Undeveloped Reserves:
Beginning of Year		—			112,559			—			18,760
End of Year		6,023			131,972			1,321			29,340

F-17

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)


	Year Ended December 31, 2014
	WildHorse Resources II, LLC (MBoe)			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC (MBoe)			Initial Esquisto (MBoe)			Pro Forma Adjusted (MBoe)
Proved Developed and Undeveloped Reserves:
Beginning of Year		35,224			—			—			35,224
Purchase		2,298			189			(189	)		2,298
Revision of quantity estimates		4,937			—			—			4,937
Extensions, discoveries and additions		1,356			10,191			209			11,756
Production		(1,637	)		(231	)		(20	)		(1,888	)

End of Year		42,178			10,149			—			52,327


Proved Developed Reserves:
Beginning of Year		16,464			—			—			16,464
End of Year		21,010			1,977			—			22,987

Proved Undeveloped Reserves:
Beginning of Year		18,760			—			—			18,760
End of Year		21,168			8,172			—			29,340

The tables above have information presented in barrels of oil equivalents, which is calculated at a rate of six thousand cubic feet of gas per one barrel of oil equivalent.

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

•

During 2014, WildHorse acquired 2,298 Mboe of proved reserves, of which 1,888 Mboe was for non-core properties acquired in East Texas and 410 Mboe was a result of leaseholds acquired in its RCT field in Louisiana.

•

During 2014, WildHorse had upward performance revisions to total proved reserves of 4,937 Mboe, of which 3,043 Mboe related to gas processing, 1,405 Mboe related to LOE reductions and 517 Mboe related to changes in commodity prices, partially offset by a reduction of 28 Mboe due to changes in ownership interest.

•

During 2014, extensions, discoveries and additions increased proved reserves by 11,756 Mboe. Of the increase, 10,400 Mboe resulted from Esquisto’s continuous drilling in the Eagle Ford horizons in Burleson County, Texas and 1,356 Mboe related to WildHorse’s drilling of two horizontal wells in East Texas.

F-18

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)

An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the United States, is as follows for the year ended December 31, 2015 reflecting the Comstock Acquisition and the Burleson North Acquisition as if the transactions occurred January 1, 2015:


	Year Ended December 31, 2015 Proved Oil Reserves (MBbls)
	WildHorse Resources II, LLC			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC			Comstock Acquisition			Burleson North Acquisition			Pro Forma Adjusted
Proved Developed and Undeveloped Reserves:
Beginning of Year		222			7,459			—			—			7,681
Purchase		—			1,972			(771	)		8,575			9,776
Revision of quantity estimates		58			367			(49	)		(809	)		(433	)
Extensions, discoveries and additions		731			26,867			1,128			925			29,651
Production		(73	)		(953	)		(308	)		(1,767	)		(3,101	)

End of Year		938			35,712			—			6,924			43,574


Proved Developed Reserves:
Beginning of Year		222			1,436			—			—			1,658
End of Year		444			7,059			—			6,924			14,427

Proved Undeveloped Reserves:
Beginning of Year		—			6,023			—			—			6,023
End of Year		494			28,653			—			—			29,147


	Year Ended December 31, 2015 Proved Natural Gas Reserves (MMcf)
	WildHorse Resources II, LLC			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC			Comstock Acquisition			Burleson North Acquisition			Pro Forma Adjusted
Proved Developed and Undeveloped Reserves:
Beginning of Year		249,787			6,238			—			—			256,025
Purchase		—			4,296			(2,238	)		5,877			7,935
Revision of quantity estimates		(45,925	)		2,127			(77	)		(314	)		(44,189	)
Extensions, discoveries and additions		120,899			22,439			2,756			262			146,356
Production		(13,637	)		(1,265	)		(441	)		(1,424	)		(16,767	)

End of Year		311,124			33,835			—			4,401			349,360


Proved Developed Reserves:
Beginning of Year		122,780			1,273			—			—			124,053
End of Year		134,169			8,821			—			4,401			147,391

Proved Undeveloped Reserves:
Beginning of Year		127,007			4,965			—			—			131,972
End of Year		176,955			25,014			—			—			201,969

F-19

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)


	Year Ended December 31, 2015 Proved Natural Gas Liquids Reserves (MBbls)
	WildHorse Resources II, LLC			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC			Comstock Acquisition			Burleson North Acquisition			Pro Forma Adjusted
Proved Developed and Undeveloped Reserves:
Beginning of Year		324			1,650			—			—			1,974
Purchase		—			710			(596	)		579			693
Revision of quantity estimates		146			455			(25	)		(96	)		480
Extensions, discoveries and additions		—			5,976			716			50			6,742
Production		(103	)		(261	)		(95	)		(105	)		(564	)

End of Year		367			8,530			—			428			9,325


Proved Developed Reserves:
Beginning of Year		324			329			—			—			653
End of Year		367			1,868			—			428			2,663

Proved Undeveloped Reserves:
Beginning of Year		—			1,321			—			—			1,321
End of Year		—			6,662			—			—			6,662

The following tables set forth our pro forma reserves for the year ended December 31, 2015:


	Year Ended December 31, 2015
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Equivalent (Mboe)
Proved Developed and Undeveloped Reserves:
Beginning of Year		7,681			256,025			1,974			52,327
Purchase		9,776			7,935			693			11,791
Revision of quantity estimates		(433	)		(44,189	)		480			(7,319	)
Extensions, discoveries and additions		29,651			146,356			6,742			60,786
Production		(3,101	)		(16,767	)		(564	)		(6,459	)

End of Year		43,574			349,360			9,325			111,126


Proved Developed Reserves:
Beginning of Year		1,658			124,053			653			22,987
End of Year		14,427			147,391			2,663			41,655

Proved Undeveloped Reserves:
Beginning of Year		6,023			131,972			1,321			29,340
End of Year		29,147			201,969			6,662			69,471

F-20

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)


	Year Ended December 31, 2015
	WildHorse Resources II, LLC (MBoe)			Esquisto Resources, LLC and Subsidiary and Esquisto Resources II, LLC (MBoe)			Comstock Acquisition (MBoe)			Burleson North Acquisition (MBoe)			Pro Forma (MBoe)
Proved Developed and Undeveloped Reserves:
Beginning of Year		42,178			10,149			—			—			52,327
Purchase		—			3,398			(1,740	)		10,133			11,791
Revision of quantity estimates		(7,450	)		1,176			(87	)		(958	)		(7,319	)
Extensions, discoveries and additions		20,881			36,583			2,303			1,019			60,786
Production		(2,449	)		(1,425	)		(476	)		(2,109	)		(6,459	)

End of Year		53,160			49,881			—			8,085			111,126


Proved Developed Reserves:
Beginning of Year		21,010			1,977			—			—			22,987
End of Year		23,173			10,397			—			8,085			41,655

Proved Undeveloped Reserves:
Beginning of Year		21,168			8,172			—			—			29,340
End of Year		29,987			39,484			—			—			69,471

The tables above have information presented in barrels of oil equivalents, which is calculated at a rate of six thousand cubic feet of gas per one barrel of oil equivalent.

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

•

During 2015, Esquisto acquired 1,658 Mboe of proved reserves primarily attributable to the producing wells acquired in the Comstock Acquisition.

•

During 2015, the Burleson North Assets are reflected as an acquisition of 10,133 Mboe attributable to proved reserves.

•

During 2015, WildHorse had downward revisions of proved reserves of 7,450 Mboe and Esquisto had upward revisions of 1,089 Mboe for a combined downward revision of 6,361 Mboe. The WildHorse downward revision related to commodity price changes representing 3,410 Mboe and downward revisions of 4,040 Mboe resulting from technical changes. Esquisto had positive proved reserve revisions of 1,314 Mboe as a result of operational efficiencies gained through increased experience in the Eagle Ford horizons, offset by negative price revisions of 225 Mboe. There were negative revisions of proved reserves on the Burleson North Asset of 958 Mboe related to commodity prices.

•

During 2015, extensions, discoveries and additions increased proved reserves by 60,786 Mboe. Of the increase, 20,881 Mboe related primarily to WildHorse’s drilling in its RCT field in Louisiana. In addition, Esquisto had an increase in proved reserves of 38,886 Mboe, resulting from continuous drilling in the Eagle Ford horizons in Burleson County, Texas. There was an increase in proved reserves on the Burleson North Asset of 1,019 Mboe resulting from the addition of nine wells in the Eagle Ford trend and one well in the Austin Chalk trend.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, natural gas and NGL reserves of the property. An estimate of fair

F-21

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)

value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2015 and December 31, 2014 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves is as follows at December 31, 2014 and December 31, 2015 (in thousands):


	As of December 31, 2014
	WildHorse Resources II, LLC			Esquisto Resources II, LLC			Corporate Reorganization			Pro Forma
				(In thousands)
Oil, natural gas and NGL producing activities:
Future cash inflows	$	1,167,732		$	769,878		$	—		$	1,937,610
Future production costs		(420,781	)		(132,010	)		—			(552,791	)
Future development costs		(147,809	)		(142,015	)		—			(289,824	)
Future income taxes		(563	)		—			(274,169	)		(274,732	)

Undiscounted future net cash flows		598,579			495,853			(274,169	)		820,263
10% annual discount factor		(368,680	)		(280,558	)		162,114			(487,124	)

Standardized measure of discounted future cash flows	$	229,899		$	215,295		$	(112,055	)	$	333,139


	As of December 31, 2015
	WildHorse Resources II, LLC			Esquisto Resources II, LLC			Burleson North Acquisition			Corporate Reorganization			Pro Forma
Oil, natural gas and NGL producing activities:
Future cash inflows	$	891,436		$	1,959,585		$	347,910		$	—		$	3,198,931
Future production costs		(388,806	)		(477,447	)		(143,550	)		—			(1,009,803	)
Future development costs		(147,270	)		(594,528	)		(14,219	)		—			(756,017	)
Future income taxes		(216	)		—			—			(235,898	)		(236,114	)

Undiscounted future net cash flows		355,144			887,610			190,141			(235,898	)		1,196,997
10% annual discount factor		(212,889	)		(577,935	)		(57,863	)		160,564			(688,123	)

Standardized measure of discounted future cash flows	$	142,255		$	309,675		$	132,278		$	(75,334	)	$	508,874

It is not intended that the Financial Accounting Standards Board’s standardized measure of discounted future net cash flows represent the fair market value of proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules, which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

F-22

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)

Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves are as follows for the year ended December 31, 2014 (in thousands):


	WildHorse Resources II, LLC			Esquisto Resources II, LLC			Initial Esquisto Assets			Corporate Reorganization			Pro Forma
Standardized measure of discounted future net cash flow, beginning of year	$	165,181		$	—		$	—		$	—		$	165,181
Changes from
Purchases of proved reserves		14,587			7,251			—			(7,251	)		14,587
Extensions, discovers, and improved recovery, less related costs		20,195			221,367			8,000			—			249,562
Sales of natural gas, crude oil and natural gas liquids produced, net of production costs		(29,498	)		(13,404	)		(1,609	)		—			(44,511	)
Revision of quantity estimates		26,945			—			—			—			26,945
Accretion of discount		16,522			—			—			—			16,522
Changes in estimated future development costs		(3,194	)		—			—			—			(3,194	)
Development costs incurred that reduced future development costs		190			—			—			—			190
Change in sales due to prices, net of production costs		19,683			—			—			860			20,543
Net change in estimated taxes		(266	)		—			—			(112,055	)		(112,321	)
Changes in timing of estimated future production		(446	)		81			—			—			(365	)

Aggregate change in standardized measure of discounted future net cash flows		64,718			215,295			6,391			(118,446	)		167,958

Standardized measure of discounted future net cash flow, end of year	$	229,899		$	215,295		$	6,391		$	(118,446	)	$	333,139

F-23

WildHorse Resource Development Corporation

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (continued)

Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves are as follows for the year ended December 31, 2015 (in thousands):


	WildHorse Resources II, LLC			Esquisto Resources II, LLC			Comstock Acquisition			Burleson North Acquisition			Corporate Reorganization			Pro Forma
Standardized measure of discounted future net cash flow, beginning of year	$	229,899		$	215,295		$	—		$	—		$	(112,055	)	$	333,139
Changes from
Purchases of proved reserves		—			69,258			53,371			361,566			(67,932	)		416,263
Extensions, discovers, and improved recovery, less related costs		68,738			192,990			45,054			22,248			—			329,030
Sales of natural gas, crude oil and natural gas liquids produced, net of production costs		(23,523	)		(39,559	)		(16,036	)		(59,434	)		—			(138,552	)
Revision of quantity estimates		(17,000	)		26,827			(2,104	)		(15,375	)		—			(7,652	)
Accretion of discount		23,020			21,530			3,113			36,157			—			83,820
Changes in estimated future development costs		—			1,646			—			—			—			1,646
Development costs incurred that reduced future development costs		—			—			—			—			—			—
Change in sales due to prices, net of production costs		(133,917	)		(59,213	)		(19,228	)		(202,074	)		5,019			(409,413	)
Net change in estimated taxes		171			—			—			—			36,721			36,892
Changes in timing of estimated future production		(5,133	)		(119,099	)		(1,257	)		(10,810	)		—			(136,299	)

Aggregate change in standardized measure of discounted future net cash flows		(87,644	)		94,380			62,913			132,278			(26,192	)		175,735

Standardized measure of discounted future net cash flow, end of year	$	142,255		$	309,675		$	62,913		$	132,278		$	(138,247	)		508,874

Estimates of economically recoverable oil, natural gas and NGL reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, natural gas and NGLs may differ materially from the amounts estimated.

F-24

Report of Independent Registered Public Accounting Firm

The Board of Directors

WildHorse Resource Development Corporation:

We have audited the accompanying balance sheet of WildHorse Resource Development Corporation (the Company) as of August 4, 2016. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

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

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of WildHorse Resource Development Corporation as of August 4, 2016, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

August 12, 2016

F-25

WildHorse Resource Development Corporation

Balance Sheet


	August 4, 2016
Assets
Assets
Cash and cash equivalents		—

Total assets		—


Shareholders’ Equity
Shareholders’ Equity
Common stock, $.01 par value; authorized 1,000 shares, 1,000 issue and outstanding at August 4, 2016		10
Less receivable from WildHorse Resources II, LLC		(10	)

Total shareholders’ equity		—

F-26

WildHorse Resource Development Corporation

Notes to Balance Sheet

1.	Organization and Basis of Presentation

WildHorse Resource Development Corporation (“WRDC”) is a Delaware corporation formed by WildHorse Resources II, LLC on August 4, 2016 to become a holding company.

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). WildHorse Resources II, LLC has committed to contribute $10 as the initial sole shareholder. This contribution receivable is reflected as a reduction to equity. Separate Statements of Income, Changes in Shareholders’ Equity and of Cash Flows have not been presented because WRDC has had no business transactions or activities to date.

2.	Subsequent events

We are not aware of any events that have occurred subsequent to August 4, 2016 that would require recognition or disclosure in this financial statement.

F-27

Independent Auditors Report

The Board of Managers and Members

WildHorse Resources II, LLC:

We have audited the accompanying consolidated balance sheets of WildHorse Resources II, LLC and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, members’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of WildHorse Resources II, LLC and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

August 12, 2016

F-28

WildHorse Resources II, LLC

Consolidated Balance Sheets


	December 31, 2015			December 31, 2014
Assets
Current assets
Cash and cash equivalents	$	22,224,690		$	12,188,321
Accounts receivable, net		7,920,764			26,336,939
Derivative instruments		4,236,196			6,843,054
Prepaid expenses		559,939			765,959
Inventory		—			107,803

Total current assets		34,941,589			46,242,076

Property and equipment
Oil and gas properties		439,378,811			327,540,493
Other property and equipment		29,347,618			4,551,599
Accumulated depreciation, depletion and amortization		(78,730,805	)		(44,282,155	)

Total property and equipment, net		389,995,624			287,809,937

Other noncurrent assets
Debt issuance costs		580,594			788,773
Derivative instruments		1,415,507			384,475
Restricted cash		550,581			300,152
Other noncurrent assets		365,748			197,028

Total other noncurrent assets		2,912,430			1,670,428

Total assets	$	427,849,643		$	335,722,441

Liabilities and members’ equity
Current liabilities
Accounts payable	$	17,607,171		$	27,925,830
Accounts payable—related party		—			1,652,222
Accrued liabilities		9,486,266			7,841,175
Asset retirement obligations		90,000			90,000

Total current liabilities		27,183,437			37,509,227

Noncurrent liabilities
Long term debt		118,000,000			111,100,000
Asset retirement obligations		6,648,431			5,845,756
Other noncurrent liabilities		1,883,537			2,275,877

Total noncurrent liabilities		126,531,968			119,221,633

Total liabilities		153,715,405			156,730,860

Commitments and contingencies (see Note 10)		—			—
Members’ equity		274,134,238			178,991,581

Total liabilities and members’ equity	$	427,849,643		$	335,722,441

The Notes to the Consolidated Financial Statements are an integral part of these statements.

F-29

WildHorse Resources II, LLC

Consolidated Statements of Operations


	For the year ended December 31, 2015			For the year ended December 31, 2014
Operating revenues
Natural gas	$	30,555,933		$	37,740,634
Crude oil		3,305,001			2,780,301
Natural gas liquids		1,451,475			988,860
Gathering system income		314,308			—

Total operating revenues		35,626,717			41,509,795

Operating expenses
Lease operating expenses		8,606,412			9,428,056
Gathering system operating expense		914,212			—
Production and ad valorem taxes		2,665,504			2,583,928
Cost of oil sales		—			687,461
Depreciation, depletion and amortization		25,526,123			15,296,648
Impairment of proved oil and gas properties		9,312,359			24,721,015
General and administrative		10,567,242			5,837,626
Exploration expense		14,895,803			1,597,028

Total operating expenses		72,487,655			60,151,762

Loss from operations		(36,860,938	)		(18,641,967	)

Other income (expense)
Interest expense		(2,576,042	)		(2,680,293	)
Other (expense) income		(45,005	)		213,392
Gain (loss) on derivative instruments		9,510,313			6,513,966

Total other income (expense)		6,889,266			4,047,065

Net loss before income taxes		(29,971,672	)		(14,594,902	)
Income tax benefit		16,804			157,920

Net loss	$	(29,954,868	)	$	(14,436,982	)

The Notes to the Consolidated Financial Statements are an integral part of these statements.

F-30

WildHorse Resources II, LLC

Consolidated Statements of Changes in Members’ Equity

For the years ended December 31, 2015 and 2014.


	Combined Capital			Retained Deficit			Members’ Equity
Balance, December 31, 2013	$	102,050,000		$	(6,167,662	)	$	95,882,338
Capital contributions		89,437,127			—			89,437,127
Decrease of notes receivable from members, net		8,109,098			—			8,109,098
Net loss		—			(14,436,982	)		(14,436,982	)

Balance, December 31, 2014	$	199,596,225		$	(20,604,644	)	$	178,991,581
Capital contributions		125,850,026			—			125,850,026
Increase of notes receivable from members, net		(752,501	)		—			(752,501	)
Net loss		—			(29,954,868	)		(29,954,868	)

Balance, December 31, 2015	$	324,693,750		$	(50,559,512	)	$	274,134,238

The Notes to the Consolidated Financial Statements are an integral part of these statements.

F-31

WildHorse Resources II, LLC

Consolidated Statements of Cash Flows


	For the year ended December 31,
	2015			2014
Cash flows from operating activities
Net loss	$	(29,954,868	)	$	(14,436,982	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities
Depreciation, depletion and amortization		25,184,571			14,987,304
Accretion of asset retirement obligations		341,552			309,344
Impairment of proved oil and gas properties		9,312,359			24,721,015
Dry hole expense and impairments of unproved Properties		8,376,479			—
Amortization of debt issuance cost		221,896			208,151
(Gain) loss on derivative instruments		(9,510,313	)		(6,513,966	)
Cash settlements on derivative instruments		11,037,172			(2,711,680	)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		18,296,422			(19,416,231	)
Decrease (increase) in prepaid expenses		206,020			(336,483	)
Decrease (increase) in inventories		107,803			449,946
(Decrease) increase in accounts payable		(8,079,683	)		25,241,430
(Decrease) increase in accrued liabilities		(165,695	)		3,158,311

Net cash provided by (used in) operating activities		25,373,715			25,660,159

Cash flows from investing activities
Additions to oil and gas properties		(123,939,686	)		(128,667,447	)
Additions to other property and equipment		(23,153,249	)		(300,152	)
Sales of other property and equipment		22,210			—
Increase in restricted cash		(250,429	)		—

Net cash used in investing activities		(147,321,154	)		(128,967,599	)

Cash flows from financing activities
Advances on revolving credit facility		60,400,000			67,400,000
Payments on revolving credit facility		(53,500,000	)		(50,300,000	)
Member contributions		125,097,525			97,546,225
Debt issuance cost		(13,717	)		(56,739	)

Net cash provided by financing activities		131,983,808			114,589,486

Increase in cash and cash equivalents		10,036,369			11,282,046
Cash and cash equivalents
Beginning of period		12,188,321			906,275

End of period	$	22,224,690		$	12,188,321

The Notes to the Consolidated Financial Statements are an integral part of these statements.

F-32

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements

1.	Organization

WildHorse Resources II, LLC (the Company, WHR II, we, our or us) is an independent energy company engaged in the acquisition, exploitation, and development of natural gas and crude oil properties. We were organized in the State of Delaware on June 3, 2013 under the Delaware Limited Liability Company Act with NGP X US Holdings, L.P. (NGP X), a Delaware limited partnership, as the principal member. We are a growth-oriented, independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in the State of Louisiana and the State of Texas.

On June 18, 2014, we purchased WildHorse Resources Management Company, LLC (WHRM) from WildHorse Resources LLC (WHR) becoming the sole member and manager of WHRM. WHRM was organized in the State of Delaware on October 17, 2012 under the Delaware Limited Liability Company Act. WHRM is a 100% wholly owned subsidiary of ours.

Oakfield Energy LLC (Oakfield) was organized in the State of Delaware on June 4, 2014 under the Delaware Limited Liability Company Act with WHR II as the sole member and manager. Oakfield is a 100% wholly owned subsidiary of ours.

Our consolidated financial statements include the accounts of WHR II and our wholly owned subsidiaries, WHRM and Oakfield. All significant intercompany transactions have been eliminated in consolidation. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis.

2.	Summary of Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (GAAP). Our operations are considered to fall within a single reportable industry segment, which is the acquisition, exploitation, exploration and development of natural gas and crude oil properties in the United States. Significant policies are discussed below.

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 and gas 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) environmental

F-33

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

remediation costs; (7) valuation of derivative instruments and (8) 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.

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with maturities of three months or less to be cash equivalents for purposes of the Consolidated Statement of Cash Flows and other statements. These investments are carried at cost, which approximates fair value. In case a book overdraft exists at the end of a period, we reclassify the negative cash amount to accounts payable.

Restricted Cash

Restricted cash consists of certificates of deposit in place to collateralize letters of credit issued to governmental agencies. The letters of credit are required as part of normal business operations. The certificates of deposit will be in place for a period greater than 12 months and are considered noncurrent.

Inventory

Inventory consists of oil in field tanks that has been produced, but not yet sold. Inventory is stated at the lower of cost or market. We have adopted the FIFO (first-in first-out) accounting method. The cost of oil inventory sold is recorded to “Cost of oil sales” on the Consolidated Statement of Operations. We did not record oil inventory impairment expense in 2015 and 2014.

Oil and Gas Properties

We use the successful efforts method of accounting for natural gas and crude oil producing activities. Costs to acquire mineral interests in natural gas and crude oil 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. There were no capitalized exploratory drilling costs pending evaluation at December 31, 2015. There were $11.1 million of capitalized exploratory drilling costs pending evaluation at December 31, 2014.

The following table reflects the net changes in capitalized exploratory well costs:


	For the year ended December 31, 2015			For the year ended December 31, 2014
Balance, beginning of period	$	11,133,624		$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		—			11,133,624
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(5,138,634	)		—
Capitalized exploratory well costs charged to expense		(5,994,990	)		—

Balance, end of period	$	—		$	11,133,624

F-34

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed:


	December 31,
	2015		2014
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	—	$	11,133,624
Capitalized exploratory well costs that have been capitalized for a period greater than one year		—		—

	$	—	$	11,133,624

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. We recorded impairment of $1.2 million as exploration expense for unproved oil and gas properties for the year ended December 31, 2015. We had no leasehold impairment expense for the year ended December 31, 2014.

Capitalized costs of producing natural gas and crude oil 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 and probable 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. We recorded impairment expense of $9.3 million and $24.7 million to proved oil and gas properties for the year ended December 31, 2015 and 2014, respectively. The impairment resulted from lower projected oil and gas prices and a drop in projected remaining reserves in East Texas and our non-core fields.

Oil and Gas Reserves

The estimates of proved natural gas, crude oil and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB), 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. Proved reserves as of December 31, 2015 and 2014 were prepared by qualified petroleum engineers on our staff and audited by the independent petroleum engineering firm of Cawley, Gillespie & Associates, Inc. (CG&A).

F-35

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of natural gas, crude oil and natural gas liquids reserves, the remaining estimated lives of the natural gas and crude oil properties, or any combination of the above may be increased or reduced. See Note 14—“Supplemental Oil and Gas Information (unaudited)” for further information.

Gathering System

In 2015, our Oakfield subsidiary constructed and began operating a 15.2 mile 16” natural gas gathering system in order to provide sufficient, cost effective access to major markets for our existing and expected future production from new horizontal wells in North Louisiana. The wells are charged a fee for gathering services based on their throughput volumes and gas quality. In 2015, only wells operated by us were connected to the system. We are depreciating the Oakfield gathering assets on a straight-line basis over the current expected reserve life of wells connected to the system.

Other Property and Equipment

Other property and equipment includes our gathering system, leasehold improvements, office furniture, automobiles, computer equipment, software, pipelines, office buildings and land. Other property and equipment is depreciated using a straight-line method over the expected useful lives of the respective assets. Leasehold improvements are amortized over the remaining term of the lease and land is not depreciated or amortized.

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. For the year ended December 31, 2015 and 2014, we recorded $0.8 million and $0.2 million in capitalized interest, respectively.

Properties Acquired in Business Combinations

Assets and liabilities acquired in a business combination are required to be recorded at fair value. If sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of crude oil and natural gas reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3—“Acquisitions.”

Asset Retirement Obligations

We recognize a liability equal to the fair value of the estimated cost to plug and abandon our natural gas and crude oil wells and associated equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which the related assets are placed in service or acquired. The liability is accreted to its expected future cost each period and the capitalized cost is depleted using the units-of-production method of the related asset. The accretion expense is included in depreciation, depletion and amortization expense.

The fair value of the estimated cost is based on historical experience, managements’ expertise and third-party proposals for plugging and abandoning wells. The estimated remaining lives of the wells is based on

F-36

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

reserve life estimates and federal and state regulatory requirements. At the time the related long-lived asset is placed in service, the estimated cost is adjusted for inflation based on the remaining life, then discounted using a credit-adjusted risk-free rate to determine the fair value.

Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, including non-operated plug and abandonment expense, changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs.

Environmental Costs

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. Environmental expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

Revenue Recognition and Oil and Gas Imbalances

We follow the “sales” method of accounting for natural gas, crude oil and natural gas liquids revenues. Under this method, we recognize revenues on production as it is taken and delivered to our purchasers and revenues are recorded net of gathering and processing expense. The gas volumes sold may be more or less than the gas volumes we are entitled to based on our ownership interest in the property. 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.

Accounts Receivable

We grant credit to creditworthy independent and major natural gas and crude oil marketing companies for the sale of natural gas, crude oil and natural gas liquids. In addition, we grant credit to our oil and gas working interest partners. Receivables from our working interest partners are generally secured by the underlying ownership interests in the properties.

Accounts receivable balances primarily relate to joint interest billings and oil and gas sales, net of our interest. The accounts receivable balance generally includes two months of accrued revenues for operated properties and three months of accrued revenues for non-operated properties net of any collections related to those periods. The accounts receivable balance also includes other miscellaneous balances.

Accounts receivable are recorded at the amount we expect to collect. We use the specific identification method of providing allowances for doubtful accounts. As of December 31, 2015, we recorded a provision for uncollectible accounts of $0.1 million. There were no material bad debt write-offs in 2014. No provision for uncollectible accounts was established as of December 31, 2014.

Derivative Instruments

We periodically enter into derivative contracts to manage our exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that we believe have minimal credit risks, take the form of variable to fixed price swaps. The natural gas reference price, upon which the commodity derivative contracts are based, reflects market indices that have a high degree of historical correlation with actual prices received for natural gas sales.

F-37

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

We account for our derivative instruments in accordance with FASB Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging , which requires that all derivative instruments, other than those that meet the normal purchases and sales exception, be recorded on the balance sheet as either an asset or liability measured at fair value. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. Changes in fair value are recognized currently in earnings. Realized and unrealized gains and losses from our oil, gas, natural gas liquids and interest derivatives are recognized in “Other income (expense).” We compute the fair value of the unrealized gains and losses on our derivative instruments using forward prices and dealer quotes provided by a third party.

Lease Expenses

We record escalating lease expenses for our corporate office over the life of the lease on a straight-line basis.

Debt Issuance Costs

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt on a straight-line basis.

Fair Value Measurements

Accounting guidance for fair value measurements establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 4—“Fair Value Measurements.”

Income Taxes

We are taxed as a partnership for U.S. federal and most state income tax purposes. As a result, our members are responsible for federal and state income taxes on their share of our taxable income. Our consolidated subsidiary WHRM is taxed as a corporation for federal and state income tax purposes. We are also subject to the Texas franchise tax and certain aspects of the tax make it similar to an income tax.

Deferred income taxes arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. We had a net deferred income tax benefit of $0.2 million and $0.1 million in 2015 and 2014, respectively.

We must recognize the income tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the income tax effect that would be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized. There were no uncertain tax positions that required recognition in the consolidated financial statements at December 31, 2015 and 2014.

F-38

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

Supplemental Cash Flow Information

Supplement cash flow for the periods presented:


	For the year ended December 31, 2015			For the year ended December 31, 2014
Supplemental cash flows:
Cash paid for interest	$	3,131,088		$	2,514,714
Noncash investing activities:
(Decrease) increase in capital expenditures in accounts payables and accrued liabilities		(2,472,752	)		5,529,602

New Accounting Standards

Leases . In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently evaluating the standard and the impact on the Company’s financial statements and related footnote disclosures.

Balance Sheet Classification of Deferred Taxes . In November 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We do not expect the impact of adopting this guidance to be material to our financial statements and related disclosures.

F-39

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

completed at the acquisition date is required. The disclosure is required for each affected income statement line item, and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. We do not expect the impact of adopting this guidance to be material to our financial statements and related disclosures.

Presentation of Debt Issuance Cost . In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that the SEC would not object to debt issuance costs related to line-of-credit arrangements being deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We have elected this presentation in our consolidated financial statements and footnote disclosures as of December 31, 2015 and 2014.

Revenue from Contracts with Customers . In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2018. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, if any.

3.	Acquisitions

2014 Activity

On February 7, 2014, a Consent Agreement was executed for the assignment of certain oil and gas properties in east Texas subject to the Purchase and Sale Agreement executed June 17, 2013 for cash consideration of $17.1 million. After adjustments for net revenues and expenses and other customary adjustments between the May 1, 2013 effective date and the February 20, 2014 closing date, the net adjusted purchase price was $16.0 million. The purchase price was primarily allocated to oil and gas properties.

On June 3, 2014, we acquired oil and gas producing properties and leases in north Louisiana for cash consideration of $37.2 million. After adjustments for net revenues and expenses and other customary adjustments between the April 1, 2014 effective date and the July 15, 2014 closing date, the net adjusted purchase price was

F-40

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

$37.1 million. Assumed liabilities include suspended amounts payable to royalty and other working interest owners. The purchase price was primarily allocated to oil and gas properties.

On August 14, 2014, we acquired oil and gas producing properties and leases in north Louisiana for cash consideration of $2.9 million. After adjustments for net revenues and expenses and other customary adjustments between the April 1, 2014 effective date and the August 14, 2014 closing date, the net adjusted purchase price was $2.9 million. The purchase price was primarily allocated to oil and gas properties.

On October 13, 2014, we acquired oil and gas producing properties and leases in north Louisiana for cash consideration of $12.9 million. After adjustments for net revenues and expenses and other customary adjustments between the August 1, 2014 effective date and the November 7, 2014 closing date, the net adjusted purchase price was $12.8 million. Assumed liabilities include suspended amounts payable to royalty and other working interest owners. The purchase price was primarily allocated to oil and gas properties.

The total purchase price for these transactions was as follows:


Total Purchase Price
Cash paid	$	68,496,827
Net liabilities assumed		283,483

	$	68,780,310

The total purchase price for our 2014 acquisitions was considered to be at fair value. To estimate fair value of the properties as of the acquisition dates, we used an income approach. We utilized discounted cash flow models, which took into account various inputs including estimated quantities of crude oil, natural gas and natural gas liquids, estimated future commodity prices, estimated future production rates, and estimated timing and amounts of future operating and development costs.

To estimate the fair value of proved properties, we discounted the expected future net cash flows using rates commensurate with the associated risk determined appropriate at the acquisition date. To compensate for the inherent risk of estimating and valuing unproved properties, we reduced the discounted future net cash flows of probable reserves by additional risk-weighting factors. We used current acquisition prices to value term acreage costs. The fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements.

We had acquisition related expenses of $1.5 million in 2014 relating to these transactions. These acquisition related expenses were charged to General and administrative expenses in our Consolidated Statement of Operations.

4.	Fair Value Measurements

Certain of our assets and liabilities are reported at fair value on our balance sheets. The following methods and assumptions were used to estimate the fair values for each class of financial instruments:

Our financial instruments consist of cash and cash equivalents, receivables, inventory, payables, and debt instruments. We believe that the carrying value of these instruments on the Consolidated Balance Sheets approximate their fair value.

Our derivative instruments, stated at fair value, consist of variable to fixed price commodity swaps. The fair value of the derivative instruments were independently valued using forward prices and dealer quotes by a third party. See Note 5—“Derivative Instruments” for further information.

F-41

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

Fair value information for our financial assets and liabilities that are measured at fair value each reporting period is as follows at December 31, 2015 and 2014:


	Total Carrying Value		Fair Value Measurements Using
	Total Carrying Value		Level 1		Level 2		Level 3
December 31, 2015
Financial Assets
Commodity derivative instruments	$	5,651,703	$	—	$	5,651,703	$	—
Financial Liabilities
Commodity derivative instruments		—		—		—		—

	$	5,651,703	$	—	$	5,651,703	$	—

December 31, 2014
Financial Assets
Commodity derivative instruments	$	7,227,529	$	—	$	7,227,529	$	—
Financial Liabilities
Commodity derivative instruments		—		—		—		—

	$	7,227,529	$	—	$	7,227,529	$	—

FASB guidance established a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.

5.	Derivative Instruments

We have entered into certain derivative arrangements with respect to portions of our natural gas and oil production to reduce our sensitivity to volatile commodity prices. None of our derivative instruments are designated as cash flow hedges. We believe that these derivative arrangements, although not free of risk, allow us to achieve more predictable cash flows and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of natural gas and oil sales. Moreover, our derivative arrangements apply only to a portion of our production and provide only partial protection against declines in commodity prices. Such arrangements may expose us to risk of financial loss in certain circumstances. We continuously reevaluate our risk management program in light of changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements.

At the end of each reporting period, we record on our balance sheets the mark-to-market valuation of our derivative instruments. We recorded net assets for derivative instruments of $5.7 million and $7.2 million at December 31, 2015 and 2014, respectively. No unamortized premiums were reported at December 31, 2015 and 2014.

F-42

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

At December 31, 2015 and 2014, we had the following outstanding derivative instruments recorded in our balance sheet:


					Consolidated Balance Sheet Location
	Gross Fair Value				Derivative Assets				Derivative Liabilities
	Asset		Liability		Current		Non-current		Current		Non-current
December 31, 2015
Commodity price	$	5,651,703	$	—	$	4,236,196	$	1,415,507	$	—	$	—
December 31, 2014
Commodity price	$	7,227,529	$	—	$	6,843,054	$	384,475	$	—	$	—

Gains and losses for commodity derivatives are included in “Other income (expense)” on the Consolidated Statements of Operations. The following table details the effect of derivative contracts on “Other income (expense):”


	Amount of Gain (Loss) Recognized
	For the year ended December 31, 2015		For the year ended December 31, 2014
Commodity price	$	9,510,313	$	6,513,966

We use fixed price commodity swaps to accomplish our hedging strategy. Collars consisting of a sold call and purchased put are used to establish a ceiling price and floor price, for expected future natural gas sales. The sold call establishes the maximum price that we will receive for the contracted commodity volumes. The purchased put establishes the minimum price that we will receive for the contracted volumes. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. We have exposure to financial institutions in the form of derivative transactions. These transactions are with counterparties in the financial services industry, specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. We have master netting agreements for our derivative transactions with our counterparties and although we do not require collateral, we believe our counterparty risk is low because of the credit worthiness of our counterparties. See Note 4—“Fair Value Measurements” for further information.

The following derivative contracts were in place at December 31, 2015:


Natural Gas
	Collars						Variable to Fixed Price Swaps
Year	MMBtu’s Per Month		Weighted Average Floor Price		Weighted Average Ceiling Price		MMBtu’s Per Month		Weighted Average Fixed Price
2016		150,000	$	3.00	$	3.41		310,000	$	3.29
2017		200,000	$	3.20	$	3.65		40,000	$	3.01


Oil
	Variable to Fixed Price Swaps
Year	Barrels Per Month		Weighted Average Fixed Price
2016		2,250	$	50.43
2017		1,500	$	53.75

F-43

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

The following derivative contracts were in place at December 31, 2014:


Natural Gas
	Variable to Fixed Price Swaps
Year	MMBtu’s Per Month		Weighted Average Fixed Price
2015		570,000	$	4.03
2016		60,000	$	4.00

In accordance with the revolving credit agreement (Credit Agreement) entered into August 8, 2013, as amended, we are restricted from entering into derivative agreements, other than paid up premium-based options or basis differential swaps on volumes already hedged, that in the aggregate total more than 85% and 75%, for the first 24 months and the next 36 months, respectively, of the then reasonably anticipated production from proved oil and gas properties but comprising not more than 30% from proved undeveloped reserves. Additionally, we shall not enter into interest rate swap agreements where the notional amount aggregates greater than 90% of the then outstanding debt of the Credit Agreement. A subsequent change in anticipated production or a subsequent change in the amount of outstanding debt does not require a modification to existing derivative positions. We had no interest rate swap agreements in place as of December 31, 2015 and 2014.

6.	Accounts Receivable

Accounts receivable consist of the following:


	December 31,
	2015			2014
Oil, gas and NGL sales	$	3,596,021		$	3,419,764
Joint interest billings		3,455,023			18,640,970
Severance tax		530,498			3,912,488
Other current receivables		389,222			363,717
Allowance for doubtful accounts		(50,000	)		—

	$	7,920,764		$	26,336,939

In 2015 and 2014, there were two and three customers that, respectively, purchased 61% and 82%, respectively, of our production.

7.	Accrued Liabilities

Accrued liabilities consist of the following:


	December 31,
	2015		2014
Production and drilling projects	$	7,360,979	$	5,635,173
Deferred rent		362,999		339,505
Lease operating expense		917,793		910,520
General and administrative		241,640		432,366
Severance and ad valorem taxes		414,682		344,025
Interest expense		46,110		141,000
Other accrued liabilities		142,063		38,586

	$	9,486,266	$	7,841,175

F-44

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

8.	Asset Retirement Obligations

A reconciliation of our asset retirement obligation liability is as follows:


	For the year ended December 31,
	2015			2014
Balance, beginning of period	$	5,935,756		$	4,990,570
Accretion expense		341,552			309,344
Liabilities incurred		467,311			676,441
Liabilities settled		(8,413	)		—
Revisions		2,225			(40,599	)

Balance, end of period	$	6,738,431		$	5,935,756

There were no asset retirement liabilities incurred from acquisitions in 2015. In 2014, we acquired new wells with retirement obligations of $0.6 million. In 2015 and 2014, we drilled new wells with retirement obligations of $0.3 million and $0.1 million, respectively. In 2015, we constructed a new gathering system with a retirement obligation of $0.1 million

Debt

Credit Agreement

On August 8, 2013, we entered into a revolving credit agreement (Credit Agreement) with Bank of Montreal as the administrative agent, Bank of America, N.A. and Wells Fargo Bank, National Association as co-syndication agents, Comerica Bank and U.S. Bank National Association as co-documentation agents, and other banks. The Credit Agreement was amended on September 21, 2013.

The Credit Agreement provides for aggregate maximum credit amounts of $500.0 million, consisting of borrowings and letters of credit and was issued with an initial borrowing base of $130.0 million. The borrowing base as of December 31, 2015 and 2014 was $120.0 million and $140.0 million, respectively. The borrowing base is re-determined semi-annually, with WHR II and the bank group each having the right to one interim unscheduled redetermination between scheduled redeterminations. The Credit Agreement is used for acquisitions of oil and gas properties, working capital for lease acquisitions, for exploration and production operations and for development, including the drilling and completion of new wells and for general corporate purposes. The Credit Agreement requires that we provide the bank group a first priority lien on our oil and gas properties such that those properties subject to the lien represent at least 80% of the total value of the proved oil and gas properties. Additional debt outside of the Credit Agreement is significantly restricted. Unless previously terminated, the Credit Agreement shall terminate on the maturity date, August 8, 2018. There were no current maturities under the Credit Agreement as of December 31, 2015 and 2014.

The Credit Agreement includes the usual and customary covenants for credit facilities of its type and size. The covenants cover matters such as mandatory reserve reports, the responsible operation and maintenance of properties, certifications of compliance, required disclosures to the bank group, notices under other material instruments, notices of sales of oil and gas properties, incurrence of additional indebtedness, restricted payments and distributions, certain leases and investments outside of the ordinary course of business, limits on the amount of commodity and interest rate hedges that can be put in place, and events of default.

The Credit Agreement also contains two principal quarterly financial covenants: (i) maintaining a ratio of EBITDAX to Interest Expense of at least 2.5 to 1.0 and (ii) maintaining a ratio of Current Assets (including the undrawn borrowing base amount but excluding non-cash derivatives) to Current Liabilities (excluding non-cash derivatives) of at least 1.0 to 1.0. During 2015 and 2014, we were in compliance with all covenants.

F-45

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

We may choose from two interest rates: (i) the Eurodollar rate, which is based on LIBOR (London Interbank Offered Rate), plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 1.50% to 2.50%; and (ii) the Alternate Base Rate (ABR), which is based on the highest of (a) the U.S. Prime rate, (b) the Federal Funds Effective Rate in effect plus 1/2 of 1% and (c) Adjusted LIBOR plus 1%, plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 0.50% to 1.50%. From the inception of the Credit Agreement, predominately all our debt outstanding has been in the form of Eurodollar borrowings based on the Eurodollar rate. There is also a commitment fee of between 0.375% and 0.50% on the undrawn borrowing base amounts.

The cost to enter into the credit facility was $1.0 million, which is being amortized over the life of the Credit Agreement.

In 2015 and 2014, the interest incurred under the Credit Agreement was $3.1 million and $2.5 million, respectively. The weighted average interest rate for 2015 and 2014 was 2.6% and 2.4%, respectively. The outstanding debt under the Credit Agreement as of December 31, 2015 and 2014 was $118.0 million and $111.1 million, respectively. Commitment fees of $0.1 million and $0.1 million were incurred in 2015 and 2014, respectively.

10.

Commitments and Contingencies

Legal Contingencies

We are party to various ongoing and threatened legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of December 31, 2015 and 2014. Our estimates are based on information known about the matters and the input of attorneys experienced in contesting, litigating, and settling similar matters. Actual amounts could differ from our estimates and other claims could be asserted.

Environmental

From time to time, we could be liable for environmental claims arising in the ordinary course of business. At December 31, 2015 and 2014, no environmental obligations were recognized.

Transportation

We were assigned a firm gas transportation service agreement with Regency Intrastate Gas LLC (The Transporter) as a result of our property acquisition on August 8, 2013. 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 the Transporter until March 5, 2019.

F-46

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

Our minimum commitments to the Transporter as of December 31, 2015 and 2014 were as follows:


	December 31, 2015		December 31, 2014
2015	$	—	$	4,380,000
2016		4,392,000		4,392,000
2017		4,380,000		4,380,000
2018		4,380,000		4,380,000
2019		768,000		768,000

Total	$	13,920,000	$	18,300,000

Lease Obligations

We currently lease corporate office space through May 31, 2021. Total general and administrative rent expense for the year ended December 31, 2015 and 2014 was $0.8 million and $0.5 million, respectively. WHRM entered into the office lease agreement in 2013 that has escalating payments between July 2014 and May 2021. The average annual lease payment is $1.2 million over the life of the lease.

We have entered into drilling services agreements with varying terms. These contracts will expire at various times with the latest expiring in December 2016. We also have entered into compressor and equipment rental agreements with various terms. The compressor and equipment rental agreements expire at various times with the latest expiring in June 2016. Most of these agreements contain 30 day termination clauses. Total compressor and equipment rental expense incurred in 2015 and 2014 was $1.0 million and $0.7 million, respectively.

The table below reflects our minimum commitments as of December 31, 2015:


	Office Lease		Drilling Services		Compressor and Equipment
2016	$	1,211,899	$	10,760,400	$	85,255
2017		1,235,393		—		—
2018		1,258,887		—		—
2019		1,282,381		—		—
2020		1,305,875		—		—
Thereafter		548,193		—		—

Total	$	6,842,628	$	10,760,400	$	85,255

The table below reflects our minimum commitments as of December 31, 2014:


	Office Lease		Drilling Services		Compressor and Equipment
2015	$	1,188,405	$	10,701,600	$	569,403
2016		1,211,899		10,760,400		—
2017		1,235,393		—		—
2018		1,258,887		—		—
2019		1,282,381		—		—
Thereafter		1,854,068		—		—

Total	$	8,031,033	$	21,462,000	$	569,403

F-47

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

Letter of Credit and Certificate of Deposit

Standby letters of credit were issued to the Louisiana Office of Conservation and the Railroad Commission of Texas for our account for $0.3 million in 2014. In 2015, the standby letter of credit issued to the Louisiana Office of Conservation for our account was increased $0.3 million. The letters of credit are to insure our compliance with regulatory requirements. These letters of credit are collateralized by three Certificates of Deposits; the fair value of the Certificates of Deposits was $0.6 million and $0.3 million at December 31, 2015 and 2014, respectively. The amounts of the letters of credit and the Certificates of Deposit are adjusted depending on the requirements of the related governmental agency. The Certificates of Deposit are classified as restricted noncurrent assets and are not considered operating cash for the purposes of the Consolidated Statement of Cash Flows.

Incentive Plan

The Limited Liability Company Agreement (Company Agreement) allows for the sharing of gain upon our monetization either through a return of capital contributions, plus multiples of capital, through recapitalization, sale or merger or through a return of capital to the Members through other means.

The Company Agreement allows for the sharing of gain upon monetization through Incentive Units. From time to time, the Board of Managers has and may issue Incentive Units in consideration of services rendered by employees. The payout is generally dependent upon monetization achieved by the Members, with payments in the form of cash or property.

The amount of participation by employees can vary from 0% to 40% of the gain depending upon the level of monetization achieved by the Members. There were no special distributions awarded by the Board of Managers in 2015 and 2014. Therefore, no compensation costs associated with the Incentive Plan were recorded in 2015 and 2014.

11.

Employee Defined Contribution Plan

We sponsor a 401(k) savings plan. All regular employees are eligible to participate and immediately vest. We make contributions to match employee contributions up to the first 6% of compensation deferred in the plan. We made contributions of $0.4 million and $0.2 million in 2015 and 2014, respectively. There are no other retirement based plans.

12.

Related Party Transactions

Member Contributions

We received capital contributions of $125.1 million and $89.5 million from our members in 2015 and 2014, respectively. Promissory note advances are available to management to fund future capital commitments. As of December 31, 2015 and 2014, promissory note advances outstanding to management were $2.4 million and $1.7 million, respectively. Promissory note advances carry an interest rate of 2.5%. In 2015 and 2014, $0.1 million and $0.2 million in interest was accrued to the promissory notes, respectively. In 2015 and 2014, management paid $0.1 million and $0.3 million of promissory note interest, respectively. In accordance with FASB ASC Topic 505: Equity , the promissory note advances and the related accrued interest receivable are presented in the balance sheet as a deduction from members’ equity.

F-48

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

WHR and Memorial Resource Development Corp.

WildHorse Resources, LLC (WHR) is an independent energy company engaged in the acquisition, exploitation, and development of natural gas and crude oil properties organized in the State of Delaware on August 7, 2007. WHR, a related party, is under common control. On August 8, 2013, a Management Agreement between WHR and WHR II was executed where WHR was appointed the Accounting and Operations Manager for WHR II with responsibilities including administrative and land services, operator services and financial and accounting services. As Accounting and Operations Manager, WHR received operated and non-operated revenues on our behalf and billed and received joint interest billings. In addition, WHR paid for lease operating expenses and drilling costs on our behalf. On August 8, 2013, an Asset and Cost Sharing Agreement between WHR and WHR II was executed. As part of the agreement, shared WHR general and administrative costs were allocated between WHR and WHR II in accordance with a sharing ratio. The sharing ratio was based on the previous quarter’s capital expenditures and number of operated wells. Company specific costs were billed directly to the appropriate entity. As a result of these agreements, we made net payments of $5.0 million to WHR in 2014.

On June 18, 2014 Memorial Resource Development Corp. (MRD), the principal member of WHR, completed an initial public offering. As a result of the offering, the Management Agreement between WHR and WHR II and the Asset Cost Sharing Agreement between WHR and WHR II were terminated.

On June 18, 2014, we purchased WildHorse Resources Management Company, LLC (WHRM) from WHR for $0.2 million becoming the sole member and manager of WHRM.

On June 18, 2014, a Management Services Agreement between MRD, as the parent of WHR, and WHRM, was executed where we agreed to provide accounting and operating transition services to WHR with responsibilities including administrative and land services, operator services and financial and accounting services. As Accounting and Operations Manager, we received operated and non-operated revenues on behalf of WHR and bill and receive joint interest billings. In addition, we paid for lease operating expenses and drilling costs on behalf of WHR. As a result of this agreement, we paid $57.6 million in net payments to WHR in 2015. We received net payments of $53.0 million from WHR and MRD in 2014. We were owed $0.0 million and $1.6 million, net, from WHR and MRD as of December 31, 2015 and 2014, respectively.

On February 25, 2015, the Management Services Agreement between MRD and WHRM was terminated with an effective date of March 1, 2015.

NGP Affiliated Companies

During the year ended December 31, 2015 and 2014, we made payments of $1.0 million and $6.5 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities.

During the year ended December 31, 2015 and 2014, we made payments of $0.1 million and $0.1 million, respectively, to Multi-Shot, LLC, a NGP affiliated company, for services related to our drilling and completion activities.

During the year ended December 31, 2015 and 2014, we received net payments of $0.1 million and $0.1 million, respectively, from PennTex Midstream Partners, LP, a NGP affiliated company, for the gathering, processing and transportation of natural gas and NGLs.

F-49

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

During the year ended December 31, 2015 and 2014, we made net payments of $0.4 million and $0.1 million, respectively, to Highmark Energy Operating, LLC, a NGP affiliated company, for non-operated working interests in oil and gas properties we operate.

WHRM

WHRM was organized in the State of Delaware on October 17, 2012 under the Delaware Limited Liability Company Act with WHR as the sole member and manager. The Management Services Agreement was executed on August 8, 2013, where WHRM began providing general, administrative and employee services to WHR II as well as WHR. WHRM shared costs were also subject to the same sharing ratio as the Asset and Cost Sharing Agreement between WHR and WHR II. As a result of this agreement, we made net payments of $6.0 million to WHRM in 2014.

On June 18, 2014, we purchased WHRM from WHR becoming the sole member and manager. All significant intercompany transactions after the purchase date have been eliminated in consolidation.

13.

Subsequent Events

On March 3, 2016, the drilling services agreement was terminated with an effective date of March 3, 2016. The amount owed to the drilling services contractor under the termination agreement is $7.6 million, which could be reduced if the released rig is subcontracted to another customer.

During 2016, we entered into the following commodity derivatives:

Commodity / Term

Contract
Type

Average
Monthly Volume

Price per Unit

Natural Gas

July 2016 – December 2016

Collar

45,000 Mmbtu’s

$2.32 - $2.61

June 2016 – December 2016

Collar

105,714 Mmbtu’s

$2.32 - $2.52

March 2016 – December 2016

Swap

200,000 Mmbtu’s

$2.33

Subsequent events were evaluated through the date the financial statements were issued, April 4, 2016. There were no other material subsequent events requiring additional disclosure in or amendments to these financial statements.

14.

Supplemental Oil and Gas Information (unaudited)

Proved reserves as of December 31, 2015 and 2014 were prepared by qualified petroleum engineers on our staff and audited by the independent petroleum engineering firm of CG&A. Estimated future net cash flows and present values were based upon the petroleum engineer’s review of historical production data and other geological, economic, ownership and engineering data. No reports on our reserves have been filed with any federal agency. In accordance with the SEC’s guidelines, our estimates of proved reserves and the future net revenues from which present values are derived are based on an unweighted 12-month average of the first-day-of-the-month price for the period, held constant throughout the life of the properties. Operating costs, development costs and certain production-related taxes were deducted in arriving at estimated future net revenues. The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in barrels (Bbl). Gas volumes are expressed in thousands of cubic feet (Mcf) at standard temperature and pressure bases. Total volumes are presented in thousands of cubic feet equivalent (Mcfe). For this computation, one barrel is the equivalent of 6,000 cubic feet of natural gas.

F-50

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

The following unaudited table sets forth proved natural gas, crude oil and natural gas liquids reserves, all within the United States, specifically north Louisiana and east Texas, at December 31, 2015 and 2014, together with the changes therein:


	Natural Gas (Mcf)			Crude (Bbls)			Natural Gas Liquids (Bbls)			Total (Mcfe)			Total Boe
Quantities of proved reserves
Balance, December 31, 2013		210,292,734			175,214			—			211,344,018			35,224,003
Purchases		13,683,960			17,115			—			13,786,650			2,297,775
Revisions		30,880,332			(2,710	)		(207,168	)		29,621,064			4,936,844
Extensions, discoveries and additions		4,317,958			62,949			572,882			8,132,944			1,355,491
Production		(9,388,187	)		(30,691	)		(41,383	)		(9,820,631	)		(1,636,722	)

Balance, December 31, 2014		249,786,797			221,877			324,331			253,064,045			42,177,341
Revisions		(45,925,392	)		57,792			145,785			(44,703,930	)		(7,450,655	)
Extensions, discoveries and additions		120,899,407			731,595			—			125,288,977			20,881,496
Production		(13,636,843	)		(73,117	)		(103,281	)		(14,695,231	)		(2,449,205	)

Balance, December 31, 2015		311,123,969			938,147			366,835			318,953,861			53,158,977

Noteworthy amounts included in the categories of proved reserve changes in the above table include:

•

During 2014, we acquired 2,298 MBoe of proved reserves, of which 1,888 MBoe was for non-core properties acquired in East Texas and 410 MBoe was a result of leaseholds acquired in our RCT field in Louisiana.

•

During 2014, we had upward performance revisions to total proved reserves of 4,937 MBoe, of which 3,043 MBoe related to gas processing, 1,405 MBoe related to LOE reductions and 517 MBoe related to changes in commodity prices, partially offset by a reduction of 28 MBoe due to changes in ownership interest.

•

During 2014, extensions, discoveries and additions increased proved reserves by 1,355 MBoe related to drilling two horizontal wells in East Texas.

•

During 2015, we had downward revisions of proved reserves of 7,450 MBoe, 3,410 MBoe of which related to commodity price changes and 4,040 MBoe of which related to downward revisions resulting from technical changes.

•

During 2015, extensions, discoveries and additions increased proved reserves by 20,881 MBoe related to drilling in our RCT field in Louisiana.


	Natural Gas (Mcf)		Crude (Bbls)		Natural Gas Liquids (Bbls)		Total (Mcfe)		Total Boe
Proved developed reserves,
December 31, 2013		97,733,422		175,214		—		98,784,706		16,464,118
December 31, 2014		122,780,281		221,877		324,331		126,057,529		21,009,588
December 31, 2015		134,168,828		443,901		366,835		139,033,244		23,172,207
Proved undeveloped reserves,
December 31, 2013		112,559,312		—		—		112,559,312		18,759,885
December 31, 2014		127,006,516		—		—		127,006,516		21,167,753
December 31, 2015		176,955,141		494,246		—		179,920,617		29,986,770

F-51

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

Costs incurred in oil and gas producing activities:


	For the year ended December 31, 2015		For the year ended December 31, 2014
Property acquisition costs
Proved	$	—	$	21,336,813
Unproved		22,201,001		69,729,226

Total acquisition cost		22,201,001		91,066,039
Development costs		57,956,840		28,253,686
Exploratory costs and expense		46,562,021		12,730,651

	$	126,719,862	$	132,050,376

These costs include oil and gas property acquisition, exploration and development activities regardless of whether the costs were capitalized or charged to expense, including lease rental expenses, geological and geophysical expenses and changes to the long-lived asset related to our asset retirement obligation. Development costs are the costs to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil, gas and natural gas liquids.

Capitalized costs relating to oil and gas producing activities as of December 31:


	2015			2014
Proved oil and gas properties	$	364,262,660		$	247,482,071
Unproved oil and gas properties		75,116,151			80,058,422

Total oil and gas properties		439,378,811			327,540,493
Less accumulated depletion and impairment		(76,884,248	)		(43,539,189	)

Net capitalized costs	$	362,494,563		$	284,001,304

Standardized measure of discounted future net cash flows relating to proved reserves:


	For the year ended December 31, 2015			For the year ended December 31, 2014
Future cash inflows	$	891,435,688		$	1,167,732,250
Future production and development costs
Production		(388,805,626	)		(420,781,109	)
Development		(147,270,156	)		(147,808,703	)
Future Texas Franchise Taxes		(216,104	)		(563,418	)

Future net cash flows		355,143,802			598,579,020
10% annual discount for estimated timing of cash flows		(212,888,480	)		(368,679,820	)

	$	142,255,322		$	229,899,200

As a LLC that is taxed as a partnership, there were no federal income taxes recorded related to oil and gas producing activities. Therefore, future federal income taxes were not computed in the standardized measure of discounted future net cash flows relating to current proved reserves.

F-52

WildHorse Resources II, LLC

Notes to Consolidated Financial Statements (continued)

Future cash inflows are computed by applying a 12-month average commodity price adjusted for location and quality differentials to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of derivative instruments. Average price per commodity:


Petroleum Product	For the year ended December 31, 2015		For the year ended December 31, 2014
Natural gas per Mcf	$	2.70	$	4.55
Crude oil per Bbl	$	47.81	$	94.16
Natural gas liquids per Bbl	$	14.79	$	34.09

The following table reconciles the change in the standardized measure of discounted future net cash flows:


	For the year ended December 31, 2015			For the year ended December 31, 2014
Standardized measure of discounted future net cash flow, beginning of year	$	229,899,200		$	165,180,744
Changes from
Purchases of proved reserves(1)		—			14,587,295
Extensions, discoveries and improved recovery, less related costs		68,738,413			20,194,807
Sales of natural gas, crude oil and natural gas liquids produced, net of production costs		(23,523,005	)		(29,497,811	)
Revision of quantity estimates(2)		(17,000,222	)		26,945,059
Accretion of discount		23,020,081			16,521,653
Changes in estimated future development costs		—			(3,193,809	)
Development costs incurred that reduced future development costs		—			190,000
Change in sales due to prices, net of production costs		(133,916,557	)		19,683,416
Net change in estimated Texas Franchise Taxes		170,700			(265,825	)
Changes in timing of estimated future production		(5,133,288	)		(446,329	)

Aggregate change in standardized measure of discounted future net cash flows		(87,643,878	)		64,718,456

Standardized measure of discounted future net cash flow, end of year	$	142,255,322		$	229,899,200

(1)	See Note 3—“Acquisitions.”

(2)	Periodic revisions to the quantity estimates may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil, natural gas and natural gas liquids, technological advances, new geological or geophysical data, or other economic factors.

F-53

WildHorse Resources II, LLC

Consolidated Balance Sheets

(Unaudited)


	September 30, 2016			December 31, 2015
Assets
Current assets
Cash and cash equivalents	$	1,335,685		$	22,224,690
Accounts receivable, net		11,563,698			7,920,764
Prepaid expenses		323,531			559,939
Deferred IPO costs		586,851			—
Derivative instruments		571,336			4,236,196

Total current assets		14,381,101			34,941,589

Property and equipment
Oil and gas properties		450,336,811			439,378,811
Other property and equipment		30,523,208			29,347,618
Accumulated depreciation, depletion, impairment and amortization		(105,754,509	)		(78,730,805	)

Total property and equipment, net		375,105,510			389,995,624

Noncurrent assets
Debt issuance costs		470,097			580,594
Restricted cash		636,240			550,581
Derivative instruments		147,772			1,415,507
Other noncurrent assets		249,429			365,748

Total noncurrent assets		1,503,538			2,912,430

Total assets	$	390,990,149		$	427,849,643

Liabilities and members’ equity
Current liabilities
Accounts payable	$	8,081,250		$	17,607,171
Accrued liabilities		3,342,131			9,486,266
Derivative instruments		1,489,752			—
Asset retirement obligations		90,000			90,000

Total current liabilities		13,003,133			27,183,437

Noncurrent liabilities
Long-term debt		108,500,000			118,000,000
Asset retirement obligations		6,940,431			6,648,431
Derivative instruments		331,539			—
Other noncurrent liabilities		1,619,452			1,883,537

Total noncurrent liabilities		117,391,422			126,531,968

Total liabilities		130,394,555			153,715,405

Members’ equity
Members’ equity		337,973,750			324,693,750
Accumulated deficit		(77,378,156	)		(50,559,512	)

Total members’ equity		260,595,594			274,134,238

Total liabilities and members’ equity	$	390,990,149		$	427,849,643

The Notes to these Unaudited Consolidated Financial Statements are an integral part of these statements.

F-54

WildHorse Resources II, LLC

Consolidated Statements of Operations

(Unaudited)


	Nine Months Ended, September 30, 2016			Nine Months Ended, September 30, 2015
Operating revenues
Natural gas	$	25,273,466		$	23,381,342
Crude oil		2,970,883			2,239,823
Natural gas liquids		658,415			1,099,755
Gathering system income		1,157,919			—

Total operating revenues		30,060,683			26,720,920

Operating expenses
Lease operating expenses		4,542,850			6,177,938
Gathering system operating expenses		99,152			317,297
Production and ad valorem taxes		1,842,859			1,890,764
Depreciation, depletion and amortization		27,305,199			17,515,851
Impairment of proved oil and gas properties		—			8,031,780
General and administrative		8,398,927			7,475,021
Exploration expenses		8,973,306			14,306,355

Total operating expenses		51,162,293			55,715,006

(Loss) from operations		(21,101,610	)		(28,994,086	)

Other income (expense)
Interest expense		(2,731,885	)		(2,248,877	)
Other (expense) income		(76,226	)		9,379
(Loss) gain on derivative instruments		(2,894,373	)		6,062,755

Total other (expense) income		(5,702,484	)		3,823,257

Net loss before income taxes		(26,804,094	)		(25,170,829	)

Income tax (expense) benefit		(14,550	)		81,578
Net loss	$	(26,818,644	)	$	(25,089,251	)

The Notes to these Unaudited Consolidated Financial Statements are an integral part of these statements.

F-55

WildHorse Resources II, LLC

Consolidated Statements of Members’ Equity

(Unaudited)

For the period from December 31, 2015 to September 30, 2016


	Contributed Capital			Accumulated Deficit			Members’ Equity
Balance, December 31, 2015	$	324,693,750		$	(50,559,512	)	$	274,134,238
Capital contributions		13,405,578			—			13,405,578
Notes receivable from members		(125,578	)		—			(125,578	)
Net loss		—			(26,818,644	)		(26,818,644	)

Balance, September 30, 2016	$	337,973,750		$	(77,378,156	)	$	260,595,594

The Notes to these Unaudited Consolidated Financial Statements are an integral part of these statements.

F-56

WildHorse Resources II, LLC

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended, September 30, 2016			Nine Months Ended, September 30, 2015
Cash flows from operating activities
Net loss	$	(26,818,644	)	$	(25,089,251	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		27,023,704			17,264,663
Impairment of proved oil and gas properties		—			8,031,780
Dry hole expense and impairments of unproved properties		62,089			8,418,034
Accretion of asset retirement obligations		281,495			251,188
Amortization of debt issuance cost		182,538			165,709
Loss (gain) on derivative instruments		2,894,373			(6,062,755	)
Cash settlements on derivative instruments		3,898,111			6,979,862
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(3,565,214	)		18,787,226
Decrease in prepaid expenses		236,408			257,412
(Increase) in inventories		—			(1,610,506	)
(Increase) in deferred IPO costs		(586,851	)		—
(Decrease) in accounts payable		(11,829,125	)		(16,574,725	)
(Decrease) increase in accrued liabilities		(1,321,040	)		75,498

Net cash (used in) provided by operating activities		(9,542,156	)		10,894,135

Cash flows from investing activities
Additions of oil and gas properties and other property and equipment		(14,969,149	)		(109,607,955	)
Sales of other property and equipment		—			16,247
Increase in restricted cash		(85,659	)		(250,211	)

Net cash used in investing activities		(15,054,808	)		(109,841,919	)

Cash flows from financing activities
Advances on revolving credit facility		8,000,000			48,900,000
Payments on revolving credit facility		(17,500,000	)		(35,500,000	)
Member contributions		13,280,000			105,207,525
Debt issuance costs		(72,041	)		(13,523	)

Net cash provided by financing activities		3,707,959			118,594,002

(Decrease) increase in cash and cash equivalents		(20,889,005	)		19,646,218
Cash and cash equivalents
Beginning of period		22,224,690			12,188,321
End of period	$	1,335,685		$	31,834,539

Cash paid for interest	$	2,584,126		$	2,081,324

The Notes to these Unaudited Consolidated Financial Statements are an integral part of these statements.

F-57

WILDHORSE RESOURCES II, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1.	Organization

WildHorse Resources II, LLC (the Company, WHR II, we, our or us) is an independent energy company engaged in the acquisition, exploitation, and development of natural gas and crude oil properties. We were organized in the State of Delaware on June 3, 2013 under the Delaware Limited Liability Company Act with NGP X US Holdings, L.P. (NGP X), a Delaware limited partnership, as the principal member. We have focused our operations in the State of Louisiana and the State of Texas. We intend to grow reserves and production by developing our existing producing property base and by pursuing opportunistic acquisitions in areas where we have specific operating expertise.

No Member shall be liable for our debts, liabilities, contracts or other obligations except for any unpaid capital commitments of such Member and as otherwise provided in the Delaware Limited Liability Company Act. We will be dissolved no later than August 5, 2020, unless the Limited Liability Company Agreement is modified.

2.	Summary of Significant Accounting Policies

Basis of Presentation

For a complete description of our significant accounting policies, see Note 2—Summary of Significant Accounting Policies in our audited financial statements included herein.

Use of Estimates in the Preparation of Financial Statements

F-58

WILDHORSE RESOURCES II, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil and gas 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) environmental remediation costs; (7) valuation of derivative instruments and (8) 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.

New Accounting Standards

Balance Sheet Classification of Deferred Taxes . In November 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We do not expect the impact of adopting this guidance to be material to our financial statements and related disclosures.

F-59

WILDHORSE RESOURCES II, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

Presentation of Debt Issuance Cost . In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that the SEC would not object to debt issuance costs related to line-of-credit arrangements being deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We have elected this presentation in our consolidated financial statements and footnote disclosures as of September 30, 2016 and December 31, 2015.

Revenue from Contracts with Customers . In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. In May 2016, the FASB issued additional guidance, addressed implementation issues and provided technical corrections. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2018. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, if any.

3.	Acquisitions

There were no material acquisitions during the nine months ended September 30, 2016 and 2015, respectively.

4.	Fair Value Measurements

Our derivative instruments, stated at fair value, consist of variable to fixed price commodity swaps. The fair value of the derivative instruments were independently valued using forward prices and dealer quotes by a third party. See Note 4—“Derivative Instruments” for further information.

F-60

WILDHORSE RESOURCES II, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

Fair value information for our financial assets and liabilities that are measured at fair value each reporting period is as follows at September 30, 2016 and December 31, 2015:


	Total Carrying Value			Fair Value Measurements Using
	Total Carrying Value			Level 1		Level 2			Level 3
September 30, 2016
Financial Assets
Commodity derivative instruments	$	719,108		$	—	$	719,108		$	—
Financial Liabilities
Commodity derivative instruments		(1,821,291	)		—		(1,821,291	)		—

	($	1,102,183	)	$	—	($	1,102,183	)	$	—

December 31, 2015
Financial Assets
Commodity derivative instruments	$	5,651,703		$	—	$	5,651,703		$	—
Financial Liabilities
Commodity derivative instruments		—			—		—			—

	$	5,651,703		$	—	$	5,651,703		$	—

5.	Derivative Instruments

At the end of each reporting period, we record on our balance sheets the mark-to-market valuation of our derivative instruments. We recorded net liabilities for derivative instruments of $1.1 million at September 30, 2016 and net assets for derivative instruments of $5.7 million at December 31, 2015. No unamortized premiums were reported at September 30, 2016 and December 31, 2015.

At September 30, 2016 and December 31, 2015, we had the following outstanding derivative instruments recorded in our balance sheet:


	Gross Fair Value					Consolidated Balance Sheet Location
	Gross Fair Value					Derivative Assets				Derivative Liabilities
	Asset		Liability			Current		Non- Current		Current			Non- Current
September 30, 2016
Commodity price	$	998,105	$	(2,100,288	)	$	571,336	$	147,772	$	(1,489,752	)	$	(331,539	)
December 31, 2015
Commodity price	$	5,651,703	$	—		$	4,236,196	$	1,415,507	$	—		$	—

F-61

WILDHORSE RESOURCES II, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)


	Amount of Gain (Loss) Recognized
Contract Type	Nine months ended September 30, 2016			Nine months ended September 30, 2015
Commodity price	$	(2,894,373	)	$	6,062,755

We use fixed price commodity swaps to accomplish our hedging strategy. Collars consisting of a sold call and purchased put are used to establish a ceiling price and floor price, for expected future natural gas sales. The sold call establishes the maximum price that we will receive for the contracted commodity volumes. The purchased put establishes the minimum price that we will receive for the contracted volumes. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. We have exposure to financial institutions in the form of derivative transactions. These transactions are with counterparties in the financial services industry, specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. We have master netting agreements for our derivative transactions with our counterparties and although we do not require collateral, we believe our counterparty risk is low because of the credit worthiness of our counterparties. See Note 3—“Fair Value Measurements” for further information.

The following derivative contracts were in place at September 30, 2016:


Natural Gas
	Collars						Variable to Fixed Price Swaps
Year	MMBtu’s Per Month		Weighted Average Floor Price		Weighted Average Ceiling Price		MMBtu’s Per Month		Weighted Average Fixed Price
2016		460,000	$	2.62	$	2.94		690,000	$	2.87
2017		460,000	$	3.00	$	3.36		300,000	$	2.83
2018		—	$	—	$	—		170,000	$	2.95


Oil
	Variable to Fixed Price Swaps
Year	Barrels Per Month		Weighted Average Fixed Price
2016		2,000	$	50.41
2017		1,500	$	53.75

6.	Asset Retirement Obligations

A reconciliation of our asset retirement obligation liability is as follows:


	For the nine months ended September 30, 2016
Balance, beginning of period	$	6,738,431
Accretion expense		281,495
Liabilities incurred		14,658
Liabilities settled		(4,153	)

Balance, end of period	$	7,030,431

There were no asset retirement liabilities incurred from acquisitions for the nine months ended September 30, 2016.

F-62

WILDHORSE RESOURCES II, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

Debt

Credit Agreement

On August 8, 2013, we entered into a revolving credit agreement (Credit Agreement) with BMO Harris Bank, N.A., as the administrative agent, Bank of America, N.A. and Wells Fargo Bank, National Association as co- syndication agents, Comerica Bank and U.S. Bank National Association as co-documentation agents, and other banks. The Credit Agreement was amended on September 21, 2013.

The Credit Agreement provides for aggregate maximum credit amounts of $500.0 million, consisting of borrowings and letters of credit and was issued with an initial borrowing base of $130.0 million. The borrowing base as of September 30, 2016 and December 31, 2015 was $120.0 million. The borrowing base is re-determined semi-annually, with WHR II and the bank group each having the right to one interim unscheduled redetermination between scheduled redeterminations. The Credit Agreement is used for acquisitions of oil and gas properties, working capital for lease acquisitions, for exploration and production operations and for development, including the drilling and completion of new wells and for general corporate purposes. The Credit Agreement requires that we provide the bank group a first priority lien on our oil and gas properties such that those properties subject to the lien represent at least 80% of the total value of the proved oil and gas properties. Additional debt outside of the Credit Agreement is significantly restricted. Unless previously terminated, the Credit Agreement shall terminate on the maturity date, August 8, 2018. There were no current maturities under the Credit Agreement as of September 30, 2016 and December 31, 2015.

The Credit Agreement also contains two principal quarterly financial covenants: (i) maintaining a ratio of EBITDAX to Interest Expense of at least 2.5 to 1.0 and (ii) maintaining a ratio of Current Assets (including the undrawn borrowing base amount but excluding non-cash derivatives) to Current Liabilities (excluding non-cash derivatives) of at least 1.0 to 1.0. As of September 30, 2016 and December 31, 2015, we were in compliance with all covenants.

We may choose from two interest rates: (i) the Eurodollar rate, which is based on LIBOR (London Interbank Offered Rate), plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 1.50% to 2.50%; and (ii) the Alternate Base Rate (ABR), which is based on the highest of (a) the U.S. Prime rate, (b) the Federal Funds Effective Rate in effect plus ¹ / ₂ of 1% and (c) Adjusted LIBOR plus 1%, plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 0.50% to 1.50%. From the inception of the Credit Agreement, predominately all our debt outstanding has been in the form of Eurodollar borrowings based on the Eurodollar rate. There is also a commitment fee of between 0.375% and 0.50% on the undrawn borrowing base amounts.

The cost to enter into the credit facility was $1.0 million, which is being amortized over the life of the Credit Agreement.

For the nine months ended September 30, 2016 and 2015, the interest incurred under the Credit Agreement was $2.6 million and $2.4 million, respectively. The weighted average interest rate for the nine months ended September 30, 2016 and 2015 was 3.0% and 2.6%, respectively. The outstanding debt under the Credit Agreement as of September 30, 2016 and December 31, 2015 was $108.5 million and $118.0 million, respectively. Commitment fees of $0.1 million and $0.1 million were incurred for the nine months ended September 30, 2016 and 2015, respectively.

F-63

WILDHORSE RESOURCES II, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

8.	Commitments and Contingencies

Legal Contingencies

We are party to various ongoing and threatened legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of September 30, 2016 and December 31, 2015. Our estimates are based on information known about the matters and the input of attorneys experienced in contesting, litigating, and settling similar matters. Actual amounts could differ from our estimates and other claims could be asserted.

Incentive Plan

The amount of participation by employees can vary from 0% to 40% of the gain depending upon the level of monetization achieved by the Members. There were no special distributions awarded by the Board of Managers during the nine months ended September 30, 2016 and 2015, respectively. Therefore, no compensation costs associated with the Incentive Plan were recorded for the nine months ended September 30, 2016 and 2015, respectively.

9.	Related Party Transactions

Member Contributions

We received capital contributions of $13.3 million and $105.2 million from our members during the nine months ended September 30, 2016 and 2015, respectively. Promissory note advances are available to management to fund future capital commitments. As of September 30, 2016 and December 31, 2015, promissory note advances outstanding to management were $2.4 million. Promissory note advances carry an interest rate of 2.5%. For the nine months ended September 30, 2016 and 2015, $0.1 million and $0.1 million in interest was accrued to the promissory notes, respectively. There were no management payments of promissory note interest during the nine months ended September 30, 2016. During the nine months ended September 30, 2015, management made payments of $0.1 million for promissory note interest. In accordance with FASB ASC Topic 505: Equity, the promissory note advances and the related accrued interest receivable are presented in the balance sheet as a deduction from members’ equity.

WHR and Memorial Resource Development Corp.

WildHorse Resources, LLC (WHR) is an independent energy company engaged in the acquisition, exploitation, and development of natural gas and crude oil properties organized in the State of Delaware on August 7, 2007. On June 18, 2014 Memorial Resource Development Corp. (MRD), the principal member of WHR, completed an initial public offering.

On June 18, 2014, we purchased WildHorse Resources Management Company, LLC (WHRM) from WHR for $0.2 million becoming the sole member and manager of WHRM. All significant intercompany transactions after the purchase date have been eliminated in consolidation.

F-64

WILDHORSE RESOURCES II, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

On February 25, 2015, the Management Services Agreement between MRD and WHRM was terminated with an effective date of March 1, 2015.

No amounts were owed from MRD and WHR as of September 30, 2016 and December 31, 2015.

NGP Affiliated Companies

During the nine months ended September 30, 2016 and 2015, we received net payments of $0.2 million and $0.1 million, respectively, from Highmark Energy Operating, LLC, a NGP affiliated company, for non-operated working interests in oil and gas properties we operate.

During the nine months ended September 30, 2016 and 2015, we made payments of $0.4 million and $1.0 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities.

During the nine months ended September 30, 2016 and 2015, we made net payments of $0.1 million and received net payments of $0.1 million, respectively, from PennTex Midstream Partners, LP, a NGP affiliated company, for the gathering, processing and transportation of natural gas and NGLs.

10.

Subsequent Events

On October 13, 2016 an amendment to an option to acquire oil and gas leases in North Louisiana was executed to extend the expiration of the option period to October 23, 2017. The cash consideration paid in October 2016 for the extension was $1,541,715.

During October 2016, we entered into the following commodity derivatives:

Commodity / Term

Contract Type

Average Monthly
Volume

Price per Unit

Natural Gas

January 2017 – December 2017

Swap

280,000 Mmbtu’s

3.37

As of September 30, 2016 promissory note advances outstanding to management including interest were $2.6 million. On November 9, 2016, the management members conveyed to WildHorse certain ownership interests in WildHorse in exchange for the discharge in full and the termination of all the promissory note advances outstanding.

We have evaluated subsequent events of our consolidated financial statements. There were no further material subsequent events requiring additional disclosure in these financial statements.

F-65

Report of Independent Auditors

The Board of Managers

Esquisto Resources II, LLC and Subsidiaries

We have audited the accompanying consolidated financial statements of Esquisto Resources II, LLC and Subsidiaries (the Company) which comprise the consolidated balance sheets as of December 31, 2015 and 2014 and the related consolidated statements of operations, changes in members’ equity, and cash flows for the year ended December 31, 2015 and the period from June 20, 2014 (Inception) to December 31, 2014, and the related notes to the consolidated financial statements.

Management’s

Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s

Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Esquisto Resources II, LLC and Subsidiaries at December 31, 2015 and 2014 and the consolidated results of their operations and their cash flows for the year ended December 31, 2015 and the period from June 20, 2014 (Inception) to December 31, 2014, in conformity with U.S. generally accepted accounting principles.

/s/ ERNST & YOUNG LLP

Dallas, TX

August 10, 2016

F-66

Esquisto Resources II, LLC and Subsidiaries

Consolidated Balance Sheets

(In Thousands)


	December 31,
	2015			2014
Assets
Current assets:
Cash and cash equivalents	$	20,901		$	1,145
Accounts receivable—trade		5,816			2,941
Derivatives		2,840			—
Prepaid expenses		2,162			1,580

Total current assets		31,719			5,666
Property and equipment:
Oil and gas properties, successful efforts method:
Proved properties		348,246			102,112
Unproved properties		154,211			50,422
Accumulated depletion		(39,631	)		(7,332	)

Total property and equipment		462,826			145,202
Water assets		1,195			—
Derivatives		1,024			—

Total assets	$	496,764		$	150,868

Liabilities and members’ equity
Current liabilities:
Accounts payable	$	17,236		$	19,230
Accrued expenses and other current liabilities		19,437			16,075

Total current liabilities		36,673			35,305
Long-term debt		119,363			25,695
Notes payable to members		6,438			2,097
Deferred state tax liability		1,074			383
Asset retirement obligation		282			37
Commitments and contingencies		—			—
Members’ equity		332,934			87,351

Total liabilities and equity	$	496,764		$	150,868

The accompanying notes are an integral part of these consolidated financial statements.

F-67

Esquisto Resources II, LLC and Subsidiaries

Consolidated Statements of Operations

(In Thousands)


	Year Ended December 31, 2015			Period From June 20, 2014 (Inception) to December 31, 2014
Operating revenues:
Oil sales	$	42,376		$	13,352
Natural gas liquid sales		2,992			1,210
Natural gas sales		2,975			575

Total operating revenues		48,343			15,137
Operating costs and expenses:
Oil and natural gas production		6,509			998
Production taxes		2,275			735
Depletion and depreciation		32,300			7,331
Exploration and abandonments		2,967			2
General and administrative		5,671			2,388
Gain from derivative financial instruments		(4,344	)		—
Accretion of discount on asset retirement obligations		12			1

Total operating costs and expenses		45,390			11,455

Total operating income		2,953			3,682

Other income (expense):
Other income		7			—
Interest expense		(4,693	)		(606	)
State deferred tax expense		(691	)		(383	)
Other expense		(485	)		(333	)

		(5,862	)		(1,322	)

Net (loss) income	$	(2,909	)	$	2,360

The accompanying notes are an integral part of these consolidated financial statements.

F-68

Esquisto Resources II, LLC and Subsidiaries

Consolidated Statements of Changes in Members’ Equity

(In Thousands)

Year Ended December 31, 2015 and

Period from June 20, 2014 (Inception) to December 31, 2014


	Total Equity
Balance at June 20, 2014 (Inception)	$	—
Property contributions		76,102
Cash contributions		8,889
Net income		2,360

Balance at December 31, 2014		87,351
Cash contributions		208,376
Property contributions		40,116
Net loss		(2,909	)

Balance at December 31, 2015	$	332,934

The accompanying notes are an integral part of these consolidated financial statements.

F-69

Esquisto Resources II, LLC and Subsidiaries

Consolidated Statements of Cash Flows

(In Thousands)


	Year Ended December 31, 2015			Period From June 20, 2014 (Inception) to December 31, 2014
Operating activities
Net (loss) income	$	(2,909	)	$	2,360
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Changes in fair value of derivative financial instruments		(4,344	)		—
Cash settlements of gains from derivative financial instruments		480			—
Depletion and depreciation		32,300			7,331
Exploration and abandonments		2,967			2
State deferred tax expense		691			383
Accretion of discount on asset retirement obligations		12			1
Amortization of deferred financing costs		529			82
Change in operating assets and liabilities:
Accounts receivable		(2,875	)		(2,941	)
Prepaid expenses		(41	)		—
Accounts payable, accrued expenses, and notes payable to members		1,399			2,503

Net cash provided by operating activities		28,209			9,721
Investing activities
Acquisitions of oil and gas properties		(167,906	)		(14,417	)
Additions to oil and gas properties		(141,562	)		(28,661	)
Acquisitions of water assets		(500	)		—

Net cash used in investing activities		(309,968	)		(43,078	)
Financing activities
Proceeds from long-term debt		110,000			45,700
Payments on long-term debt		(16,000	)		(19,700	)
Debt issuance costs		(861	)		(387	)
Cash contributions by members		208,376			8,889

Net cash provided by financing activities		301,515			34,502

Net increase in cash and cash equivalents		19,756			1,145
Cash and cash equivalents, beginning of period		1,145			—

Cash and cash equivalents, end of period	$	20,901		$	1,145

Supplemental disclosure of cash flow information
Cash paid for interest	$	(4,123	)	$	(420	)

Supplemental disclosure of noncash financing activities
Capital contributions—property	$	40,116		$	76,102

The accompanying notes are an integral part of these consolidated financial statements.

F-70

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2015 and 2014

1.	Organization and Nature of Operations

Esquisto Resources, LLC (E1), a Texas limited liability company was formed on June 20, 2014, by several members who owned certain oil and gas properties located in Burleson County, Texas which were contributed to E1 at the inception of the company or shortly thereafter. Esquisto Resources II, LLC (E2), a Texas limited liability company was formed on July 1, 2015 by three of the members of E1 to complete an acquisition that the other members of E1 elected not to participate in. Subsequent to December 31, 2015, a merger was consummated whereby E1 was merged into E2. Collectively E1 and E2 will be referred to herein as Esquisto, Esquisto Resources or the Company. Capital contributions through December 31, 2015 have consisted of $217.3 million in cash ($208.4 million in 2015 and $8.9 million in 2014) and $116.2 million ($40.1 million in 2015 and $76.1 million in 2014) in undeveloped acreage and producing oil and gas properties. Future distributions will be paid to members based on their sharing ratios. The Company is an independent energy company engaged in the exploration, development, and acquisition of unconventional oil and associated liquids-rich natural gas reserves, primarily in the Eagle Ford shale play in Southeast Texas.

The consolidated financial statements include the results of operations of E1 and E2 from the dates of their formations, respectively, and have been presented on a consolidated basis to account for the January 2016 merger of the two entities (see Note 13 for further discussion). From February 2015 forward, the Companies have followed common control basis of accounting when the Companies became greater than 50% controlled by two members under common control. See Note 3 for more information regarding the financial statement basis of presentation to reflect common control accounting.

The financial statements were originally issued on May 16, 2016, and are being reissued on August 10, 2016 to reflect the retrospective accounting treatment for the January 2016 common control transaction.

2.	Summary of Significant Accounting Policies

a.	General

The Company’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP).

b.	Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions within the respective entities and between E1 and E2 and subsidiaries have been eliminated. As discussed in Note 3, the operations for businesses contributed under common control as of January 2016 have been included in the consolidated financial statements for the period from February 17, 2015 through December 31, 2015.

c.	Use of Estimates in the Preparation of Financial Statements

Preparation of the accompanying consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the amounts included in the notes thereto, including discussion and disclosure of contingent assets and liabilities. Depletion of oil and gas properties and impairment of proved and unproved oil and natural gas properties, in part, is determined using estimates of proved, probable, and possible oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable, and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to

F-71

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

numerous uncertainties, including, among others, estimates of future recoverable reserves and commodity price outlooks. Although the Company uses its best estimates and judgments, actual results could differ from these estimates and assumptions utilized as future confirming events occur.

d.	Cash and Cash Equivalents

The Company’s cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less.

e.	Accounts Receivable

As of December 31, 2015 and 2014, the Company had accounts receivable—trade of $5.8 million and $2.9 million, respectively. The Company’s accounts receivable—trade are primarily comprised of oil and natural gas sales receivables for which the Company does not require collateral security. The Company has not written off any bad debts in the past nor does it have any allowances for doubtful accounts as of December 31, 2015 and 2014. The Company reviews its accounts receivable based on the specific facts and circumstances of each outstanding amount and general economic condition. In accordance with Accounting Standards Codification (ASC) Topic 450, Contingencies , the Company establishes allowance for doubtful accounts equal to the estimable portions of accounts receivable for which failure to collect is considered probable.

f.	Prepaid Expenses

Prepaid drilling costs of $2.1 million and $1.6 million as of December 31, 2015 and 2014, respectively, were amounts billed by other operators for wells being drilled whereby the Company had a working interest in accordance with joint operating agreements.

g.	Credit Risk and Other Concentrations

The Company sells oil and natural gas to various types of customers, including pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial condition and payment history. The future availability of a ready market for oil and natural gas depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. The Company does not believe the loss of any single purchaser would materially impact its operating results because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

The Company places its temporary cash positions with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution. For the years ended December 31, 2015 and 2014, the Company has not incurred losses related to these positions. See Note 12 for further information about the Companies major customers.

h.	Oil and Natural Gas Properties

The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use.

F-72

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

The Company does not carry the costs of drilling an exploratory well as an asset in its balance sheet following the completion of drilling unless both of the following conditions are met:

(i)

the well has found a sufficient quantity of reserves to justify its completion as a producing well, and

(ii)

the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonment expense. See Note 7 for additional information regarding the Company’s suspended exploratory well costs.

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

The Company performs assessments of its long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets.

Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales, or expiration of all or a portion of such projects. If the estimated future net undiscounted cash flows attributable to such projects are not expected to be sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time. For the year ended December 31, 2015, the Company recognized an impairment loss of $2.8 million that is included in exploration and abandonment expense. No impairment expense was recognized in 2014.

i.	Asset Retirement Obligations

The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally

F-73

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated. See Note 9 for additional information about the Company’s asset retirement obligations.

j.	Revenue Recognition

The Company uses the sales method of accounting for oil, natural gas liquid and natural gas revenues, recognizing revenues based on the oil, natural gas liquids and natural gas delivered rather than the net revenue interest share of oil and gas produced. The Company had no material imbalances as of December 31, 2015 and 2014.

The Company recognizes revenues when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

k.	Derivatives

All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. The Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company’s credit-adjusted risk-free rate curve. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. See Note 6 for additional information about the Company’s derivative instruments.

l.	Environmental

The Company’s environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs.

m.	Income Taxes

Federal income taxes have not been provided for in the accompanying financial statements as the members are responsible for reporting their allocable share of the Company’s tax basis income, gains, deductions, losses and credits in their individual tax returns. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each member as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

F-74

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

The Company is subject to the Texas Margin Tax, at an effective rate of up to three-fourths of 1% on the portion of its income that is apportioned to Texas. The margin tax qualifies as an income tax under the Financial Accounting Standards Board (FASB), ASC Topic 740 Accounting for Uncertainty in Income Taxes , which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax. For the year ended December 31, 2015 and the period from June 20, 2014 (Inception) to December 31, 2014, the Company recognized deferred state tax expenses of $691,000 and $383,000 respectively, and deferred tax liabilities as of December 31, 2015 and 2014 of $1.1 million and $383,000, respectively, related to the Texas Margin Tax which is included in the accompanying financial statements.

Uncertain Tax Positions. The Company evaluates the uncertainty in tax positions taken or expected to be taken in the course of preparing the financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Tax positions with respect to tax at the Company level deemed not to meet the more likely than not threshold would be recorded as a tax benefit or expense in the current year. The Company has determined no material unrecognized tax benefits or liabilities exist as of December 31, 2015 or 2014 and no provision for income tax is required in the Company’s financial statements. However, the conclusions regarding the evaluation are subject to review and may changes based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof. With all tax positions meeting the “more likely than not” threshold under ASC 740, the Company determined that there is no current effect on the financial statements from a lapse of the statute of limitations as it relates to unrecognized tax benefits. Additionally, the Company’s tax years for 2014—2015 remain open for examination. As of December 31, 2015 and 2014, the Company has no amounts related to accrued interest and penalties. The Company does not anticipate any significant changes to its tax positions over the next year.

n.	Segments

Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and natural gas exploration, development and production. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.

o.	New Accounting Pronouncements

In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities . ASU 2016-01 changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs . ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet

F-75

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior to ASU 2015-03, debt issuance costs were required to be recognized as deferred charges and recorded as assets. ASU 2015-03 is required to be adopted by all public companies for all annual and interim reporting periods beginning after December 15, 2015. Early adoption of this standard was permitted and the Company elected to adopt this standard, on a retrospective basis, during the fourth quarter of 2015. The adoption of ASU 2015-03 only affects the presentation of the Company’s accompanying consolidated balance sheets and related financial statement disclosures in Note 8.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which supersedes the revenue recognition requirements in Accounting Standards Codification (ASC) Topic 605, Revenue Recognition , and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to annual reports beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements or decided upon its method of adoption.

3.	Contribution of Assets under Common Control

In January 2016, E1 was merged into E2 to become a wholly owned subsidiary. Simultaneously and as a part of the same transaction, members of the Company also contributed certain working interests in developed and undeveloped oil and gas properties as well as member interests in another entity, Burleson Water Resources, LLC, that also became a wholly owned subsidiary as of that date. Since the majority of the members have been under common control since February 17, 2015, this merger and contribution was accounted for as a transaction among entities under common control. As such, the accompanying consolidated financial statements have been presented to include the operations of the January 2016 merger and contribution as if the Company owned the assets since February 2015, when the Company and its members became under common control, or when the assets were acquired by the members, whichever is later.

4.	Acquisitions

Champlin Acreage. In December 2015, the Company acquired 3,628 acres of undeveloped acreage in Burleson County from Clayton Williams Energy, Inc. (Clayton Williams) for a total purchase price of $21.8 million. The acquisition was accounted for using the purchase method.

F-76

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

Comstock. In July 2015, the Company acquired producing properties, undeveloped acreage and water assets from Comstock Resources Inc. (Comstock) with an effective date of May 1, 2015 for a total purchase price of $103.0 million, net of customary closing adjustments. The Company also incurred approximately $373,000 in legal, due diligence, engineering, and other costs associated with the business combination that were charged to other expense in 2015. The Company funded the acquisition from member capital contributions and $50 million in borrowings under a revolving credit agreement discussed in Note 8. At the time of the acquisition, the properties included approximately 15 producing wells. The allocation of fair value to the underlying assets and liabilities acquired as of the transaction date are as follows (in thousands):


Adjusted purchase price
Proved properties	$	57,741
Unproved properties		44,887
Water assets		500
Asset retirement obligation		(112	)

Total	$	103,016

The properties acquired had revenues and direct operating expenses prior to our ownership as follows (in thousands):


	Seven Months Ended July 31, 2015		Year Ended December 31, 2014
	(unaudited)
Oil and natural gas sales	$	18,035	$	10,608
Direct operating expenses:
Oil and natural gas production		1,118		436
Production taxes		881		506

		1,999		942

Operating revenues in excess of direct operating expenses	$	16,036	$	9,666

Porter Acreage. In June 2015, one of the members of the Company formed an entity for the sole purpose of acquiring 3,696 acres of undeveloped acreage in Burleson County from Clayton Williams for a total purchase price of $22.2 million. In September 2015, the entity that owned those properties was contributed to the Company in exchange for an increased membership interest. There was no activity on the properties between closing and contribution to the Company. As the contribution occurred subsequent to the period in which common control was obtained, the Company recorded the assets received at the carryover basis of the contributing member.

Initial Equity Contribution. In June 2014, the original members of the Company contributed their producing and undeveloped assets in Burleson County, Texas to the Company in exchange for membership interests proportionate to their working interests in the properties prior to their contribution. Subsequent to the initial contribution, another member contributed some additional undeveloped acreage in Burleson County, Texas to the Company for a 2.5% interest in the Company. The members collectively had spent a total of $76.1 million on the properties to date and they were being contributed to the company pro-rata to their working interest ownership percentages. Such contributions were recorded by the Company at their respective fair values on the date of contribution.

Miscellaneous Undeveloped Acreage Costs. During 2015 and 2014, the Company also incurred costs on undeveloped acreage in and around its existing acreage in Burleson County, Texas for an additional $22.6 million and $14.4 million, respectively.

F-77

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

See Note 13 for a discussion of certain properties contributed by the members of E1 and E2 in January 2016, which have been retrospectively presented in these financial statements as the contributions represent a transaction under common control.

5.	Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:

Level 1 —Quoted prices for identical assets or liabilities in active markets.

Level 2 —Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Unobservable inputs for the asset or liability.

Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

The Company did not have any assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2014 nor did it have any liabilities that are measured at fair value on a recurring basis as of December 31, 2015. The following table presents the Company’s assets that are measured at fair value on a recurring basis as of December 31, 2015 for each of the fair value hierarchy levels.


	Fair Value Measurements at December 31, 2015 Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value at December 31, 2015
Commodity derivatives	$	—	$	3,864	$	—	$	3,864

The Company’s commodity derivatives represent oil swap contracts, oil collars and short puts. The asset and liability measurements for the Company’s commodity derivative contracts represent Level 2 inputs in the hierarchy. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives.

The asset and liability values attributable to the Company’s commodity derivatives were determined based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contracts with short puts, which is based on active and independent market-quoted volatility factors.

F-78

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. The Company did not record any impairments to proved oil and natural gas properties for the year ended December 31, 2015 or 2014 as the fair value exceeded the carrying value in all cases. During 2015, the Company recorded an impairment of unproved oil and natural gas properties of $2.8 million.

Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of December 31, 2015 and 2014 are as follows (in thousands):


	December 31, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	119,363	$	120,000	$	25,695	$	26,000

Long-term debt includes the Company’s credit facilities and the Company’s second lien debt. The fair value of debt is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy.

The fair value of the Company’s revolving credit facility and second lien note are calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rates and (iii) the applicable credit-adjustments.

The Company has other financial instruments consisting primarily of cash equivalents, accounts receivable, prepaid expenses, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in a business combination and asset retirement obligations.

Concentrations of Credit Risk. At December 31, 2015 and 2014, the Company’s primary concentration of credit risks are the risks of collecting accounts receivable—trade and the risk of a counterparty’s failure to perform under derivative contracts owed to the Company. See Note 12 for information regarding the Company’s major customers and Note 6 for information regarding the Company’s outstanding derivative contracts.

6.	Derivative Financial Instruments

The Company utilizes commodity swap contracts and puts to: (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, may utilize interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness.

All material physical sales contracts governing the Company’s oil production are tied directly to, or highly correlated with, New York Mercantile Exchange (NYMEX) WTI oil prices. The Company uses derivative contracts to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and actual index prices at which the oil is sold.

F-79

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

The following table sets forth the volumes per day associated with the Company’s outstanding oil derivative contracts as of December 31, 2015 and the weighted-average oil prices for those contracts:


	2016								Year Ended December 31,
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		2017		2018
Swap contracts:
Volume (Bbl)		46,100		52,736		28,996		18,400		73,000		—
Price per Bbl	$	50.77	$	51.46	$	52.42	$	53.64	$	53.64	$	—
Collar contracts:
Volume (Bbl)		—		—		13,380		18,472		60,784		25,096
Price per Bbl:
Ceiling	$	—	$	—	$	62.10	$	62.10	$	62.10	$	62.10
Floor	$	—	$	—	$	50.00	$	50.00	$	50.00	$	50.00
Put contracts:
Volume (Bbl)		47,143		40,640		—		—		—		—
Price per Bbl	$	50.00	$	50.00	$	—	$	—	$	—	$	—

Tabular disclosure of derivative financial instruments. All of the Company’s derivatives are accounted for as non-hedge derivatives as of December 31, 2015 and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty.

The aggregate fair value of the Company’s derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following:


Fair Value of Derivative Instruments as of December 31, 2015
Type	Consolidated Balance Sheet Location		Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
					(In Thousands)
Derivatives not designated as hedging instruments Asset Derivatives
Commodity price derivatives		Derivatives—current	$	2,872	$	(32	)	$	2,840
Commodity price derivatives		Derivatives—noncurrent		1,240		(216	)		1,024

								$	3,864

Liability Derivatives
Commodity price derivatives		Derivatives—current	$	32	$	(32	)	$	—
Commodity price derivatives		Derivatives—noncurrent		216		(216	)		—

								$	—

F-80

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

The following table details the location of realized and unrealized gains and losses recognized on the Company’s derivative contracts in the accompanying consolidated statements of operations:


Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) Recognized in Earnings on Derivatives	Amount of Gain/(Loss) Recognized in Earnings on Derivatives Period Ended December 31,
Derivatives Not Designated as Hedging Instruments		2015		2014
		(In Thousands)
Commodity price derivatives	Derivative gains, net	$	4,344	$	—

Derivative Counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.

The following table provides the Company’s net derivative assets by counterparty as of December 31, 2015:


	Net Assets
	(In Thousands)
Wells Fargo Bank, N.A.	$	2,280
Koch Supply & Trading LP		976
Comerica Bank		608

	$	3,864

7.	Exploratory Well Costs

The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company’s capitalized exploratory well and project costs are presented in unproved properties in the accompanying consolidated balance sheet. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonment expense.

The following table reflects the Company’s capitalized exploratory well and project activity during the year ended December 31, 2015 and the period from Inception to December 31, 2014 ( in thousands ):


	2015			2014
Beginning capitalized exploratory well costs	$	6,385		$	—
Additions to exploratory well costs pending the determination of proved reserves		96,726			66,490
Reclassification due to determination of proved reserves		(87,913	)		(60,105	)

Ending capitalized exploratory well costs	$	15,198		$	6,385

As of December 31, 2015 and 2014, the Company had no exploratory projects for which exploratory costs have been capitalized for a period greater than one year from the date drilling was completed.

F-81

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

8.	Long-Term Debt and Notes Payable to Members

Long-term debt consisted of the following components at December 31, 2015 and 2014 ( in thousands ):


	2015			2014
Outstanding debt principal balances:
Wells Fargo revolving credit facility	$	50,000		$	—
BOK revolving credit facility		40,000			6,000
Second lien		30,000			20,000

		120,000			26,000
Issuance costs		(637	)		(305	)

Long-term debt		119,363			25,695
Less current portion of long-term debt		—			—

Long-term debt	$	119,363		$	25,695

Notes payable to members	$	6,438		$	2,097

Wells Fargo Revolving Credit Facility. In July 2015, the Company entered into a revolving credit facility (Wells Fargo Revolving Credit Facility) with a syndicate of financial institutions, led by Wells Fargo Bank, N.A. (Wells Fargo). The initial loan commitment is $250.0 million and it expires in July, 2020. Debt issuance costs of $540,000 were capitalized and are being amortized over the life of the Wells Fargo Revolving Credit Facility. As of December 31, 2015, the borrowing base under the Wells Fargo Revolving Credit Facility was $60.0 million, comprised of a $50.0 million conforming piece and a $10.0 million non-conforming piece. As of December 31, 2015, the Company had $50.0 million in outstanding borrowings under the Wells Fargo Revolving Credit Facility.

Borrowings under the Wells Fargo Revolving Credit Facility bear interest, at the option of the Company, based on: (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5% plus a defined alternate base rate spread margin, which is currently 2.0% or (b) a base Eurodollar rate, substantially equal to London Interbank Offered Tate (LIBOR), plus a margin (the “Applicable Margin”), which is currently 3.0% and is also determined by a spread margin based on loan utilization. The Company also pays commitment fees on undrawn amounts under the Wells Fargo Revolving Credit Facility that are determined by a similar utilization grid (currently 0.5%). Borrowings under the Wells Fargo Revolving Credit Facility are secured by the Company’s proved oil and natural gas reserves that are owned by E2.

The Wells Fargo Revolving Credit Facility requires the maintenance of the ratio of EBITDAX to Interest Expense to be greater than 2.5 to 1.0 and a current ratio greater than 1.0 to 1.0. As of December 31, 2015, the Company was in compliance with all of its debt covenants. As of March 31, 2016, the Company determined it was not in compliance with the current ratio test under the Wells Fargo Revolving Credit Facility, but was able to cure the default, through additional capital contributions from its members, during the allotted 30-day grace period. Otherwise, the Company has remained in compliance with its debt covenants under the Wells Fargo Revolving Credit Facility. The Company has evaluated its current liquidity position, including estimated future cash flows provided from operations, cash outflows for oil and gas acquisitions/additions, and available unused capital commitments from its members, and does not anticipate any future events of default related to its debt covenants.

F-82

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

BOK Revolving Credit Facility. In June 2014, the Company entered into a revolving credit facility (BOK Revolving Credit Facility) with a syndicate of financial institutions, led by Bank of Oklahoma, N.A. (BOK). The initial loan commitment was $50.0 million and it was set to expire in June, 2015. In December 2014, the Company amended the BOK Revolving Credit Facility when it entered into the Second Lien discussed below and the maturity was extended to December 2015. In July 2015, the maturity was extended to March, 31, 2016. Debt issuance costs of $315,000 were capitalized and are being amortized over the life of the BOK Revolving Credit Facility. The borrowing base under the BOK Revolving Credit Facility is adjusted periodically based on the Company adding new wells as drilling completed. As of December 31, 2015, the borrowing base under was $50.0 million and the Company had $40.0 million in outstanding borrowings under the BOK Revolving Credit Facility.

Borrowings under the BOK Revolving Credit Facility bear interest, at the option of the Company, based on: (a) a rate per annum equal to the prime rate announced from time to time by BOK plus 2.75% or (b) a rate, substantially equal to LIBOR, plus 3.0%. The Company also pays commitment fees on undrawn amounts under the BOK Revolving Credit Facility that is currently 0.25%. Borrowings under the BOK Revolving Credit Facility are secured by the Company’s proved oil and natural gas reserves that are owned by E1.

The BOK Revolving Credit Facility requires the maintenance of a Debt Service Coverage Ratio of 1.0 to 1.0, a Funded Debt to EBITDAX ratio of 4.5 to 1.0 and a Current Ratio of 1.0 to 1.0. No events of default have occurred related to the Company’s compliance with the BOK Revolving Credit Facility debt covenants for any period.

Second Lien. In December 2014, the Company entered into a second lien with BOK (Second Lien) for $20 million that was increased to $30.0 million in May 2015 which is the balance due as of December 31, 2015. The notes mature on June 30, 2016. The Company incurred debt issuance costs associated with the Second Lien of $394,000 that were capitalized and are being amortized over the life of the loan.

Borrowings under the Second Lien bear interest at a rate per annum equal to the prime rate announced from time to time by BOK plus 6.0% Borrowings under the Second Lien are secured by the Company’s proved oil and natural gas reserves that are owned by E1.

The Second Lien requires the balance of the consolidated BOK Revolving Credit Facility plus the Second Lien to remain under 90% of the PV-8 of Company proved reserves. No events of default have occurred related to the Company’s compliance with the Second Lien debt covenants for any period.

Notes payable to members. The Company owes $6.4 million and $2.1 million as of December 31, 2015 and 2014, respectively, to members for general and administrative expenses incurred on behalf of the Company. These notes are payable to members by December 31, 2022 and bear interest after a year at the Applicable Federal Rate compounded annually paid at maturity. See related party information in Note 11.

Principal maturities. Principal maturities of long-term debt and notes payable to members at December 31, 2015, are as follows (in thousands):


2016	$	70,000
2017		—
2018		—
2019		—
2020		50,000
Thereafter		6,438

F-83

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

Subsequent to December 31, 2015, the $70.0 million due in 2016 was refinanced on January 12, 2016 in conjunction with the merger discussed in Note 13. Simultaneously with the closing of the merger transaction, the Wells Fargo Revolving Credit Facility’s borrowing base was increased to $135.0 million, of which $70.0 million was drawn to pay off the BOK Revolving Credit Facility and Second Lien. This brought out total borrowings under the Wells Fargo Revolving Credit Facility as of January 12, 2016 to $120.0 million which is now due in 2020 with an additional $15.0 million available for borrowing at the time of the merger. Therefore, the entire outstanding indebtedness as of December 31, 2015 has been classified on the balance sheet as long-term debt. See additional discussion of subsequent events in Note 13.

Interest expense. The following amounts have been incurred and charged to interest expense for the year ended December 31, 2015 and period from Inception to December 31, 2014 (in thousands):


	2015		2014
Cash payments for interest	$	4,123	$	420
Amortization of debt issuance costs		529		82
Net changes in accruals		41		104

Total interest expense	$	4,693	$	606

9.	Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.

The following table summarizes the Company’s asset retirement obligation activity during the year ended December 31, 2015 and period from Inception to December 31, 2014 (in thousands):


	2015		2014
Beginning asset retirement obligations	$	37	$	—
Obligations assumed in acquisitions		121		—
New wells placed on production		98		36
Changes in estimates(a)		14		—
Accretion of discount		12		1

Ending asset retirement obligations	$	282	$	37

(a)

Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The increase in 2015 is primarily due to the forecasted timing of abandoning the Company’s oil and gas wells being accelerated as a result of lower commodity prices, which has the effect of shortening the economic lives of the Company’s producing wells.

As of December 31, 2015 and 2014, the Company considered the above asset retirement obligations to all be noncurrent.

F-84

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

10.

Commitments and Contingencies

General . The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating, and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s consolidated financial position, results of operations, or liquidity.

Legal Matters. From time to time, the Company is a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a while or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. The Company is unaware of any pending claims brought against the Company requiring the reserve of a contingent liability as of the date of these consolidated financial statements.

Drilling Commitments. The Company’s principal drilling commitments are related to a drilling rig contract, a walking package contract and a drill pipe contract that require the Company to pay day rates for contracted drilling rigs, walking packages or drill pipe over their contractual term. In addition, the Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company recognizes its drilling commitments in the periods in which the rig services are performed or the well is drilled. The Company’s future minimum drilling commitments at December 31, 2015 are as follows (in thousands):


2016	$	1,127
2017		—
2018		—
2019		—
2020		—
Thereafter		—

Environmental Matters. The Company is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These include existing and possible future obligations to investigate the effects of the release or disposal of certain petroleum and chemical substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources, for remediation and restoration costs, and for personal injuries; and to pay civil penalties and, in some cases, criminal penalties and punitive damages. The obligations relate to sites owned by the Company or others and are associated with past and present operations.

Liabilities are accrued when it is probable that future costs will be incurred and such costs can be reasonably estimated. As of December 31, 2015 and 2014, the Company had no liabilities recorded for any environmental liabilities.

F-85

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

11.

Related-Party Transactions

The Company is being managed by its three majority and primary members. As such, members are charging the Company general and administrative expenses that will be paid at some time in the future. Each managing member calculates a percentage of salaries and benefits to be charged to the Company based on time spent and a weighted average of time spent by all member personnel is then calculated and applied to their respective non-compensation expenditures. Management believes the allocation method is reasonable. Although it is not practicable to determine what the costs would be if the Company were to directly obtain these services, management believes the aggregate costs charged to the Company by the members are reasonable. During 2015 and 2014, the Company accrued $4.3 million and $2.1 million, respectively, as general and administrative expenses payable to members. These amounts do not necessarily correspond to the sharing ratios, but rather to the actual general and administrative expenses incurred by each member on behalf of the Company. These liabilities have been recorded on the accompanying balance sheets as long-term notes payable to members. They will accrue interest at the Applicable Federal Rate beginning in 2017 if not paid in full and be subordinate to all other bank debt.

The Company paid Petromax Operating Company, Inc. (Petromax), who is the operator of the majority of the Company’s wells, $981,000 and $218,000 during 2015 and 2014, respectively for Council of Petroleum Accountants Societies (COPAS) overhead charges on drilling and producing wells at market rates as set forth in joint operating agreements (JOA’s) and in accordance with an Operating Agreement between Petromax and the Company. Such amounts have been expensed in the accompanying financial statements in general and administrative expenses. Petromax is owned 33.3% by Mike Hoover, the Chief Operating Officer of the Company, who also owns indirectly approximately 20% of one of the members of the Company that owns approximately 36.2% of Esquisto Resources.

The Company paid Calbri Energy, Inc. (Calbri), a less than 1% owner of Esquisto Resources, $380,000 and $49,000 in 2015 and 2014, respectively, for completion consulting services. The day rate being paid to Calbri is competitive with others in the area that we use for similar services.

12.

Major Customers

For the year ended December 31, 2015, the Company sold approximately 59% of its share of oil and natural gas production to Sunoco Partners & Terminals, L.P. (Sunoco) and approximately 15% of its share of oil and natural gas production to Shell Trading U.S. Company (Shell). For the year ended December 31, 2014, the Company sold approximately 79% of its share of oil and gas production to Shell and approximate 11% of its share of oil and gas production to ETC Texas Pipeline, Ltd. (ETC). The Company is of the opinion that the loss of any one purchaser would not have a material adverse effect on the ability of the Company to sell its oil and natural gas production.

13.

Subsequent Events

Subsequent events have been evaluated through August 10, 2016, the date the financial statements were issued.

Merger. In January 2016, the Company consummated a merger and contribution agreement whereby, E1 was merged into E2 and various members of E1 and E2 contributed additional assets to E2 in exchange for additional member interests. Prior to the merger and contribution agreement, all of the assets of E1 and E2 consisted primarily of developed and undeveloped properties in the East Texas Eagle Ford formation in Burleson County, Texas. The additional assets contributed by members consisted primarily of developed and undeveloped

F-86

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

properties in the East Texas Eagle Ford, Austin Chalk and Pecan Gap formations in Lee County, Washington County and Brazos County, Texas as well as membership interests in BWR. This transaction has been accounted for as a transaction between entities under common control, and the 2015 Esquisto financial statements have been presented to as if the Company owned the contributed properties since February 2015, when the Company and its members became under common control, or when the assets were acquired by the members, whichever is later. Esquisto recorded the assets contributed at the members’ historical cost basis, which approximated $43.6 million as of January 2016.

In conjunction with the merger, the BOK Revolving Credit Facility and the Second Lien were retired and terminated and the Wells Fargo Revolving Credit Facility was increased to a borrowing base of $135.0 million, $70.0 million of which was drawn at consummation to pay off the two aforementioned debts bringing the outstanding balance to $120.0 million.

Derivatives. From March to July 2016, the Company entered into additional derivative financial instruments as follows:

•

15,000 barrels of oil per month was hedged with a swap priced at $42.00 per barrel for April 2016 to December 2016 with JPMorgan Chase Bank, N.A. (JPMorgan) as the counterparty

•

27,000 barrels of oil per month was hedged with a swap priced at an average of $43.90 per barrel for July 2016 to December 2016 with JPMorgan

•

10,000 barrels of oil per month was hedged with a swap priced at $50.28 per barrel for July 2016 to December 2016 with Wells Fargo as the counterparty

•

5,000 barrels of oil per month was hedged with a swap priced at $50.70 per barrel for October 2016 to December 2016 with JPMorgan as the counterparty

•

15,000 barrels of oil per month was hedged with a swap priced at $45.54 per barrel for all of 2017 with Wells Fargo as the counterparty

•

12,000 barrels of oil per month was hedged with a swap priced at $47.62 per barrel for all of 2017 with JPMorgan as the counterparty

•

10,000 barrels of oil per month was hedged with a swap priced at $44.45 per barrel for all of 2017 with JPMorgan as the counterparty

•

5,000 barrels of oil per month was hedged with a swap priced at $52.55 per barrel for all of 2017 with JPMorgan as the counterparty

•

12,000 barrels of oil per month was hedged with a swap priced at $47.96 per barrel for all of 2018 with Wells Fargo as the counterparty

•

15,000 barrels of oil per month was hedged with a swap priced at $48.80 per barrel for all of 2018 with JPMorgan as the counterparty

•

10,000 barrels of oil per month was hedged with a swap priced at $54.12 per barrel for all of 2018 with JPMorgan as the counterparty

•

5,000 barrels of oil per month was hedged with a swap priced at $55.05 per barrel for all of 2019 with JPMorgan as the counterparty

•

50,000 MMBTU of natural gas per month was hedged with a swap priced at $3.080 per MMBTU for September 2016 to December 2016 with Wells Fargo as the counterparty

•

50,000 MMBTU of natural gas per month was hedged with a swap priced at $3.171 per MMBTU for all of 2017 with Wells Fargo as the counterparty

F-87

Esquisto Resources II, LLC and Subsidiaries

Notes to Consolidated Financial Statements (continued)

Had these derivative financial instruments been in place and open as of December 31, 2015, the open positions would have been as follows:


	2016								Year Ended December 31,
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		2017		2018		2019
Crude oil swap contracts:
Volume (Bbl)		46,100		97,736		184,996		189,400		577,000		444,000		60,000
Price per Bbl	$	50.77	$	47.11	$	45.81	$	45.94	$	47.59	$	49.97	$	55.05
Crude oil collar contract:
Volume (Bbl)		—		—		13,380		18,472		60,784		25,096		—
Price per Bbl:
Ceiling	$	—	$	—	$	62.10	$	62.10	$	62.10	$	62.10		—
Floor	$	—	$	—	$	50.00	$	50.00	$	50.00	$	50.00		—
Crude oil put contract:
Volume (Bbl)		47,143		40,640		—		—		—		—		—
Price per Bbl	$	50.00	$	50.00	$	—	$	—	$	—	$	—		—
Natural gas swap contracts:
Volume (MMBTU)		—		—		50,000		150,000		600,000		—		—
Price per MMBTU	$	—	$	—	$	3.080	$	3.080	$	3.171	$	—		—

Capital Call. In May 2016, the Company made a $25 million capital call to initially pay down the Wells Fargo Revolving Credit Facility and then primarily to fund bringing back a drilling rig to drill three wells beginning toward the end of May.

F-88

Unaudited Supplementary Information

F-89

Esquisto Resources II, LLC and Subsidiaries

Unaudited Supplementary Information

Oil and Natural Gas Exploration and Production Activities

The Company has only one reportable operating segment, which is oil and natural gas exploration and production in the United States. See the Company’s accompanying statement of operations for information about results of operations for oil and gas producing activities.

Capitalized Costs


	December 31,
	2015			2014
	(In Thousands)
Oil and natural gas properties:
Proved	$	348,246		$	102,112
Unproved		154,211			50,422

Capitalized costs for oil and natural gas properties		502,457			152,534
Less accumulated depletion, depreciation, and amortization		(39,631	)		(7,332	)

Net capitalized costs for oil and natural gas properties	$	462,826		$	145,202

Costs Incurred for Oil and Natural Gas Producing Activities ^(a)


	Periods Ended December 31,
	2015		2014
	(In Thousands)
Property acquisition costs:
Proved	$	114,029	$	16,431
Unproved		92,010		74,087
Exploration costs		97,157		62,018
Development costs		49,694		—

Total costs incurred	$	352,890	$	152,536

(a)	The costs incurred for oil and natural gas producing activities includes $233,000 and $36,000 of asset retirement obligations included in exploration costs for the years ended December 31, 2015 and 2014, respectively.

Reserve Quantity Information

The estimates of the Company’s proved reserves as of December 31, 2015 and 2014 were based on evaluations by independent petroleum engineers, Cawley, Gillespie and Associates, Inc. Proved reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission (SEC) and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual arrangements.

Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing, and production may cause either

F-90

Esquisto Resources II, LLC and Subsidiaries

Unaudited Supplementary Information (continued)

upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a rollforward of total proved reserves for the year ended December 31, 2015 and 2014. Oil and natural gas liquid (NGL) volumes are expressed in thousands of barrels (MBbls), natural gas volumes are expressed in millions of cubic feet (MMcf), and total volumes are expressed in thousands of barrels of oil equivalent (MBOE).


	For the Periods Ended December 31, 2015 and 2014
	Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)			Total (MBOE)
Balance, June 20, 2014 (Inception)		—			—			—			—
Extensions and discoveries		7,464			1,674			6,315			10,191
Purchases of minerals-in-place		154			22			79			189
Production		(159	)		(46	)		(156	)		(231	)

Balance, December 31, 2014		7,459			1,650			6,238			10,149
Extensions and discoveries		26,867			5,976			22,439			36,583
Purchases of minerals-in-place		1,972			710			4,296			3,398
Revisions of previous estimates		367			455			2,127			1,176
Production		(953	)		(261	)		(1,265	)		(1,425	)

Balance, December 31, 2015		35,712			8,530			33,835			49,881

The changes in proved reserves during 2015 and 2014 are comprised of the following items:

Extensions and discoveries. Extensions and discoveries during 2015 and 2014 are primarily comprised of discoveries and extensions in the Eagle Ford horizons in Burleson County, Texas as a result of continuous drilling in the area.

Purchase of minerals-in-place. Purchases of minerals-in-place during 2014 are primarily attributable to the contribution of assets at the inception of the Company which only included one producing well. Purchase of minerals-in-place during 2015 are primarily attributable to the producing wells acquired in the Comstock acquisition.

Revisions of previous estimates. Revisions of previous estimates during 2015 are primarily attributable to operational efficiencies gained through increased experience in the area (increase of approximately 1,315 MBOE) partially offset by decreased commodity prices which decreased the useful lives of the wells, decreasing ultimate reserves recovered (decrease of approximately 139 MBOE).

F-91

Esquisto Resources II, LLC and Subsidiaries

Unaudited Supplementary Information (continued)

The following table provides the Company’s proved developed and proved undeveloped reserves for the year ended December 31, 2015 and 2014.


	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBOE)
Proved developed reserves:
Beginning of the year		1,436		329		1,273		1,977
End of the year		7,059		1,868		8,821		10,397
Proved undeveloped reserves:
Beginning of the year		6,023		1,321		4,965		8,172
End of the year		28,653		6,662		25,014		39,484

The Company uses both public and proprietary geologic data to establish continuity of the formation and its producing properties. This included seismic data and interpretation (2-D, 3-D and micro seismic); open hole log information (both vertical and horizontally collected) and petrophysical analysis of the log data; mud logs; gas sample analysis; drill cutting samples; measurements of total organic content; thermal maturity and sidewall cores. After the geologic area was shown to be continuous, statistical analysis of existing producing wells was conducted to generate areas of reasonable certainty at distances from established production. As a result of this analysis, proved undeveloped reserves for drilling locations within these areas of reasonable certainty were recorded during 2015.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by applying commodity prices used in determining proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved reserves less estimated future expenditures (based on year-end estimated costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Since the Company is not subject to federal income taxes, future income taxes have been excluded.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

F-92

Esquisto Resources II, LLC and Subsidiaries

Unaudited Supplementary Information (continued)

The following table provides the standardized measure of discounted future cash flows as of December 31, 2014 as well as a rollforward in total for such year ( in thousands ):


	December 31,
	2015			2014
Oil and natural gas producing activities:
Future cash inflows	$	1,959,585		$	769,878
Future production costs		(477,447	)		(132,010	)
Future development costs(a)		(594,528	)		(142,015	)

Undiscounted future net cash flows		887,610			495,853
10% annual discount factor		(577,935	)		(280,558	)

Standardized measure of discounted future cash flows	$	309,675		$	215,295

(a)	Includes $6.7 million and $1.3 million of undiscounted future asset retirement expenditures estimated as of December 31, 2015 and 2014, respectively using current estimates of future abandonment costs.

See Note 9 for additional information regarding the Company’s discounted asset retirement obligations.

Changes in Standardized Measure of Discounted Future Net Cash Flows


	Period Ended December 31,
	2015			2014
Oil and natural gas sales, net of production costs	$	(39,559	)	$	(13,404	)
Net changes in prices and production costs		(59,213	)		—
Extensions and discoveries		192,990			221,367
Purchases of minerals-in-place		69,258			7,251
Revision of previous quantity estimates		26,827			—
Changes of production rates (timing) and other		(119,099	)		81
Changes in estimated future development costs		1,646			—
Accretion of discount		21,530			—

Changes in present value of future net revenues		94,380			215,295
Standardized measure balance, beginning of year		215,295			—

Standardized measure balance, end of year	$	309,675		$	215,295

F-93

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)


	September 30, 2016			December 31, 2015
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	115		$	20,901
Accounts receivable—trade		11,570			5,816
Derivatives		—			2,840
Prepaid expenses		1,087			2,162

Total current assets		12,772			31,719
Property and equipment:
Oil and gas properties, successful efforts method:
Proved properties		430,061			348,246
Unproved properties		159,637			154,211
Accumulated depletion		(72,721	)		(39,631	)

Total property and equipment		516,977			462,826
Water assets		1,188			1,195
Derivatives		—			1,024

Total assets	$	530,937		$	496,764

Liabilities and members’ equity
Current liabilities:
Accounts payable	$	23,202		$	17,236
Accrued expenses and other current liabilities		11,595			19,437
Derivatives		1,946			—

Total current liabilities		36,743			36,673
Long-term debt		124,058			119,363
Notes payable to members		9,625			6,438
Derivatives		2,159			—
Deferred state tax liability		1,509			1,074
Asset retirement obligation		300			282
Commitments and contingencies		—			—
Members’ equity		356,543			332,934

Total liabilities and members’ equity	$	530,937		$	496,764

The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-94

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(in thousands)


	Nine Months Ended September 30,
	2016			2015
Operating revenues:
Oil sales	$	48,737		$	26,723
Natural gas liquid sales		2,960			1,938
Natural gas sales		2,475			2,041

Total operating revenues		54,172			30,702
Operating costs and expenses:
Oil and natural gas production		5,038			4,304
Production taxes		2,529			1,456
Depletion, depreciation and accretion		33,197			20,653
Exploration and abandonments		2			206
General and administrative		5,659			4,232
Loss (gain) from derivative financial instruments		5,800			(1,116	)

Total operating costs and expenses		52,225			29,735

Total operating income		1,947			967

Other income (expense):
Other income		5			4
Interest expense		(2,879	)		(3,074	)
State deferred tax expense		(435	)		(478	)
Other expense		(358	)		(485	)

		(3,667	)		(4,033	)

Net loss	$	(1,720	)	$	(3,066	)

The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-95

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY (Unaudited)

For the Nine Months Ended September 30, 2016

(in thousands)


	Total Members’ Equity
Balance at January 1, 2016	$	332,934
Cash contributions		25,000
Property contributions		329
Net loss		(1,720	)

Balance at September 30, 2016	$	356,543

The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-96

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)


	Nine Months Ended September 30,
	2016			2015
Operating activities:
Net loss	$	(1,720	)	$	(3,066	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Changes in fair value of derivative financial instruments		5,800			(1,116	)
Cash settlements of gains from derivative financial instruments		2,169			(335	)
Depletion, depreciation and accretion		33,197			20,653
Exploration and abandonments		2			206
Early extinguishment of long-term debt		358			—
State deferred tax expense		435			478
Amortization of deferred financing costs		158			350
Changes in operating assets and liabilities:
Accounts receivable		(5,753	)		839
Prepaid expenses		31			—
Accounts payable, accrued expenses and notes payable to members		(860	)		672

Net cash provided by operating activities		33,817			18,681
Investing activities:
Acquisitions of oil and gas properties		(13,827	)		(141,051	)
Additions to oil and gas properties		(69,872	)		(100,997	)
Acquisitions of water assets		(83	)		(500	)

Net cash used in investing activities		(83,782	)		(242,548	)
Financing activities:
Proceeds from long-term debt		93,000			105,000
Payments on long-term debt		(88,000	)		(16,000	)
Debt issuance costs		(596	)		(836	)
Early termination of second lien debt		(225	)		—
Cash contributed by members		25,000			153,364

Net cash provided by financing activities		29,179			241,528

Net (decrease) increase in cash and cash equivalents		(20,786	)		17,661
Cash and cash equivalents, at beginning of period		20,901			1,145

Cash and cash equivalents, at end of period	$	115		$	18,806

Supplemental disclosure of cash flow information
Cash paid for interest	$	(2,804	)	$	(2,667	)

Supplemental disclosure of noncash investing and financing activities
Capital expenditures in accounts payable and accrued expenses	$	33,523		$	33,217

Capital contributions—property and member interests	$	329		$	40,116

The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-97

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Nine Months Ended September 30, 2016

(1)

Interim Financial Statements

The accompanying consolidated financial statements of Esquisto Resources II, LLC and subsidiaries (the Company), with the exception of the consolidated balance sheet at December 31, 2015, have not been audited by independent public accountants. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly in accordance with United States Generally Accepted Accounting Procedures (GAAP) the financial position of the Company at September 30, 2016 and the operations and cash flows of the Company for the nine month periods ended September 30, 2016 and 2015. All such adjustments are of a normal recurring nature. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed or omitted from these financial statements. Accordingly, these financial statements should be read in conjunction with the December 31, 2015 audited consolidated financial statements of the Company. Certain amounts in prior year financial statements may have been reclassified to conform to current year classifications.

(2)

Organization, Basis of Presentation and Nature of Operations

Esquisto Resources, LLC and Subsidiary (E1), a Texas limited liability company was formed on June 20, 2014, by several members who owned certain oil and gas properties located in Burleson County, Texas which were contributed to E1 at the inception of the company or shortly thereafter. Esquisto Resources II, LLC (E2), a Texas limited liability company was formed on July 1, 2015 by three of the members of E1 to complete an acquisition that the other members of E1 at the time elected not to participate in.

In January 2016, E1 was merged into E2 to become a wholly owned subsidiary. Simultaneously, and as a part of the same transaction, members of the Company also contributed certain working interests in developed and undeveloped oil and gas properties as well as members interests in another entity, Burleson Water Resources, LLC, that also became a wholly owned subsidiary as of that date. Since the majority of the members have been under common control since February 17, 2015, this merger and contribution was accounted for as a transaction among entities under common control. As such, the accompanying consolidated financial statements have been presented to include the operations of the January 2016 merger and contribution as if the Company owned the assets since February 2015, when the Company and its members became under common control, or when the assets were acquired by the members, whichever is later. The transfers were recorded based on the carrying amounts of the transferring entities.

Collectively E1, E2 and the additional contributed assets will be referred to herein as Esquisto, Esquisto Resources or the Company. Capital contributions through September 30, 2016 have consisted of $242.3 million in cash ($25.0 million during the nine months ended September 30, 2016, $208.4 million in 2015 and $8.9 million in 2014) and $116.5 million ($329,000 during the nine months ended September 30, 2016, $40.1 million in 2015 and $76.1 million in 2014) in undeveloped acreage and producing oil and gas properties. Future distributions will be paid to members based on their sharing ratios. The Company is an independent energy company engaged in the exploration, development, and acquisition of unconventional oil and associated liquids-rich natural gas reserves, primarily in the Eagle Ford shale play in Southeast Texas.

F-98

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

(3)

Fair Value Measurements

Level 1 —Quoted prices for identical assets or liabilities in active markets.

Level 3 —Unobservable inputs for the asset or liability.

The Company did not have any assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2016 and December 31, 2015.

Fair value information for the financial assets and liabilities that are measured at fair value each reporting period are as follows at September 30, 2016 and December 31, 2015:


	Fair Value Measurements at September 30, 2016 Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Fair Value at September 30, 2016
Commodity derivatives	$	—	$	(4,105	)	$	—	$	(4,105	)


	Fair Value Measurements at December 31, 2015 Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Fair Value at December 31, 2015
Commodity derivatives	$	—	$	3,864		$	—	$	3,864

F-99

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. The Company did not record any impairments to proved oil and natural gas properties for the nine months ended September 30, 2016 as the fair value exceeded the carrying value in all cases.

Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheet as of September 30, 2016 and December 31, 2015 are as follows (in thousands):


	September 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	124,058	$	125,000	$	119,363	$	120,000

Concentrations of Credit Risk. At September 30, 2016, the Company’s primary concentration of credit risks are the risks of collecting accounts receivable—trade and the risk of a counterparty’s failure to perform under derivative contracts owed to the Company. Refer to note 4 for information regarding the Company’s outstanding derivative contracts.

(4)

Derivative Financial Instruments

The Company utilizes commodity swaps and collars to: (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, may utilize interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness.

F-100

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

The following table sets forth the volumes per day associated with the Company’s outstanding oil derivative contracts as of September 30, 2016 and the weighted-average oil prices for those contracts:


	Fourth Quarter 2016		Year Ended December 31,
	Fourth Quarter 2016		2017		2018		2019
Crude oil swap contracts:
Volume (Bbl)		219,400		592,000		444,000		60,000
Price per Bbl	$	46.31	$	47.66	$	49.97	$	55.05
Natural gas swap contracts:
Volume (MMBTU)		150,000		600,000		—		—
Price per MMBTU	$	3.080	$	3.171		—		—
Crude oil collar contract:
Volume (Bbl)		18,472		60,784		25,096		—
Price per Bbl:
Ceiling	$	62.10	$	62.10	$	62.10		—
Floor	$	50.00	$	50.00	$	50.00		—

Tabular disclosure of derivative financial instruments. All of the Company’s derivatives are accounted for as non-hedge derivatives as of September 30, 2016 and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty.

F-101

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

Fair Value of Derivative Instruments as of September 30, 2016

Type

Combined Balance Sheet
Location

Fair Value

Gross
Amounts
Offset in the
Consolidated
Balance Sheet

Net Fair Value
Presented in
the Consolidated
Balance Sheet

(In Thousands)

Derivatives not designated as hedging instruments Asset Derivatives

Commodity price derivatives

Derivatives—current

673

(673

)

—

Commodity price derivatives

Derivatives—noncurrent

347

(347

)

—

Liability Derivatives

Commodity price derivatives

Derivatives—current

(2,619

)

673

(1,946

)

Commodity price derivatives

Derivatives—noncurrent

(2,506

)

347

(2,159

)

(4,105

)

Fair Value of Derivative Instruments as of December 31, 2015

Type

Combined Balance Sheet
Location

Fair Value

Gross
Amounts
Offset in the
Consolidated
Balance Sheet

Net Fair Value
Presented in the
Consolidated
Balance Sheet

(In Thousands)

Derivatives not designated as hedging instruments Asset Derivatives

Commodity price derivatives

Derivatives—current

2,872

(32

)

2,840

Commodity price derivatives

Derivatives—noncurrent

1,240

(216

)

1,024

3,864

Liability Derivatives

Commodity price derivatives

Derivatives—current

(32

)

—

Commodity price derivatives

Derivatives—noncurrent

(216

)

216

—

The following table details the location of realized and unrealized gains and losses recognized on the Company’s derivative contracts in the accompanying combined statements of operations:


Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) Recognized in Earnings on Derivatives	Amount of Gain/(Loss) Recognized in Earnings on Derivatives
		Nine Months Ended September 30,
		2016			2015
		(In Thousands)
Commodity price derivatives	Gain/(loss) from derivative financial instruments	$	(5,800	)	$	1,116

F-102

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

The following table provides the Company’s net derivative assets by counterparty as of September 30, 2016 and December 31, 2015:


	Net Assets (Liabilities)
	September 30, 2016			December 31, 2015
	(In Thousands)
JPMorgan Chase Bank, N.A.	$	(2,859	)	$	—
Wells Fargo Bank, N.A.		(1,360	)		2,280
Comerica Bank		114			608
Koch Supply & Trading LP		—			976

	$	(4,105	)	$	3,864

(5)

Exploratory Well Costs

The following table reflects the Company’s capitalized exploratory well and project activity during the nine months ended September 30, 2016 ( in thousands ):


	2016
Beginning capitalized exploratory well costs	$	15,198
Additions to exploratory well costs pending the determination of proved reserves		34,233
Reclassification due to determination of proved reserves		(33,674	)

Ending capitalized exploratory well costs	$	15,757

As of September 30, 2016, the Company had no exploratory projects for which exploratory costs have been capitalized for a period greater than one year from the date drilling was completed.

F-103

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

(6)

Long-Term Debt and Notes Payable to Members

Long-term debt consisted of the following components at September 30, 2016 and December 31, 2015 ( in thousands ):


	2016			2015
Outstanding debt principal balances:
Wells Fargo revolving credit facility	$	125,000		$	50,000
BOK revolving credit facility		—			40,000
Second lien		—			30,000
Issuance costs		(942	)		(637	)

Long-term debt		124,058			119,363
Less current portion of long-term debt		—			—

Long-term debt	$	124,058		$	119,363

Notes payable to members	$	9,625		$	6,438

Wells Fargo Revolving Credit Facility. In July 2015, the Company entered into a revolving credit facility (Wells Fargo Revolving Credit Facility) with a syndicate of financial institutions, led by Wells Fargo Bank, N.A. (Wells Fargo). The borrowing base and outstanding balance under the Wells Fargo Revolving Credit Facility increased as a result of the aforementioned merger and contribution in January 2016. The initial loan commitment is $250.0 million and it expires in July, 2020; no other significant terms of the credit facility were amended. Total debt issuance costs of $1.1 million were capitalized and are being amortized over the life of the Wells Fargo Revolving Credit Facility. As of September 30, 2016, the borrowing base under the Wells Fargo Revolving Credit Facility was $160.0 million and the Company had $125.0 million in outstanding borrowings.

Borrowings under the Wells Fargo Revolving Credit Facility bear interest, at the option of the Company, based on: (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5% plus a defined alternate base rate spread margin, which is currently 2.0% or (b) a base Eurodollar rate, substantially equal to London Interbank Offered Tate (LIBOR), plus a margin (the “Applicable Margin”), which is currently 2.25% and is also determined by a spread margin based on loan utilization. The Company also pays commitment fees on undrawn amounts under the Wells Fargo Revolving Credit Facility that are determined by a similar utilization grid (currently 0.5%). Borrowings under the Wells Fargo Revolving Credit Facility are secured by the Company’s proved oil and natural gas reserves that are owned by E2.

The Wells Fargo Revolving Credit Facility requires the maintenance of the ratio of EBITDAX to Interest Expense to be greater than 2.5 to 1.0 and a current ratio greater than 1.0 to 1.0. As of June 30, 2016 and September 30, 2016, the Company was in compliance with all debt covenants. As of March 31, 2016, the Company determined it was not in compliance with the current ratio test under the Wells Fargo Revolving Credit Facility, but was able to cure the default, through additional capital contributions from its members, during the allotted 30-day grace period. Otherwise, the Company was in compliance with its debt covenants under the Wells Fargo Revolving Credit Facility as of March 31, 2016. The Company has evaluated its current liquidity position, including estimated future cash flows provided by operations, cash outflows for oil and gas acquisitions/additions, and available unused capital commitments from its members, and does not anticipate any future events of default related to its debt covenants.

F-104

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

Notes payable to members. The Company owes $9.6 million and $6.4 million as of September 30, 2016 and December 31, 2015, respectively, to members for general and administrative expenses incurred on behalf of the Company. These notes are payable to members by December 31, 2022 and bear interest after a year at the Applicable Federal Rate compounded annually paid at maturity. See related party information in Note 8.

Principal maturities. Principal maturities of long-term debt and notes payable to members at September 30, 2016, are as follows (in thousands):


2016	$	—
2017		—
2018		—
2019		—
2020		125,000
Thereafter		9,625

Interest expense. The following amounts have been incurred and charged to interest expense for the nine months ended September 30, 2016 (in thousands):


	2016
Cash payments for interest	$	2,804
Amortization of debt issuance costs		158
Net changes in accruals		(83	)

Total interest expense	$	2,879

(7)

Asset Retirement Obligations


	2016
Beginning asset retirement obligations	$	282
Accretion of discount		18

Ending asset retirement obligations	$	300

As of September 30, 2016, the Company considered the above asset retirement obligations to all be noncurrent.

(8)

Related-Party Transactions

F-105

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

Company were to directly obtain these services, management believes the aggregate costs charged to the Company by the members are reasonable. During the nine months ended September 30, 2016, the Company accrued $3.2 million, and during the nine months ended September 30, 2015, the Company accrued $3.3 million, as general and administrative expenses payable to members. These amounts do not necessarily correspond to the sharing ratios, but rather to the actual general and administrative expenses incurred by each member on behalf of the Company. These liabilities have been recorded on the accompanying balance sheets as long-term notes payable to members. They will accrue interest at a the Applicable Federal Rate beginning in 2017 if not paid in full and be subordinate to all other bank debt.

The Company paid Petromax Operating Company, Inc. (Petromax), who is the operator of the majority of the Company’s wells, $923,000 during the nine months ended September 30, 2016, and $635,000 during the nine months ended September 30, 2015, for Council of Petroleum Accountants Societies (COPAS) overhead charges on drilling and producing wells at market rates as set forth in joint operating agreements (JOA’s) and in accordance with an Operating Agreement between Petromax and the Company. Such amounts have been expensed in the accompanying financial statements in general and administrative expenses. Petromax is owned 33.3% by Mike Hoover, the Chief Operating Officer of the Company, who also owns indirectly approximately 20% of one of the members of the Company that owns approximately 36.2% of Esquisto Resources.

The Company paid Calbri Energy, Inc. and an affiliate (Calbri), a less than 1% owner of Esquisto Resources, $764,000 during the nine months ended September 30, 2016, respectively, and $280,000 during the nine months ended September 30, 2015, respectively, for completion consulting services and trucking. The rates being paid to Calbri are competitive with others in the area that we use for similar services.

(9)

Subsequent Events

Subsequent events have been evaluated through November 10, 2016, the date the financial statements were issued.

Derivatives. Subsequent to September 30, 2016, the Company entered into additional derivative financial instruments as follows:

•

15,000 barrels of oil per month was hedged with a swap priced at $53.87 per barrel for January 2017 to December 2017 with JPMorgan Chas Bank, N.A. (JPMorgan) as the counterparty

•

10,000 barrels of oil per month was hedged with a swap priced at $55.00 per barrel for January 2018 to December 2018 with JPMorgan as the counterparty

F-106

ESQUISTO RESOURCES II, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (continued)

Had these derivative financial instruments been in place and open as of September 30, 2016, the open positions would have been as follows:


	Fourth Quarter 2016		Year Ended December 31,
	Fourth Quarter 2016		2017		2018		2019
Crude oil swap contracts:
Volume (Bbl)		219,400		772,000		564,000		60,000
Price per Bbl	$	46.31	$	49.11	$	51.04	$	55.05
Natural gas swap contracts:
Volume (MMBTU)		150,000		600,000		—		—
Price per MMBTU	$	3.080	$	3.171		—		—
Crude oil collar contract:
Volume (Bbl)		18,472		60,784		25,096		—
Price per Bbl:
Ceiling	$	62.10	$	62.10	$	62.10		—
Floor	$	50.00	$	50.00	$	50.00		—

Acquisition. On October 20, 2016, the Company signed a purchase and sale agreement to acquire approximately 4,900 net undeveloped acres and nine producing wells in Burleson County, Texas in and around the assets it already owns and operates. The Company has agreed to pay $29.4 million for the undeveloped leasehold acres and $548,000 for the nine producing wells, subject to normal and customary closing adjustments. The Company made a $27 million capital call from members that was funded in early November to partially fund this acquisition in addition to borrowings from the Wells Fargo Revolving Credit Facility. This transaction closed in early November 2016.

F-107

Report of Independent Auditors

The Board of Managers

Esquisto Resources II, LLC and Subsidiaries:

We have audited the accompanying statements of revenues and direct operating expenses (the “financial statements”), which comprise the revenues and direct operating expenses of certain oil and gas properties of the members of Esquisto Resources II, LLC (“Esquisto”) prior to formation of and contribution to Esquisto (the “Pre-Esquisto Properties working interest”) for the period from January 1, 2014 to June 20, 2014 and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Pre-Esquisto Properties working interest for the period from January 1, 2014 to June 20, 2014 in conformity with accounting principles generally accepted in the United States of America, using the basis of presentation described in Note 1.

/s/ ERNST & YOUNG LLP

Dallas, TX

August 1, 2016

F-108

Statements of Revenues and Direct Operating Expenses of the

Pre-Esquisto Properties Working Interest (as described in Note 1)

(in thousands)


	Period From January 1, 2014 to June 20, 2014
Revenues	$	1,809
Direct operating expenses		(200	)

Revenues in excess of direct operating expenses	$	1,609

See accompanying notes to the Statements of Revenues and Direct Operating Expenses.

F-109

Notes to Statements of Revenues and Direct Operating Expenses of the

Pre-Esquisto Properties Working Interest (as described in Note 1)

(1)

Basis of Presentation

On June 20, 2014, Esquisto Resources, LLC (“Esquisto”) was formed and entered into a contribution agreement with initial members (the “Contribution Agreement”) whereby initial members agreed to contribute to Esquisto their working interests in certain undeveloped acreage and producing oil and gas properties in the Eagleford trend in East Texas (the “Pre-Esquisto Properties working interest”) with a total basis of $76.1 million that was considered a non-cash property contribution by members. The Contribution Agreement contains customary representations and warranties, covenants, indemnification provisions and conditions to closing. The transaction closed on June 20, 2014.

The accompanying audited statements include revenues from oil (including condensate and gas liquids) and gas production and direct operating expenses associated with the Pre-Esquisto Properties working interest. The accompanying statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Pre-Esquisto Properties working interest including, but not limited to, general and administrative expenses, interest expense and state income tax expense. These costs were not separately allocated to the Pre-Esquisto Properties working interest in the accounting records of the initial members of Esquisto. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Pre-Esquisto Properties working interest had it been an Esquisto property due to the differing size, structure, operations and accounting policies of the initial members of Esquisto and Esquisto. The accompanying statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs that Esquisto will incur upon the allocation of the purchase price paid for the Pre-Esquisto Properties working interest. Furthermore, no balance sheet has been presented for the Pre-Esquisto Properties working interest because the acquired properties were not accounted for as a separate subsidiary or division of the initial members of Esquisto and complete financial statements are not available, nor has information about the Pre-Esquisto Properties working interest’s operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical Statements of Revenues and Direct Operating Expenses of the Pre-Esquisto Properties working interest are presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission (“SEC”) Regulation S-X.

These Statements of Revenues and Direct Operating Expenses are not indicative of the results of operations for the Pre-Esquisto Properties working interest on a go forward basis.

(2)

Summary of Significant Accounting Policies

Use of Estimates —The Statements of Revenues and Direct Operating Expenses are derived from the historical operating statements of the initial members of Esquisto. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the Statements of Revenues and Direct Operating Expenses. Actual results could be different from those estimates.

Revenue Recognition —Total revenues in the accompanying statements include the sale of crude oil, natural gas and natural gas liquids, net of royalties. The initial Esquisto members recognize revenues when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. Oil and gas revenues included in these statements are recorded on the sales method, under which revenues are based on the oil, natural gas liquids and natural gas delivered rather than the net revenue interest share of oil and gas produced. There were no significant imbalances with other revenue interest owners during the period from January 1, 2014 to June 20, 2014.

F-110

Notes to Statements of Revenues and Direct Operating Expenses of the

Pre-Esquisto Properties Working Interest (as described in Note 1) (continued)

During the period from January 1, 2014 to June 20, 2014, Shell Trading (US) Company accounted for approximately 94% of the Pre-Esquisto Properties working interest’s total revenues. During such period, no other purchaser accounted for more than 10% of the total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect; however, it is not likely that the loss of any single significant customer or contract would materially affect the Pre-Esquisto Properties working interest in the long-term as such purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

Direct Operating Expenses —Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Pre-Esquisto Properties working interest. The direct operating expenses include lease operating, production taxes, processing and transportation expenses. Lease operating expenses include lifting costs, well repair expenses, facility maintenance expenses, well workover costs, and other field related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and gas production activities.

(3)

Contingencies

The activities of the Pre-Esquisto Properties working interest may become subject to potential claims and litigation in the normal course of operations. Esquisto does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Pre-Esquisto Properties working interest.

(4)

Subsequent Events

Esquisto has evaluated events through August 1, 2016, the date the Statements of Revenues and Direct Operating Expenses were available to be issued, and has concluded no events need to be reported during this period.

Supplementary Oil and Gas Disclosures (Unaudited)

Supplemental reserve information

The following unaudited supplemental reserve information summarizes the net proved reserves of oil and gas and the standardized measure thereof as of June 20, 2015 and for the period from January 1, 2014 to June 20, 2014 attributable to the Pre-Esquisto Properties working interest. All of the reserves are located in the United States. The following table sets forth certain information with respect to the reserves attributable to the Pre-Esquisto Properties working interest as of June 20, 2014 and for the period from January 1, 2014 to June 20, 2014. The reserve disclosures are based on reserve studies prepared in accordance with the guidelines established by the SEC.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may each differ from those assumed in these estimates. In addition, the different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to the Pre-Esquisto

F-111

Notes to Statements of Revenues and Direct Operating Expenses of the

Pre-Esquisto Properties Working Interest (as described in Note 1) (continued)

Properties working interest. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Pre-Esquisto Properties working interest and any adjustments in the projected economic life of such property resulting from changes in product prices.

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which was first effective for reporting reserve information as of December 31, 2009. In January 2010, the Financial Accounting Standards Board issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. Under the SEC’s final rule, prior period reserves were not restated.

Estimated quantities of oil, NGL and gas reserves

The following table sets forth certain data pertaining to the Pre-Esquisto Properties working interest’s proved, proved developed and proved undeveloped reserves as of June 20, 2014 and for the period from January 1, 2014 to June 20, 2014.


	Oil (MBbl)			NGL (MBbl)			Gas (MMCF)			Total (MBOE)
June 20, 2014
Proved Reserves
Beginning balance, January 1, 2014		—			—			—			—
Revision of previous estimates		—			—			—			—
Extensions and discoveries		154			22			79			189
Improved recovery		—			—			—			—
Purchase of reserves-in-place		—			—			—			—
Sale of reserves-in-place		—			—			—			—
Production		(17	)		(2	)		(7	)		(20	)

Ending balance, June 20, 2014		137			20			72			169

Proved Developed Reserves January 1		—			—			—			—

Proved Developed Reserves June 20		137			20			72			169

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure of Discounted Future Net Cash Flows (excluding income tax expense) relating to proved crude oil and gas reserves is presented below:


	June 20, 2014
Future cash inflows	$	14,256
Future development and abandonment costs(a)		(50	)
Future production expense		(3,691	)

Future net cash flows		10,515
Discounted at 10% per year		(3,584	)

Standardized measure of discounted future net cash flows	$	6,931

(a)	The $50,000 as of June 20, 2014 represents undiscounted future asset retirement expenditures estimated as of those dates using current estimates of future abandonment costs.

F-112

Notes to Statements of Revenues and Direct Operating Expenses of the

Pre-Esquisto Properties Working Interest (as described in Note 1) (continued)

The Standardized Measure of Discounted Future Net Cash Flows (discounted at 10%) from production of proved reserves was developed as follows:

•

An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on current economic conditions.

•

In accordance with SEC guidelines, the engineers’ estimates of future net revenues from proved properties and the present value thereof are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. These prices are held constant throughout the life of the properties, except where such guidelines permit alternate treatment. The realized sales prices used in the reserve reports as of June 20, 2014 were $99.80 per barrel of oil, and $23.57 per barrel of NGL and $3.77 per MCF of gas.

•

The future gross revenue streams were reduced by estimated future operating costs and future development and abandonment costs, all of which were based on current costs in effect at the date presented and held constant throughout the life of the properties.

As described in Note 1, these Statements of Revenue and Direct Operating Expenses do not include income tax expense or balance sheet information, therefore income tax and capital expenditure estimates were omitted from the Standardized Measure of Discounted Future Net Cash Flows calculation. The principal sources of changes in the Standardized Measure of Discounted Future Net Cash Flows for each of the periods presented below are as follows:


	Period From January 1, 2014 to June 20, 2014
Balance, beginning of year	$	—
Oil and gas sales, net of production costs		(1,609	)
Extensions and discoveries		8,000
Net change in sales prices and production costs		—
Improved recovery, net of costs		—
Changes in estimated future development costs		—
Changes in production rates (timing) and other		—
Purchase of minerals-in-place		—
Sales of minerals-in-place		—
Revision of quantity estimates		—
Accretion of discount		—

Standardized measure of discounted future net cash flows	$	6,391

F-113

Report of Independent Auditors

The Board of Managers

Esquisto Resources II, LLC and Subsidiaries:

We have audited the accompanying statements of revenues and direct operating expenses (the “financial statements”), which comprise the revenues and direct operating expenses of certain oil and gas properties of Comstock Resources, Inc. acquired by Esquisto Resources II, LLC (the “Comstock Properties working interest”) for the seven month period ended July 31, 2015 and the year ended December 31, 2014 and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Auditor’s Responsibility

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties of Comstock Resources, Inc. acquired by Esquisto Resources II, LLC (the “Comstock Properties working interest”) for the seven month period ended July 31, 2015 and the year ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America, using the basis of presentation described in Note 1.

/s/ ERNST & YOUNG LLP

Dallas, TX

August 1, 2016

F-114

Statements of Revenues and Direct Operating Expenses of the

Comstock Properties Working Interest (as described in Note 1)

(in thousands)


	Period From January 1, 2015 to July 31, 2015			Year Ended December 31, 2014
Revenues	$	18,035		$	10,608
Direct operating expenses		(1,999	)		(942	)

Revenues in excess of direct operating expenses	$	16,036		$	9,666

See accompanying notes to the Statements of Revenues and Direct Operating Expenses.

F-115

Notes to Statements of Revenues and Direct Operating Expenses of the

Comstock Properties Working Interest (as described in Note 1)

(1)

Basis of Presentation

On June 30, 2015, Esquisto Resources II, LLC (“Esquisto”) entered into a purchase and sale agreement (the “PSA”) to acquire from Comstock Oil & Gas, LP (“Comstock”), a wholly owned subsidiary of Comstock Resources, Inc., its working interests in certain producing oil and gas properties, undeveloped acreage and water assets in the Eagleford trend in East Texas (the “Comstock Properties working interest”) for a total of $115 million in cash, subject to customary purchase price adjustments. The PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to closing. The transaction closed on July 22, 2015 and was effective as of May 1, 2015.

The accompanying audited statements include revenues from oil (including condensate and gas liquids) and gas production and direct operating expenses associated with the Comstock Properties working interest. The accompanying statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Comstock Properties working interest including, but not limited to, general and administrative expenses, interest expense and state income tax expense. These costs were not separately allocated to the Comstock Properties working interest in the accounting records of Comstock. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Comstock Properties working interest had it been an Esquisto property due to the differing size, structure, operations and accounting policies of Comstock and Esquisto. The accompanying statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs that Esquisto will incur upon the allocation of the purchase price paid for the Comstock Properties working interest. Furthermore, no balance sheet has been presented for the Comstock Properties working interest because the acquired properties were not accounted for as a separate subsidiary or division of Comstock and complete financial statements are not available, nor has information about the Comstock Properties working interest’s operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical Statements of Revenues and Direct Operating Expenses of the Comstock Properties working interest are presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission (“SEC”) Regulation S-X.

These Statements of Revenues and Direct Operating Expenses are not indicative of the results of operations for the Comstock Properties working interest on a go forward basis.

(2)

Summary of Significant Accounting Policies

Use of Estimates —The Statements of Revenues and Direct Operating Expenses are derived from the historical operating statements of Comstock. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the Statements of Revenues and Direct Operating Expenses. Actual results could be different from those estimates.

Revenue Recognition —Total revenues in the accompanying statements include the sale of crude oil, natural gas and natural gas liquids, net of royalties. Comstock recognizes revenues when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. Oil and gas revenues included in these statements are recorded on the sales method, under which revenues are based on the oil, natural gas liquids and natural gas delivered rather than the net revenue interest share of oil and gas produced. There were no significant imbalances with other revenue interest owners during the period from January 1, 2015 to July 31, 2015 and the year ended December 31, 2014.

During the period from January 1, 2015 to July 31, 2015, Sunoco, Inc. accounted for approximately 77% and Shell Trading (US) Company accounted for approximately 10% of the Comstock Properties working

F-116

Notes to Statements of Revenues and Direct Operating Expenses of the

Comstock Properties Working Interest (as described in Note 1)

interest’s total revenues. During 2014, Shell Trading (US) Company accounted for approximately 76% of the Comstock Properties working interest’s total revenues. During such periods, no other purchaser accounted for more than 10% of the total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect; however, it is not likely that the loss of any single significant customer or contract would materially affect the Comstock Properties working interest in the long-term as such purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

Direct Operating Expenses —Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Comstock Properties working interest. The direct operating expenses include lease operating, production taxes, processing and transportation expenses. Lease operating expenses include lifting costs, well repair expenses, facility maintenance expenses, well workover costs, and other field related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and gas production activities.

(3)

Contingencies

The activities of the Comstock Properties working interest may become subject to potential claims and litigation in the normal course of operations. Esquisto does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Comstock Properties working interest.

(4)

Subsequent Events

Supplementary Oil and Gas Disclosures (Unaudited)

Supplemental reserve information

The following unaudited supplemental reserve information summarizes the net proved reserves of oil and gas and the standardized measure thereof as of July 31, 2015 and December 31, 2014 and for the period from January 1, 2015 to July 31, 2015 and the year ended December 31, 2014 attributable to the Comstock Properties working interest. All of the reserves are located in the United States. The following table sets forth certain information with respect to the reserves attributable to the Comstock Properties working interest as of July 31, 2015 and December 31, 2014 and for the period from January 1, 2015 to July 31, 2015 and the year ended December 31, 2014. The reserve disclosures are based on reserve studies prepared in accordance with the guidelines established by the SEC.

F-117

Notes to Statements of Revenues and Direct Operating Expenses of the

Comstock Properties Working Interest (as described in Note 1)

be construed as the current market value of the estimated oil and gas reserves attributable to the Comstock Properties working interest. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Comstock Properties working interest and any adjustments in the projected economic life of such property resulting from changes in product prices.

Estimated quantities of oil, NGL and as reserves

The following table sets forth certain data pertaining to the Comstock Properties working interest’s proved, proved developed and proved undeveloped reserves as of July 31, 2015 and December 31, 2014 and for the period from January 1, 2015 to July 31, 2015 and the year ended December 31, 2014.


	Oil (MBbl)			NGL (MBbl)			Gas (MMCF)			Total (MBOE)
July 31, 2015
Proved Reserves
Beginning balance, January 1, 2015		999			295			1,108			1,479
Revision of previous estimates		(49	)		(25	)		(77	)		(87	)
Extensions and discoveries		1,128			716			2,756			2,303
Improved recovery		—			—			—			—
Purchase of reserves-in-place		—			—			—			—
Sale of reserves-in-place		—			—			—			—
Production		(308	)		(95	)		(441	)		(476	)

Ending balance, July 31, 2015		1,770			891			3,346			3,219

Proved Developed Reserves January 1		999			295			1,108			1,479

Proved Developed Reserves July 31		1,770			891			3,346			3,219


December 31, 2014
Proved Reserves
Beginning balance, January 1		—			—			—			—
Revision of previous estimates		—			—			—			—
Extensions and discoveries		1,113			320			1,199			1,633
Improved recovery		—			—			—			—
Purchase of reserves-in-place		—			—			—			—
Sale of reserves-in-place		—			—			—			—
Production		(114	)		(25	)		(91	)		(154	)

Ending balance, December 31, 2014		999			295			1,108			1,479

Proved Developed Reserves January 1		—			—			—			—

Proved Developed Reserves December 31		999			295			1,108			1,479

F-118

Notes to Statements of Revenues and Direct Operating Expenses of the

Comstock Properties Working Interest (as described in Note 1)

The changes in proved reserves during 2015 and 2014 are comprised of the following items:

Revision of previous estimates . Revision of previous estimates of 87 MBOE during 2015 is attributable to decreased commodity prices, which decreased the useful lives of the wells, decreasing the ultimate reserves recovered.

Extensions and discoveries . Extensions and discoveries of 2,303 MBOE and 1,633 MBOE during 2015 and 2014, respectively, are comprised of discoveries and extensions in the Eagle Ford horizons in Burleson County, Texas as a result of continuous drilling in the area.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure of Discounted Future Net Cash Flows (excluding income tax expense) relating to proved crude oil and gas reserves is presented below:


	July 31, 2015			December 31, 2014
Future cash inflows	$	143,062		$	105,359
Future development and abandonment costs(a)		(695	)		(305	)
Future production expense		(41,876	)		(21,661	)

Future net cash flows		100,491			83,393
Discounted at 10% per year		(37,578	)		(30,022	)

Standardized measure of discounted future net cash flows	$	62,913		$	53,371

(a)	The $695,000 and $305,000 as of July 31, 2015 and December 31, 2014, respectively, represent undiscounted future asset retirement expenditures estimated as of those dates using current estimates of future abandonment costs.

The Standardized Measure of Discounted Future Net Cash Flows (discounted at 10%) from production of proved reserves was developed as follows:

•

An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on current economic conditions.

•

In accordance with SEC guidelines, the engineers’ estimates of future net revenues from proved properties and the present value thereof are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. These prices are held constant throughout the life of the properties, except where such guidelines permit alternate treatment. The realized sales prices used in the reserve reports as of July 31, 2015 and December 31, 2014 were $67.15 and $94.48 per barrel of oil, respectively, and $15.90 and $22.32 per barrel of NGL, respectively, and $3.00 and $3.97 per MCF of gas, respectively.

•

F-119

Notes to Statements of Revenues and Direct Operating Expenses of the

Comstock Properties Working Interest (as described in Note 1)


	Seven Months Ended July 31, 2015			Year Ended December 31, 2014
Balance, beginning of year	$	53,371		$	—
Oil and gas sales, net of production costs		(16,036	)		(9,666	)
Extensions and discoveries		45,054			63,037
Net change in sales prices and production costs		(19,228	)		—
Improved recovery, net of costs		—			—
Changes in estimated future development costs		—			—
Changes in production rates (timing) and other		(1,257	)		—
Purchase of minerals-in-place		—			—
Sales of minerals-in-place		—			—
Revision of quantity estimates		(2,104	)		—
Accretion of discount		3,113			—

Standardized measure of discounted future net cash flows	$	62,913		$	53,371

F-120

Independent Auditors’ Report

The Board of Managers

WHE AcqCo., LLC:

We have audited the accompanying statements of revenues and direct operating expenses (the “financial statements”), which comprise the revenues and direct operating expenses of certain oil and gas properties of Clayton Williams Energy, Inc. contracted to be acquired by WHE AcqCo., LLC (the “Burleson North Properties working interest”) for the nine month period ended September 30, 2016 and the years ended December 31, 2015 and 2014, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

The accompanying financial statements referred to above were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. The financial statements are not intended to be a complete presentation of the operations of the Burleson North Properties working interest.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Burleson North Properties working interest for the nine month period ended September 30, 2016 and the years ended December 31, 2015 and 2014 in accordance with U.S. generally accepted accounting principles.

Other Matter

U.S. generally accepted accounting principles require that the Supplementary Oil and Gas Disclosures contained herein be presented to supplement the basic financial statements. Such information, although not a part of the

F-121

basic financial statements, is required by the Financial Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

/s/ KPMG LLP

Dallas, Texas

November 10, 2016

F-122

Statements of Revenues and Direct Operating Expenses of the

Burleson North Properties Working Interest (as described in Note 1)

(in thousands)


	Period From January 1, 2016 to September 30, 2016			Years Ended December 31,
	Period From January 1, 2016 to September 30, 2016			2015			2014
Revenues	$	37,193		$	85,709		$	150,877
Direct operating expenses		(16,512	)		(26,275	)		(27,975	)

Revenues in excess of direct operating expenses	$	20,681		$	59,434		$	122,902

See accompanying notes to the Statements of Revenues and Direct Operating Expenses.

F-123

Notes to Statements of Revenues and Direct Operating Expenses of the

Burleson North Properties Working Interest (as described in Note 1)

(1)

Basis of Presentation

On October 24, 2016, WHE AcqCo., LLC (“WHE AcqCo”) entered into a purchase and sale agreement (the “PSA”) to acquire from Clayton Williams Energy, Inc. (“CWEI”) its working interests in certain producing oil and gas properties and undeveloped acreage in the Eagleford and Austin Chalk trends in East Texas (the “Burleson North Properties working interest”) for a total of $400.0 million in cash, subject to customary purchase price adjustments. The PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to closing. The transaction is expected to close in December 2016 and is effective as of October 1, 2016.

The accompanying audited statements include revenues from oil (including condensate and gas liquids) and gas production and direct operating expenses associated with the Burleson North Properties working interest and were derived from CWEI’s consolidated historical accounting records. The accompanying statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Burleson North Properties working interest including, but not limited to, general and administrative expenses, interest expense and state income tax expense. These costs were not separately allocated to the Burleson North Properties working interest in the accounting records of CWEI. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Burleson North Properties working interest had it been a WHE AcqCo property due to the differing size, structure, operations and accounting policies of CWEI and WHE AcqCo. The accompanying statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs that WHE AcqCo will incur upon the allocation of the purchase price paid for the Burleson North Properties working interest. Furthermore, no balance sheet has been presented for the Burleson North Properties working interest because the acquired properties were not accounted for as a separate subsidiary or division of CWEI and complete financial statements are not available, nor has information about the Burleson North Properties working interest’s operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical Statements of Revenues and Direct Operating Expenses of the Burleson North Properties working interest are presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission (“SEC”) Regulation S-X.

These Statements of Revenues and Direct Operating Expenses are not indicative of the results of operations for the Burleson North Properties working interest on a go forward basis.

(2)

Summary of Significant Accounting Policies

Use of Estimates— The Statements of Revenues and Direct Operating Expenses are derived from the historical operating statements of CWEI. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the respective reporting periods. Actual results could be different from those estimates.

Revenue Recognition— Total revenues in the accompanying statements include the sale of crude oil, natural gas and natural gas liquids, net of royalties. CWEI recognizes revenues when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. Oil and gas revenues included in these statements are recorded on the sales method, under which revenues are based on the oil, natural gas liquids and natural gas delivered rather than the net revenue interest share of oil and gas produced. There were no significant imbalances with other revenue interest owners during the period from January 1, 2016 to September 30, 2016 and the years ended December 31, 2015 and 2014.

F-124

Notes to Statements of Revenues and Direct Operating Expenses of the

Burleson North Properties Working Interest (as described in Note 1) (continued)

During the period from January 1, 2016 to September 30, 2016, two customers accounted for approximately 46% and 45% of the Burleson North Properties working interest’s total revenues, respectively. During 2015, these two customers accounted for approximately 58% and 36% of the Burleson North Properties working interest’s total revenues, respectively. During 2014, these two customers accounted for approximately 28% and 64% of the Burleson North Properties working interest’s total revenues, respectively. During such periods, no other purchaser accounted for more than 10% of the total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect; however, it is not likely that the loss of any single significant customer or contract would materially affect the Burleson North Properties working interest in the long-term as such purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

Direct Operating Expenses— Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Burleson North Properties working interest. The direct operating expenses include lease operating, production taxes, processing and transportation expenses. Lease operating expenses include lifting costs, well repair expenses, facility maintenance expenses, well workover costs, and other field related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and gas production activities.

(3)

Contingencies

The activities of the Burleson North Properties working interest may become subject to potential claims and litigation in the normal course of operations. CWEI does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Burleson North Properties working interest.

(4)

Subsequent Events

CWEI has evaluated events through November 10, 2016, the date the Statements of Revenues and Direct Operating Expenses were available to be issued, and are not aware of any events that have occurred that require adjustments to or disclosure in the financial statements.

Supplementary Oil and Gas Disclosures (Unaudited)

Supplemental reserve information

The following unaudited supplemental reserve information summarizes the net proved reserves of oil and gas and the standardized measure thereof attributable to the Burleson North Properties working interest as of September 30, 2016 and December 31, 2015 and 2014 and for the period from January 1, 2016 to September 30, 2016 and the years ended December 31, 2015 and 2014 attributable to the Burleson North Properties working interest. All of the reserves are located in the United States. The reserve disclosures are based on reserve studies prepared in accordance with the guidelines established by the SEC.

F-125

Notes to Statements of Revenues and Direct Operating Expenses of the

Burleson North Properties Working Interest (as described in Note 1) (continued)

upon the same available data. The standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to the Burleson North Properties working interest. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Burleson North Properties working interest and any adjustments in the projected economic life of such property resulting from changes in product prices.

Estimated quantities of oil, NGL and gas reserves

The following table sets forth certain data pertaining to the Burleson North Properties working interest’s proved developed reserves as of September 30, 2016 and December 31, 2015 and 2014 and for the period from January 1, 2016 to September 30, 2016 and the years ended December 31, 2015 and 2014.


	Oil (MBbl)			NGL (MBbl)			Gas (MMCF)			Total (MBOE)
September 30, 2016
Proved Reserves
Beginning balance, January 1, 2016		6,924			428			4,401			8,085
Revision of previous estimates		(401	)		(21	)		65			(411	)
Production		(922	)		(71	)		(895	)		(1,142	)

Ending balance, September 30, 2016		5,601			336			3,571			6,532

Proved Developed Reserves January 1		6,924			428			4,401			8,085

Proved Developed Reserves September 30		5,601			336			3,571			6,532


December 31, 2015
Proved Reserves
Beginning balance, January 1		8,575			579			5,877			10,133
Revision of previous estimates		(809	)		(96	)		(314	)		(958	)
Extensions and discoveries		925			50			262			1,019
Production		(1,767	)		(105	)		(1,424	)		(2,109	)

Ending balance, December 31, 2015		6,924			428			4,401			8,085

Proved Developed Reserves January 1		8,575			579			5,877			10,133

Proved Developed Reserves December 31		6,924			428			4,401			8,085


December 31, 2014
Proved Reserves
Beginning balance, January 1		7,018			469			5,743			8,444
Revision of previous estimates		637			35			756			798
Extensions and discoveries		2,556			183			776			2,868
Production		(1,636	)		(108	)		(1,398	)		(1,977	)

Ending balance, December 31, 2014		8,575			579			5,877			10,133

Proved Developed Reserves January 1		7,018			469			5,743			8,444

Proved Developed Reserves December 31		8,575			579			5,877			10,133

F-126

Notes to Statements of Revenues and Direct Operating Expenses of the

Burleson North Properties Working Interest (as described in Note 1) (continued)

The changes in proved reserves during 2016, 2015 and 2014 are comprised of the following items:

Revision of previous estimates. Revision of previous estimates for all periods can be primarily attributed to changes in commodity prices whereby when increased, it increases the estimated useful life of the wells and when decreased, it decreases the estimated useful life of the wells, thereby increasing or decreasing the ultimate recoverable reserves, respectively.

Extensions and discoveries. Extensions and discoveries during 2015 and 2014 are the result of drilling in the Eagleford trend where nine wells were added in 2015 and 25 wells were added in 2014, and the addition of one Austin Chalk well in 2015.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure of Discounted Future Net Cash Flows (excluding income tax expense) relating to proved crude oil and gas reserves is presented below:


	September 30, 2016			December 31,
	September 30, 2016			2015			2014
Future cash inflows	$	233,975		$	347,910		$	815,002
Future development and abandonment costs(a)		(14,219	)		(14,219	)		(13,720	)
Future production expense		(108,069	)		(143,550	)		(252,909	)

Future net cash flows		111,687			190,141			548,373
Discounted at 10% per year		(30,643	)		(57,863	)		(186,807	)

Standardized measure of discounted future net cash flows	$	81,044		$	132,278		$	361,566

(a)	The $14.2 million, $14.2 million and $13.7 million as of September 30, 2016, December 31, 2015 and 2014, respectively, represent undiscounted future asset retirement expenditures estimated as of those dates using current estimates of future abandonment costs.

The Standardized Measure of Discounted Future Net Cash Flows (discounted at 10%) from production of proved reserves was developed as follows:

•

An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on current economic conditions.

•

In accordance with SEC guidelines, the engineers’ estimates of future net revenues from proved properties and the present value thereof are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. These prices are held constant throughout the life of the properties, except where such guidelines permit alternate treatment. The realized sales prices used in the reserve reports as of September 30, 2016 and December 31, 2015 and 2014 were $39.79, $47.98 and $90.71 per barrel of oil, respectively, and $10.75, $13.04 and $24.96 per barrel of NGL, respectively, and $2.10, $2.30 and $3.87 per MCF of gas, respectively.

•

F-127

Notes to Statements of Revenues and Direct Operating Expenses of the

Burleson North Properties Working Interest (as described in Note 1) (continued)


	Period From January 1, 2016 to September 30, 2016			Years Ended December 31,
	Period From January 1, 2016 to September 30, 2016			2015			2014
Balance, beginning of year	$	132,278		$	361,566		$	287,062
Oil and gas sales, net of production costs		(20,681	)		(59,434	)		(122,902	)
Extensions and discoveries		—			22,248			130,766
Net change in sales prices and production costs		(34,732	)		(202,074	)		(2,747	)
Changes in production rates (timing) and other		(233	)		(10,810	)		14,217
Revision of quantity estimates		(5,509	)		(15,375	)		26,464
Accretion of discount		9,921			36,157			28,706

Standardized measure of discounted future net cash flows	$	81,044		$	132,278		$	361,566

F-128

ANNEX A

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 is an energy content correlation and does not reflect a value or price relationship between the commodities.

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.

Compound annual growth rate or CAGR . The annual growth rate of a metric over a specified period of time longer than a year, calculated by dividing the value of the metric at the end of the period in question by its value at the beginning of that period, raising the result to the power of one divided by the period length, and then subtracting one from the subsequent result. A calculation of the average compounded growth rate assumes that the growth rate derived from the calculation is even across the periods covered by the calculation and does not take into account any fluctuations for any periods other than the periods used to calculate the CAGR. Accordingly, the use of a CAGR may have limitations particularly in situations where there are substantial fluctuations in production during periods between the periods used to make the calculation.

Completion. 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.

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).

A-1

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.

Exploration costs . Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. For a complete definition of exploration costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(12).

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 2 . With respect to our Eagle Ford Acreage, a slickwater fracking technique using approximately 2,600 pounds per foot of sand and 53 Bbls per foot of fluid, with 200 foot stages and seven clusters per stage at 90 barrels per minute. With respect to our North Louisiana Acreage, a slickwater fracking technique using approximately 1,600 pounds per foot of sand, with 200 foot stages and two clusters per stage at 55 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 gas.

A-2

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.

Net revenue interest . A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

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 . 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 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).

A-3

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

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

A-4

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.

Service well . A well drilled or completed for the purpose of supporting production in an existing field.

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.

Spud . Commenced drilling operations on an identified location.

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.

Stratigraphic test well . A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

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.

Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

A-5

Unproved properties . Properties with no proved reserves.

Wellbore . The hole drilled by the bit that is equipped for 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.

A-6

Shares

LOGO

WildHorse Resource Development Corporation

Common Stock

Prospectus

, 2016

Barclays

BofA Merrill Lynch

BMO Capital Markets

Citigroup

Wells Fargo Securities

Guggenheim Securities

J.P. Morgan

Raymond James

Simmons & Company International

Energy Specialists of Piper Jaffray

Tudor, Pickering, Holt & Co.

Capital One Securities

Comerica Securities

Scotia Howard Weil

Wunderlich

Part II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.

Other Expenses of Issuance and Distribution

The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts and commissions) payable by us in connection with the registration of the common stock offered hereby. With the exception of the SEC registration fee, the FINRA filing fee, and the NYSE listing fee, the amounts set forth below are estimates.


SEC registration fee	$	75,335
FINRA filing fee		98,000
NYSE listing fee		250,000
Accounting fees and expenses		750,000
Legal fees and expenses		2,500,000
Printing and engraving expenses		600,000
Transfer agent and registrar fees		20,000
Fees associated with new revolving credit facility		2,300,000
Miscellaneous		131,665

Total	$	6,725,000

Item 14.

Indemnification of Directors and Officers

Section 145 of the DGCL provides that a corporation may indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise), against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. A similar standard is applicable in the case of derivative actions (i.e., actions by or in the right of the corporation), except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation.

Our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that limit the liability of our directors and officers for monetary damages to the fullest extent permitted by the DGCL. Consequently, our directors will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except liability:

•

for any breach of the director’s duty of loyalty to our company or our stockholders;

•

for any act or omission not in good faith or that involve intentional misconduct or knowing violation of law;

•

under Section 174 of the DGCL regarding unlawful dividends and stock purchases; or

•

for any transaction from which the director derived an improper personal benefit.

II-1

Any amendment to, or repeal of, these provisions will not eliminate or reduce the effect of these provisions in respect of any act, omission or claim that occurred or arose prior to that amendment or repeal. If the DGCL is amended to provide for further limitations on the personal liability of directors or officers of corporations, then the personal liability of our directors and officers will be further limited to the fullest extent permitted by the DGCL.

In addition, we intend to enter into indemnification agreements with our current directors and officers containing provisions that are in some respects broader than the specific indemnification provisions contained in the DGCL. The indemnification agreements will require us, among other things, to indemnify our directors against certain liabilities that may arise by reason of their status or service as directors and to advance their expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and officers.

We intend to maintain liability insurance policies that indemnify our directors and officers against various liabilities, including certain liabilities under arising under the Securities Act and the Exchange Act, that may be incurred by them in their capacity as such.

The proposed form of Underwriting Agreement to be filed as Exhibit 1.1 to this registration statement provides for indemnification of our directors and officers by the underwriters against certain liabilities arising under the Securities Act or otherwise in connection with this offering.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Item 15.

Recent Sales of Unregistered Securities

Prior to the closing of this offering, we will issue shares of our common stock to WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings in connection with the Corporate Reorganization and shares to the third-party sellers in the Rosewood Acquisition (based on the midpoint of the price range set forth on the cover page of the prospectus). The shares of our common stock described in this Item 15 will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering.

Item 16.

Exhibits and Financial Statement Schedules

(a) Exhibits. See the Exhibit Index immediately following the signature page hereto, which is incorporated by reference as if fully set forth herein.

(b) Financial Statement Schedules. Financial statement schedules are omitted because the required information is not applicable, not required or included in the financial statements or the notes thereto included in the prospectus that forms a part of this registration statement.

Item 17.

Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant

II-2

has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on November 23, 2016.


WILDHORSE RESOURCE DEVELOPMENT CORPORATION

By:		/s/ Jay C. Graham
Name:		Jay C. Graham
Title:		Chief Executive Officer and Chairman

Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities and on the dates indicated.


Name	Title	Date

/s/ Jay C. Graham Jay C. Graham	Chief Executive Officer and Chairman (Principal Executive Officer)		November 23, 2016

/s/ Andrew J. Cozby Andrew J. Cozby	Executive Vice President and Chief Financial Officer (Principal Financial Officer)		November 23, 2016

* Terence Lynch	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)		November 23, 2016

* Anthony Bahr	President and Director		November 23, 2016

* Richard D. Brannon	Director		November 23, 2016

* Scott Gieselman	Director		November 23, 2016

* David W. Hayes	Director		November 23, 2016

* Tony R. Weber	Director		November 23, 2016



* By:		/ S / J AY C. G RAHAM
		Jay C. Graham Attorney-in-fact

II-4

INDEX TO EXHIBITS


Exhibit Number		Description
	***1.1	Form of Underwriting Agreement
	***2.1	Form of Master Contribution Agreement
	***3.1	Certificate of Incorporation of WildHorse Resource Development Corporation
	***3.2	Form of Amended and Restated Certificate of Incorporation of WildHorse Resource Development Corporation
	***3.3	Bylaws of WildHorse Resource Development Corporation
	***3.4	Form of Amended and Restated Bylaws of WildHorse Resource Development Corporation
	***3.5	Form of WHR Holdings, LLC Limited Liability Company Agreement
	***3.6	Form of WildHorse Investment Holdings, LLC Limited Liability Company Agreement
	***3.7	Form of Esquisto Holdings, LLC Limited Liability Company Agreement
	***3.8	Form of WHE AcqCo. Holdings, LLC Limited Liability Company Agreement
	***4.1	Form of Common Stock Certificate
	***4.2	Form of Registration Rights Agreement
	***4.3	Form of Stockholders’ Agreement
	***5.1	Form of Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
	*10.1	Form of Credit Agreement
	***10.2	Form of WildHorse Resource Development Corporation Long-Term Incentive Plan
	***10.3	Form of Indemnification Agreement between WildHorse Resource Development Corporation and each of the directors and officers thereof
	***10.4	Form of Transition Services Agreement
	**10.5	Form of Executive Change In Control and Severance Benefit Plan
	**10.6	Form of Restricted Stock Award Agreement
	***21.1	Subsidiaries of WildHorse Resource Development Corporation
	**23.1	Consent of KPMG LLP
	**23.2	Consent of KPMG LLP
	**23.3	Consent of KPMG LLP
	**23.4	Consent of Ernst & Young LLP
	**23.5	Consent of Ernst & Young LLP
	**23.6	Consent of Ernst & Young LLP
	**23.7	Consent of Cawley, Gillespie & Associates, Inc.
	**23.8	Consent of Cawley, Gillespie & Associates, Inc.
	***23.9	Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto)
	***24.1	Power of Attorney (included on the signature page of this Registration Statement)
	***99.1	Cawley, Gillespie & Associates, Inc., Audit Letter of WildHorse Resources II, LLC at December 31, 2014
	***99.2	Cawley, Gillespie & Associates, Inc., Reserve Report of Esquisto Resources II, LLC at December 31, 2014
	***99.3	Cawley, Gillespie & Associates, Inc., Audit Letter of WildHorse Resources II, LLC at December 31, 2015

II-5


Exhibit Number		Description
	***99.4	Cawley, Gillespie & Associates, Inc., Reserve Report of Esquisto Resources II, LLC at December 31, 2015
	***99.5	Cawley, Gillespie & Associates, Inc., Audit Letter of WildHorse Resources II, LLC at June 30, 2016
	***99.6	Cawley, Gillespie & Associates, Inc., Reserve Report of Esquisto Resources II, LLC at June 30, 2016
	**99.7	Consent of Jonathan M. Clarkson

*	To be filed by amendment.

**	Filed herewith.

***	Previously filed.

II-6

Exhibit 10.5

FORM OF

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

EXECUTIVE CHANGE IN CONTROL AND SEVERANCE BENEFIT PLAN

1. Purpose and Effective Date . WildHorse Resource Development Corporation, a Delaware corporation (the “ Company ”) has adopted this Executive Change in Control and Severance Benefit Plan (the “ Plan ”) to provide for the payment of severance and/or change in control benefits to Eligible Individuals. The effective date of the Plan is , 2016.

2. Definitions . For purposes of the Plan, the terms listed below will have the meanings specified herein:

(a) “ Accrued Payments ” means (i) any unpaid Base Salary through the Date of Termination (but calculated at the rate then in effect), which shall be paid within 30 days of the Date of Termination, (ii) any unpaid Performance Bonus actually earned in the calendar year prior to the calendar year in which the Date of Termination occurs, which shall be paid at the time annual bonuses are normally paid by the Company, (iii) unreimbursed business or other expenses accrued through the Date of Termination that are eligible for reimbursement in accordance with the applicable Company policies through the Date of Termination (provided that such expenses and any required substantiation and documentation are submitted timely in accordance with applicable Company policies), and (iv) such employee benefits, if any, as to which an Eligible Individual may be entitled pursuant to the terms governing such benefits.

(b) “ Applicable Performance Bonus ” means the greater of (i) the Eligible Individual’s average Performance Bonus amounts for the two calendar years preceding the calendar year in which the Date of Termination occurs or (ii) the Eligible Individual’s target Performance Bonus for the calendar year in which the Date of Termination occurs, calculated based on such Eligible Individual’s Base Salary.

(c) “ Base Salary ” means the amount an Eligible Individual is entitled to receive as wages or salary on an annualized basis, calculated as of the Date of Termination or, if greater, before giving effect to any reduction not consented to by the Eligible Individual.

(d) “ Board ” means the Board of Directors of the Company.

(e) “ Cause ” means a determination made in good faith by two-thirds (2/3) of the Board that an Eligible Individual (i) has been convicted of a misdemeanor involving moral turpitude or a felony, (ii) has engaged in grossly negligent or willful misconduct in the performance of his duties for the Company (other than due to the Eligible Individual’s incapacity due to physical or mental illness), which actions have had a material detrimental effect on the Company and which actions continued for a period of thirty (30) days after a written notice of demand for performance has been delivered to the Eligible Individual specifying the manner in which the Eligible Individual has failed to perform, (iii) has engaged in conduct which is materially injurious to the Company (including, without limitation, misuse or misappropriation of the Company’s funds or other property), or (iv) has committed an act of fraud. No termination of the Eligible Individual’s employment shall be for Cause as set forth in clauses (iii)

or (iv) above until (A) there shall have been delivered to the Eligible Individual a copy of a written notice setting forth that the Eligible Individual was guilty of the conduct set forth in clauses (iii) or (iv), as applicable, and specifying the particulars thereof in detail, and (B) the Eligible Individual shall have been provided an opportunity to be heard by the Board (with the assistance of the Eligible Individual’s counsel if the Eligible Individual so desires). No act, nor failure to act, on the Eligible Individual’s part shall be considered “willful” unless he has acted, or failed to act, with an absence of good faith and without reasonable belief that his action or failure to act was in the best interest of the Company and its affiliates. Notwithstanding anything contained in this Plan to the contrary, no failure to perform by the Eligible Individual after Notice of Termination is given by the Eligible Individual shall constitute Cause.

(f) “ CEO ” means the Chief Executive Officer of the Company.

(g) “ Change in Control ” shall have the meaning given such term in the Company’s 2016 Long Term Incentive Plan.

(h) “ COBRA ” means the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended.

(i) “ Code ” means the Internal Revenue Code of 1986, as amended, and applicable administrative guidance issued thereunder.

(j) “ Committee ” shall have the meaning given such term in the Company’s 2016 Long Term Incentive Plan.

(k) “ Date of Termination ” means the date of receipt of the Notice of Termination or any later date specified therein, as the case may be; provided, however, that if an Eligible Individual’s employment is terminated by reason of death, the Date of Termination shall be the date of death of the Eligible Individual. For all purposes of the Plan, an Eligible Individual’s Date of Termination shall not occur prior to the date the Eligible Individual incurs a “separation from service” within the meaning of Section 409A of the Code.

(l) “ Disability ” means an Eligible Individual’s inability to perform the essential functions of his or her position with or without reasonable accommodation, if required by law, due to physical or mental impairment. The existence of any such Disability shall be certified, at the Company’s discretion, by either the Company’s disability carrier or a physician acceptable to both the Eligible Individual and the Company. If the parties are not able to agree on the choice of physician, each party shall select a physician who, in turn, shall select a third physician to render such certification. In no event will an Eligible Individual’s employment be terminated as a result of Disability, unless otherwise agreed to by the Eligible Individual and the Company, until at least 180 consecutive days of leave has elapsed and the Company has provided the Eligible Individual with written notice of termination.

(m) “ Good Reason ” means, without the express written consent of the Eligible Individual, the occurrence of one of the following arising on or after the date such Eligible Individual commences participation in this Plan, as determined in a manner consistent with Treasury Regulation § 1.409A-1(n)(2)(ii): (i) a material reduction in the Eligible Individual’s base compensation, (ii) a material diminution in the Eligible Individual’s authority, duties or

responsibilities, (iii) a permanent relocation in the geographic location at which the Eligible Individual must perform services to a location more than 50 miles from the location at which the Eligible Individual normally performed services immediately before the relocation, (iv) a material reduction in the authority, duties, or responsibilities of the person to whom the Eligible Individual reports, or (v) any other action or inaction that constitutes a material breach by the Company of its obligations under this Plan. In the case of an Eligible Individual’s allegation of Good Reason, (A) the Eligible Individual shall provide notice to the Company of the event alleged to constitute Good Reason within 60 days after the initial occurrence of such event, and (B) the Company shall have the opportunity to remedy the alleged Good Reason event within 30 days from receipt of notice of such allegation. If not remedied within that 30-day period, the Eligible Individual may submit a Notice of Termination, provided that the Notice of Termination must be given no later than 100 days after the expiration of such 30 day period; otherwise, the Eligible Individual will be deemed to have accepted such event, or the Company’s remedy of such event, that may have given rise to the existence of Good Reason; provided, however, such acceptance shall be limited to the occurrence of such event and shall not waive the Eligible Individual’s right to claim Good Reason with respect to future similar events.

(n) “ Notice of Termination ” means a written notice communicated by the Company or the Eligible Individual, as applicable, that (i) indicates the specific reason for termination of the Eligible Individual’s employment, (ii) sets forth in reasonable detail the facts and circumstances claimed to provide a basis for the termination, and (iii) specifies the Date of Termination.

(o) “ Performance Bonus ” means the annual performance bonus payment an Eligible Individual is eligible to receive for a given calendar year pursuant to the Company’s annual cash performance bonus program or such other similar incentive plan in effect from time to time for its senior executives.

(p) “ Pro-Rata Bonus ” means an amount equal to the Performance Bonus that an Eligible Individual would have actually been entitled to receive for the calendar year in which the Date of Termination occurs, multiplied by a fraction, the numerator of which is the number of days during which the Eligible Individual was employed by the Company in the calendar year of termination, and the denominator of which is 365.

(q) “ Release Conditions ” means an Eligible Individual’s (or his estate’s) execution and delivery to the Company on or prior to the 50 ^th day following the Date of Termination of a release of claims agreement in the Company’s customary form, which shall exclude (and not release) claims for indemnification, claims for coverage under applicable officer and director policies and claims as a director or indirect stockholder of the Company and which may be amended by the Company to reflect changes in applicable laws and regulations and, where applicable, the Eligible Individual’s (or his estate’s) non-revocation of such release.

3. Administration of the Plan .

(a) Authority of the Administrator . The Plan will be administered by the Committee, or by a person or committee appointed by the Committee to administer the Plan (the “ Administrator ”). Subject to the express provisions of the Plan and applicable law, the

Administrator will have the authority, in its sole and absolute discretion, to: (i) adopt, amend, and rescind administrative and interpretive rules and regulations related to the Plan, (ii) delegate its duties under the Plan to such agents as it may appoint from time to time, and (iii) make all other determinations, perform all other acts and exercise all other powers and authority necessary or advisable for administering the Plan, including the delegation of those ministerial acts and responsibilities as the Administrator deems appropriate. The Administrator shall have complete discretion and authority with respect to the Plan and its application except to the extent that discretion is expressly limited by the Plan. The Administrator may correct any defect, supply any omission, or reconcile any inconsistency in the Plan in any manner and to the extent it deems necessary or desirable to carry the Plan into effect, and the Administrator will be the sole and final judge of that necessity or desirability.

(b) Manner of Exercise of Authority . Any action of, or determination by, the Administrator will be final, conclusive and binding on all persons, including the Company, its owners, each Eligible Individual, or other persons claiming rights from or through an Eligible Individual. The express grant of any specific power to the Administrator, and the taking of any action by the Administrator, will not be construed as limiting any power or authority of the Administrator. The Administrator may delegate to officers or managers of the Company, or committees thereof, the authority, subject to such terms as the Administrator will determine, to perform such functions, including administrative functions, as the Administrator may determine. The Administrator may appoint agents to assist it in administering the Plan.

(c) Limitation of Liability . The Administrator will be entitled to, in good faith, rely or act upon any report or other information furnished to the Administrator by any officer or employee of the Company, the Company’s legal counsel, independent auditors, consultants or any other agents assisting in the administration of the Plan. The Administrator and any officer or employee of the Company acting at the direction or on behalf of the Administrator will not be personally liable for any action or determination taken or made in good faith with respect to the Plan and will, to the fullest extent permitted by law, be indemnified and held harmless by the Company with respect to any such action or determination.

4. Eligibility . The employees of the Company listed on Exhibit A attached hereto, as the same may be updated from time to time by the Administrator, are eligible (“ Eligible Individuals ”) to receive the benefits described in this Plan. Each Eligible Individual will be further designated on Exhibit A attached hereto as a Level One Participant, Level Two Participant or Level Three Participant for purposes of this Plan.

5. Plan Benefits .

(a) Termination Due to Death or Disability . In the event an Eligible Individual’s employment terminates by reason of his death or Disability, the Eligible Individual (or his estate) will, contingent upon the Eligible Individual (or his estate) satisfying the Release Conditions, be entitled to receive each of the following:

(i) the Accrued Payments.

(ii) a Pro-Rata Bonus for the calendar year in which the Date of Termination occurs, payable as soon as administratively feasible following preparation of the Company’s unaudited financial statements for the applicable calendar year, but in no event later than March 15 of the calendar year following the calendar year to which such Performance Bonus relates.

(iii) an amount equivalent to twelve (12) months of the Eligible Individual’s Base Salary, payable in a lump sum within 60 days of the Date of Termination.

(iv) group health care coverage continuation for a period of eighteen (18) months following the Eligible Individual’s Date of Termination in accordance with Section 5(e).

(b) Termination Without Cause or For Good Reason . In the event an Eligible Individual’s employment is terminated by the Company without Cause or by the Eligible Individual for Good Reason, the Eligible Individual will, contingent upon the Eligible Individual (or his estate) satisfying the Release Conditions, be entitled to receive each of the following:

(i) the Accrued Payments.

(iii) a lump sum payment equal to:

A. in the case of a Level One Participant, two (2) times the sum of (1) an amount equivalent to twelve (12) months of Base Salary and (2) the Eligible Individual’s Applicable Performance Bonus, payable no later than 60 days after the Date of Termination;

B. in the case of a Level Two Participant, one and one-half (1.5) times the sum of (1) an amount equivalent to twelve (12) months of Base Salary and (2) the Eligible Individual’s Applicable Performance Bonus, payable no later than 60 days after the Date of Termination; or

C. in the case of a Level Three Participant, one (1.0) times the sum of (1) an amount equivalent to twelve (12) months of Base Salary and (2) the Eligible Individual’s Applicable Performance Bonus, payable no later than 60 days after the Date of Termination.

(iv) group health care coverage continuation for a period of (A) in the case of a Level One Participant, twenty-four (24) months, (B) in the case of a Level Two Participant, eighteen (18) months, or (C) in the case of a Level Three Participant, twelve (12) months, following the Eligible Individual’s Date of Termination in accordance with Section 5(e).

(v) immediate vesting in full of all unvested equity-based awards held by the Eligible Individual as of the Date of Termination, except in the case of awards that remain subject to objective performance-based determinations, in which case such awards will remain outstanding and will immediately vest upon and to the extent of the determination that such performance criteria have been satisfied (unless otherwise provided in the applicable award agreements governing such performance awards).

(c) Change in Control . Upon the occurrence of a Change in Control, all unvested equity-based awards held by an Eligible Individual as of the date of the Change in Control shall immediately vest in full, regardless of any other established vesting schedule, such that all remaining unvested equity awards shall be fully vested on the date of such Change in Control. In the case of awards subject to objective performance-based determinations, all performance objectives shall be calculated based on, as determined by the Administrator in its sole discretion, actual performance against the stated performance objectives as of the date of the Change in Control (unless otherwise provided in the applicable award agreements governing such performance awards).

(d) Termination Without Cause or For Good Reason Following a Change in Control . In the event an Eligible Individual is terminated by the Company for any reason other than for Cause or an Eligible Individual terminates employment for Good Reason, in each case within two years following a Change in Control, then the Eligible Individual will, contingent upon the Eligible Individual (or his estate) satisfying the Release Conditions, be entitled to receive each of the following:

(i) the Accrued Payments.

(iii) a lump sum payment equal to:

A. with respect to a Level One Participant, a lump sum payment within 60 days following the Date of Termination equal to three (3) times the sum of (1) an amount equivalent to twelve (12) months of Base Salary and (2) the Eligible Individual’s Applicable Performance Bonus;

B. with respect to a Level Two Participant, a lump sum payment within 60 days following the Date of Termination equal to two and one-half (2.5) times the sum of (1) an amount equivalent to twelve (12) months of Base Salary and (2) the Eligible Individual’s Applicable Performance Bonus; or

C. with respect to a Level Three Participant, a lump sum payment within 60 days following the Date of Termination equal to two (2) times the sum of (1) an amount equivalent to twelve (12) months of Base Salary and (2) the Eligible Individual’s Applicable Performance Bonus.

(iv) group health care coverage continuation for a period of (A) in the case of a Level One Participant, thirty-six (36) months, (B) in the case of a Level Two Participant, thirty (30) months, or (C) in the case of a Level Three Participant, twenty-four (24) months, following the Eligible Individual’s Date of Termination in accordance with Section 5(e).

(e) COBRA . If the Eligible Individual timely and properly elects continuation coverage under the Company’s group health plans pursuant to COBRA, then:

(i) the Company shall reimburse the Eligible Individual for the monthly amount required for the Eligible Individual to effect and continue such coverage for himself and his spouse and eligible dependents, if any, under the Company’s group health plans (the “ Monthly Payment Amount ”). Each such monthly reimbursement payment (the “ Monthly Reimbursement Payment ”) shall be paid to the Eligible Individual on the Company’s first regularly scheduled pay date in the month immediately following the month in which the Eligible Individual timely remits the Monthly Premium Payment. The Eligible Individual shall be eligible to receive Monthly Reimbursement Payments until this Section 5(d)(i) the earlier of: (A) the date the Eligible Individual is no longer eligible to receive COBRA continuation coverage and (B) the date on which the Eligible Individual becomes eligible to receive coverage under a group health plan sponsored by another employer (and any such eligibility shall be promptly reported to the Company by the Eligible Individual); provided, however, that the Eligible Individual acknowledges and agrees that (1) the election of COBRA continuation coverage and the payment of any premiums due with respect to such COBRA continuation coverage will remain the Eligible Individual’s sole responsibility, and the Company will assume no obligation for payment of any such premiums relating to such COBRA continuation coverage, (2) in no event shall the Company be required to pay a Monthly Reimbursement Payment if such payment could reasonably be expected to subject the Company to sanctions imposed pursuant to section 2716 of the Public Health Service Act, the Patient Protection and Affordable Care Act of 2010 and the respective regulations and guidance promulgated thereunder (collectively, “ PPACA ”); and

(ii) On and after the date the Eligible Individual is no longer eligible to receive COBRA continuation coverage (the “ COBRA End Date ”), if the Eligible Individual entitled to receive additional months of group health care coverage continuation under Section 5(b) or 5(d), as applicable, and has not become eligible to receive coverage under a group health plan sponsored by another employer during the period beginning on the Date of Termination and ending on the COBRA End Date, then the Company shall pay to the Eligible Individual a lump sum cash payment on the Company’s first regularly scheduled pay date following the COBRA End Date equal to the product of (A) the Monthly Reimbursement Payment and (B) the number of additional months set forth in Section 5(b) or 5(d), as applicable, for which the Eligible Individual is entitled to receive group health care coverage continuation.

6. Certain Excise Taxes . Notwithstanding anything to the contrary in this Plan, if an Eligible Individual is a “disqualified individual” (as defined in Section 280G(c) of the Code), and the payments and benefits provided for in this Plan, together with any other payments and benefits which such Eligible Individual has the right to receive from the Company or any of its affiliates, would, either separately or in the aggregate, constitute a “parachute payment” (as defined in Section 280G(b)(2) of the Code), then the payments and benefits provided for in this Plan shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by such Eligible Individual from the Company and its affiliates will be one dollar ($1.00) less than three times such Eligible Individual’s “base amount” (as defined in Section 280G(b)(3) of the Code) and so that no portion of such amounts and benefits received by such Eligible Individual shall be subject to the excise tax imposed by Section 4999 of the Code or (b) paid in full, whichever produces the better net after-tax position to such Eligible Individual (taking into account any applicable excise tax under Section 4999 of the Code and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing, first, payments or benefits to be paid in cash hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time) and, then, reducing any benefit to be provided in-kind hereunder in a similar order. The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by the Company in good faith. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a “parachute payment” exists, exceeds one dollar ($1.00) less than three times such Eligible Individual’s base amount, then such Eligible Individual shall be required to immediately repay such excess to the Company upon notification that an overpayment has been made. Nothing in this Section 6 shall require the Company to be responsible for, or have any liability or obligation with respect to, such Eligible Individuals’ excise tax liabilities under Section 4999 of the Code.

7. Claims for Benefits .

(a) Initial Claim. In the event that an Eligible Individual or his estate claims (a “ claimant ”) to be eligible for a payment under the Plan, or claims any other rights under the Plan, such claimant must complete and submit such claim forms and supporting documentation as will be required by the Administrator, in its sole and absolute discretion. In connection with the determination of a claim, or in connection with the review of a denied claim, the claimant may examine the Plan and any other pertinent documents generally available to Eligible Individuals that are specifically related to the claim. A written notice of the disposition of any such claim will be furnished to the claimant within ninety (90) days after the claim is filed with the Administrator. Such notice will refer, if appropriate, to pertinent provisions of the Plan, will set forth in writing the reasons for denial of the claim, if a claim is denied (including references to any pertinent provisions of the Plan), and, where appropriate, will describe any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary. If the claim is denied, in whole or in part, the claimant will also be notified of the Plan’s claim review procedure and the time limits applicable to such procedure.

(b) Request for Review . Within ninety (90) days after receiving written notice of the Administrator’s disposition of the claim, the claimant may file with the Administrator a written request for review of his claim. In connection with the request for review, the claimant will be entitled to be represented by counsel and will be given, upon request and free of charge, reasonable access to all pertinent documents for the preparation of his claim. If the claimant does not file a written request for review within ninety (90) days after receiving written notice of the Administrator’s disposition of the claim, the claimant will be deemed to have accepted the Administrator’s written disposition, unless the claimant was physically or mentally incapacitated so as to be unable to request review within the ninety (90) day period.

(c) Decision on Review . After receipt by the Administrator of a written application for review of an initial claim determination, the Administrator will review the claim taking into account all comments, documents, records and other information submitted by the claimant regarding the claim without regard to whether such information was considered in the initial benefit determination. The Administrator will notify the claimant of its decision by delivery via certified or registered mail to the claimant’s last known address. A decision on review of the claim will be made by the Administrator within forty-five (45) days of receipt of the written request for review. If special circumstances require an extension of the forty-five (45) day period, the Administrator will so notify the claimant and a decision will be rendered within ninety (90) days of receipt of the request for review. In any event, if a claim is not determined by the Administrator within ninety (90) days of receipt of written submission for review, it will be deemed to be denied. The decision of the Administrator will be provided to the claimant as soon as possible but no later than five (5) days after the benefit determination is made. The decision will be in writing and will include the specific reasons for the decision presented in a manner calculated to be understood by the claimant and will contain references to all relevant Plan provisions on which the decision was based. Such decision will also advise the claimant that he may receive upon request, and free of charge, reasonable access to and copies of all documents, records and other information relevant to his claim and will inform the claimant of his right to file a civil action under section 502(a) of the Employee Retirement Income Security Act of 1974, as amended (“ ERISA ”), in the case of an adverse decision regarding his appeal. The decision of the Administrator will be final and conclusive.

8. General Provisions.

(a) Taxes . The Company is authorized to withhold from any payments made hereunder amounts of withholding and other taxes due or potentially payable in connection therewith, and to take such other action as the Company may deem advisable to enable the Company and Eligible Individuals to satisfy obligations for the payment of withholding taxes and other tax obligations relating to any payments made under this Plan.

(b) Offset . The Company may set off against, and each Eligible Individual authorizes the Company to deduct from, any payments due to the Eligible Individual, or to his estate, heirs, legal representatives, or successors, any amounts which may be due and owing to the Company or an affiliate by the Eligible Individual, whether arising under this Plan or otherwise; provided that no such offset may be made with respect to amounts payable that are subject to the requirements of Section 409A of the Code unless the offset would not result in a violation of the requirements of Section 409A of the Code.

(c) Term of the Plan ; Amendment and Termination. Prior to a Change in Control, the Plan may be amended or modified in any respect, and may be terminated, in any such case, by resolution adopted by two-thirds (2/3) of the Board; provided, however, that no such amendment, modification or termination that is adopted within one (1) year prior to a Change in Control that would adversely affect the benefits or protections hereunder of any individual who is an Eligible Individual as of the date such amendment, modification or termination is adopted shall be effective as it relates to such individual, except for any amendment or modification to which such Eligible Individual consents in writing; provided, further, however, that the Plan may not be amended, modified or terminated, (i) at the request of a third party who has indicated an intention or taken steps to effect a Change in Control and who effectuates a Change in Control, or (ii) otherwise in connection with, or in anticipation of, a Change in Control that actually occurs, and any such attempted amendment, modification or termination shall be null and void ab initio. Any action taken to amend, modify or terminate the Plan which is taken subsequent to the execution of an agreement providing for a transaction or transactions which, if consummated, would constitute a Change in Control shall conclusively be presumed to have been taken in connection with a Change in Control. For a period of two (2) years following the occurrence of a Change in Control, the Plan may not be amended or modified in any manner that would in any way adversely affect the benefits or protections provided hereunder to any individual who is an Eligible Individual under the Plan on the date the Change in Control occurs.

(d) Successors . The Plan shall bind and inure to the benefit of and be enforceable by the parties hereto and their respective successors, permitted assigns, heirs and personal representatives and estates, as the case may be. The Company shall require any successor pursuant to a Change in Control to expressly assume and agree to perform this Plan in the same manner and to the same extent that the Company would be required to perform if no succession had taken place. Neither the Plan nor any right or obligation hereunder of any party may be assigned or delegated without the prior written consent of the other party hereto;

provided, however, that the Company may assign this Plan to any of its affiliates and an Eligible Individual may direct payment of any benefits that will accrue upon death. An Eligible Individual shall not have any right to pledge, hypothecate, anticipate, or in any way create a lien upon any payments or other benefits provided under the Plan; and no benefits payable under the Plan shall be assignable in anticipation of payment either by voluntary or involuntary acts, or by operation of law, except by will or pursuant to the laws of descent and distribution. The Plan shall not confer any rights or remedies upon any person or legal entity other than the parties hereto and their respective successors and permitted assigns.

(e) Unfunded Obligation . All benefits due an Eligible Individual under this Plan are unfunded and unsecured and are payable out of the general funds of the Company.

(f) Limitation on Rights Conferred Under Plan . Neither the Plan nor any action taken hereunder will be construed as (i) giving an Eligible Individual the right to continue in the employ or service of the Company or an affiliate; (ii) interfering in any way with the right of the Company or any affiliate to terminate an Eligible Individual’s employment or service at any time; or (iii) giving an Eligible Individual any claim to be treated uniformly with other employees.

(g) Nonexclusivity of the Plan . The adoption of the Plan by the Company will not be construed as creating any limitations on the power of the Company to adopt such other incentive arrangements as it may deem desirable. Except as otherwise expressly provided herein, nothing contained in the Plan will be construed to prevent the Company from taking any action which is deemed by the Company to be appropriate or in its best interest, whether or not such action would have an adverse effect on the Plan or any payments made under the Plan. No employee, beneficiary or other person will have any claim against the Company as a result of any such action. Any action with respect to the Plan taken by the Administrator, the Company, or any designee of the foregoing shall be conclusive upon all Eligible Individuals and beneficiaries entitled to benefits under the Plan.

(h) Severability . If any provision of the Plan is held to be illegal or invalid for any reason, the illegality or invalidity will not affect the remaining provisions of the Plan, but such provision will be fully severable and the Plan will be construed and enforced as if the illegal or invalid provision had never been included herein.

(i) Application of Section 409A . The amounts payable pursuant to Section 5 of this Plan are intended, to the greatest extent possible, to comply with the short-term deferral exception and/or separation pay exception to Section 409A of the Code. To the extent that an Eligible Individual is a “specified employee” within the meaning of the Treasury Regulations issued pursuant to Section 409A of the Code (the “ Section 409A Regulations ”) as of the Eligible Individual’s Date of Termination, no amount that constitutes a deferral of compensation which is payable on account of the Eligible Individual’s separation from service shall be paid to the Eligible Individual before the date (the “ Delayed Payment Date ”) which is first day of the seventh month after the Eligible Individual’s Date of Termination or, if earlier, the date of the Eligible Individual’s death following such Date of Termination. All such amounts that would, but for this Section 9(i), become payable prior to the Delayed Payment Date will be accumulated and paid on the Delayed Payment Date. No interest will be paid by the Company with respect to

any such delayed payments. For purposes of Section 409A of the Code, each payment or amount due under this Plan shall be considered a separate payment, and an Eligible Individual’s entitlement to a series of payments under this Plan is to be treated as an entitlement to a series of separate payments. It is intended that this Plan, to the extent practicable, comply and be interpreted in accordance with Section 409A of the Code, and the Company shall, as necessary, adopt such confirming amendments as are necessary to comply with Section 409A of the Code without reducing the benefits payable hereunder to any Eligible Individual without his or her express written consent. The Company does not make any representations with respect to the application of Section 409A of the Code to any tax, economic or legal consequences of any payments payable under this Plan, and an Eligible Individual retains full responsibility for the potential application of Section 409A of the Code to the tax and legal consequences of payments payable to the Eligible Individual hereunder. The Company shall not indemnify or otherwise compensate an Eligible Individual for any violation of Section 409A of the Code that may occur in connection with this Plan.

(j) Governing Law . All questions arising with respect to the provisions of the Plan and payments due hereunder will be determined by application of the laws of the State of Texas, without giving effect to any conflict of law provisions thereof, except to the extent Texas law is preempted by federal law.

(k) Word Usage . Words used in the masculine shall apply to the feminine, where applicable, and wherever the context of the Plan dictates, the plural shall be read as the singular and the singular as the plural.

(l) Status/Named Fiduciary . The Plan is intended to qualify for the exemptions under Title I of ERISA provided for plans that are unfunded and maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees. The Administrator shall be the named fiduciary for purposes of the Plan.

(m) ERISA Rights . As a participant in the Plan, Eligible Individuals are entitled to certain rights and protections under ERISA, which provides that all Plan participants shall be entitled to:

(i) Examine without charge, at the Administrator’s office and at other specified locations such as worksites, all Plan documents, and copies of all documents filed by the Plan with the U.S. Department of Labor, such as detailed annual reports.

(ii) Obtain copies of all Plan documents and other Plan information upon written request to the Administrator. The Administrator may make a reasonable charge for the copies.

(iii) To the extent applicable, receive a summary of the Plan’s annual financial report. The Administrator is required by law to furnish each participant with a copy of this summary annual report.

In addition to creating rights for Plan participants, ERISA imposes obligations upon the people who are responsible for the operation of employee benefit plans. The people who operate the

Plan, called “fiduciaries” of the Plan, have a duty to do so prudently and in the interest of Eligible Individuals and beneficiaries. No one, including the Company, may fire an Eligible Individual or otherwise discriminate against the Eligible Individual in any way to prevent the Eligible Individual from obtaining benefits or exercising his or her rights under ERISA.

If a claim for a benefit under this Plan is denied in whole or in part, an Eligible Individual has the right to know why this was done, to obtain copies of documents relating to the decision without charge, and to appeal any denial, all within certain time schedules.

Under ERISA, there are steps an Eligible Individual can take to enforce the above rights. For instance, if an Eligible Individual requests materials from the Administrator and does not receive them within 30 days, the Eligible Individual may file suit in a federal court. In such a case, the court may require the Administrator to provide the materials and pay the Eligible Individual up to $110 a day until the Eligible Individual receives the materials, unless the materials were not sent because of reasons beyond the control of the Administrator. If an Eligible Individual’s claim for benefits is denied or ignored, in whole or in part, the Eligible Individual may file suit in a state or federal court. If an Eligible Individual is discriminated against for asserting his or her rights, the Eligible Individual may seek assistance from the U.S. Department of Labor, or file suit in a federal court. The court will decide who should pay court costs and legal fees. If the Eligible Individual is successful, the court may order the person sued by the Eligible Individual to pay the costs and fees. If the Eligible Individual loses, the court may order the Eligible Individual to pay the costs and fees (for example, if it finds that the Eligible Individual’s claim is frivolous).

If an Eligible Individual has any questions about this Plan, the Eligible Individual should contact the Administrator. If an Eligible Individual has any questions about this statement or about his or her rights under ERISA, or if an Eligible Individual needs assistance in obtaining documents from the Administrator, he or she should contact the nearest office of the Employee Benefits Security Administration, U.S. Department of Labor, listed in the telephone directory or the Division of Technical Assistance and Inquiries, Employee Benefits Security Administration, U.S. Department of Labor, 200 Constitution Avenue N.W., Washington D.C. 20210. An Eligible Individual may also obtain certain publications about his or her rights and responsibilities under ERISA by calling the publications hotline of the Employee Benefits Security Administration.

(n) Additional Information.


Plan Name:		WildHorse Resource Development Corporation Executive Change in Control and Severance Benefit Plan

Fiscal Year of Plan:		January 1 through December 31

Type of Plan:		Top Hat Pension Plan

Plan No.:		510

Plan Sponsor:		WildHorse Resource Development Corporation


		9805 Katy Freeway
		Suite 400
		Houston, TX 77024
		Phone: (713) 568-4910
		Employer I.D. Number: 81-3470246

Plan Administrator:		WildHorse Resource Development Corporation
		9805 Katy Freeway
		Suite 400
		Houston, TX 77024
		Phone: (713) 568-4910

Agent for Service		General Counsel of the Company,
of Legal Process:		Process shall be served at the address specified above.

[Signature Page Follows]

EXECUTED this day of , 2016.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION



By:
Name:
Title:

Signature Page

Exhibit 10.6

FORM OF

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

2016 LONG TERM INCENTIVE PLAN

RESTRICTED STOCK AWARD AGREEMENT

This Agreement (“ Agreement ”) is made and entered into as of (the “ Date of Grant ”) by and between WildHorse Resource Development Corporation, a Delaware corporation (the “ Company ”), and (the “ Grantee ” or “ you ”);

WHEREAS , the Company adopted the WildHorse Resource Development Corporation 2016 Long Term Incentive Plan (as amended from time to time, the “ Plan ”), under which the Company is authorized to grant equity-based awards to certain employees and service providers of the Company;

WHEREAS , the Company, in order to induce you to enter into and to continue and dedicate service to the Company and to materially contribute to the success of the Company, agrees to grant you this award of Restricted Stock;

WHEREAS , you acknowledge that a copy of the Plan has been furnished to you and shall be deemed a part of this Agreement as if fully set forth herein and the terms capitalized but not defined herein shall have the meanings set forth in the Plan; and

WHEREAS , you desire to accept the award of Restricted Stock made pursuant to this Agreement.

NOW, THEREFORE, in consideration of the mutual covenants set forth herein and for other valuable consideration hereinafter set forth, the parties agree as follows:

1. The Grant . Subject to the conditions set forth below, the Company hereby grants you, effective as of the Date of Grant, as a matter of separate inducement and not in lieu of any salary or other compensation for your services for the Company, an award of Restricted Stock (the “ Award ”) consisting of shares of Stock (the “ Restricted Shares ”) in accordance with the terms and conditions set forth herein and in the Plan.

2. Escrow of Restricted Shares . The Company shall evidence the Restricted Shares in the manner that it deems appropriate. The Company may issue in your name a certificate or certificates representing the Restricted Shares and retain such certificate(s) until the restrictions on such Restricted Shares expire as described in Section 5 or 6 of this Agreement or the Restricted Shares are forfeited as described in Section 4 and 6 of this Agreement. If the Company certificates the Restricted Shares, you shall execute one or more stock powers in blank for those certificates and deliver those stock powers to the Company. The Company shall hold the Restricted Shares and the related stock powers pursuant to the terms of this Agreement, if applicable, until such time as (a) a certificate or certificates for the Restricted Shares are delivered to you, (b) the Restricted Shares are otherwise transferred to you free of restrictions, or (c) the Restricted Shares are canceled and forfeited pursuant to this Agreement.

3. Ownership of Restricted Shares . From and after the time the Restricted Shares are issued in your name, you will be entitled to all the rights of absolute ownership of the Restricted Shares, including the right to vote such shares and to receive dividends thereon if, as, and when declared by the Board, subject, however, to the terms, conditions and restrictions set forth in this Agreement; provided , however , that each dividend payment will be made no later than the 60th day following the date such dividend payment is made to stockholders generally.

4. Restrictions; Forfeiture . The Restricted Shares are restricted in that they may not be sold, transferred or otherwise alienated or hypothecated until these restrictions are removed or expire as described in Section 5 or 6 of this Agreement. The Restricted Shares are also restricted in the sense that they may be forfeited to the Company (the “ Forfeiture Restrictions ”). You hereby agree that if the Restricted Shares are forfeited, as provided in Section 6 , the Company shall have the right to deliver the Restricted Shares to the Company’s transfer agent for, at the Company’s election, cancellation or transfer to the Company.

5. Expiration of Restrictions and Risk of Forfeiture . The restrictions on the Restricted Shares described in Section 4 of this Agreement will expire and the Restricted Shares will become transferable and nonforfeitable, provided that, subject to Section 6(b) , you remain in the employ of, or a service provider to, the Company or its Affiliates until the applicable dates set forth in the following schedule:


Number of Restricted Shares that Vest		Vesting Date

6. Termination of Services and Change in Control .

(a) Termination Generally . If your service relationship with the Company or its Affiliates is terminated for any reason, then those Restricted Shares for which the restrictions have not lapsed as of the date of termination shall become null and void and those Restricted Shares shall be forfeited to the Company. The Restricted Shares for which the restrictions have lapsed as of the date of such termination shall not be forfeited to the Company.

(b) Change in Control . Notwithstanding the vesting schedule set forth in Section 5 above, upon the occurrence of a Change in Control, 100% of the Restricted Shares for which the restrictions have not yet lapsed as of the date of the Change in Control shall become immediately vested.

(c) Effect of Other Agreements . Notwithstanding any provision herein to the contrary, in the event of any inconsistency between this Section 6 and any employment, severance or change in control agreement between you and the Company or a similar plan or arrangement sponsored or maintained by the Company in which you participate, the terms of such employment, severance or change in control agreement or similar plan or arrangement shall control.

7. Leave of Absence . With respect to the Award, the Company may, in its sole discretion, determine that if you are on leave of absence for any reason you will be considered to still be in the employ of, or providing services for, the Company, provided that rights to the Restricted Shares during a leave of absence will be limited to the extent to which those rights were earned or vested when the leave of absence began.

8. Delivery of Stock . Promptly following the expiration of the restrictions on the Restricted Shares pursuant to Section 5 or 6(b) of this Agreement, the Company shall cause to be issued and delivered to you or your designee a certificate or other evidence of the number of Restricted Shares as to which restrictions have lapsed (i.e., shares of Stock), free of any restrictive legend relating to the lapsed restrictions, upon receipt by the Company of any tax withholding as may be due pursuant to Section 9 . The value of such Stock shall not bear any interest owing to the passage of time.

9. Payment of Taxes . The Company shall require you to pay to the Company (or one of the Company’s Affiliates if you are an employee of an Affiliate of the Company), an amount the Company deems necessary to satisfy its (or one of its Affiliate’s) current or future obligation to withhold federal, state or local income or other taxes that you incur as a result of the Award. With respect to any required tax withholding, you may (a) direct the Company to withhold from the shares of Stock to be issued to you under this Agreement the number of shares necessary to satisfy the Company’s obligation to withhold taxes; which determination will be based on the shares’ Fair Market Value at the time such determination is made; (b) deliver to the Company shares of Stock sufficient to satisfy the Company’s tax withholding obligations, based on the shares’ Fair Market Value at the time such determination is made; (c) deliver cash to the Company sufficient to satisfy its tax withholding obligations; or (d) satisfy such tax withholding through any combination of (a), (b) and (c). If you desire to elect to use the stock withholding option described in subparagraph (a), you must make the election at the time and in the manner the Company prescribes. The Company, in its discretion, may deny your request to satisfy its tax withholding obligations using a method described under subparagraph (a) or (b).

10. Compliance with Securities Law . Notwithstanding any provision of this Agreement to the contrary, the issuance of Stock (including Restricted Shares) will be subject to compliance with all applicable requirements of federal, state, or foreign law with respect to such securities and with the requirements of any stock exchange or market system upon which the Stock may then be listed. No Stock will be issued hereunder if such issuance would constitute a violation of any applicable federal, state, or foreign securities laws or other law or regulations or the requirements of any stock exchange or market system upon which the Stock may then be listed. In addition, Stock will not be issued hereunder unless (a) a registration statement under the Securities Act of 1933, as amended (the “ Act ”), is at the time of issuance in effect with respect to the shares issued or (b) in the opinion of legal counsel to the Company, the shares issued may be issued in accordance with the terms of an applicable exemption from the registration requirements of the Act. The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any shares subject to the Award will relieve the Company of any liability in respect of the failure to issue such shares as to which such requisite authority has not been obtained. As a condition to any issuance hereunder, the Company may require you to satisfy any qualifications that may be necessary or appropriate to evidence

compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as may be requested by the Company. From time to time, the Board and appropriate officers of the Company are authorized to take the actions necessary and appropriate to file required documents with governmental authorities, stock exchanges, and other appropriate Persons to make shares of Stock available for issuance.

11. Legends . The Company may at any time place legends referencing any restrictions imposed on the shares pursuant to Sections 4 or 10 of this Agreement on all certificates representing shares issued with respect to this Award.

12. Right of the Company and Affiliates to Terminate Services . Nothing in this Agreement confers upon you the right to continue in the employ of or performing services for the Company or any of its Affiliates, or interfere in any way with the rights of the Company or any of its Affiliates to terminate your employment or service relationship at any time.

13. Furnish Information . You agree to furnish to the Company all information requested by the Company to enable it to comply with any reporting or other requirements imposed upon the Company by or under any applicable statute or regulation.

14. Remedies . The parties to this Agreement shall be entitled to recover from each other reasonable attorneys’ fees incurred in connection with the successful enforcement of the terms and provisions of this Agreement whether by an action to enforce specific performance or for damages for its breach or otherwise.

15. No Liability for Good Faith Determinations . The Company and the members of the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Restricted Shares granted hereunder.

16. Execution of Receipts and Releases . Any payment of cash or any issuance or transfer of shares of Stock or other property to you, or to your legal representative, heir, legatee or distributee, in accordance with the provisions hereof, shall, to the extent thereof, be in full satisfaction of all claims of such Persons hereunder. The Company may require you or your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a release and receipt therefor in such form as it shall determine.

17. No Guarantee of Interests . The Board and the Company do not guarantee the Stock of the Company from loss or depreciation.

18. Notice . All notices required or permitted under this Agreement must be in writing and personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually received by the person to whom it is properly addressed or if earlier the date it is sent via certified United States mail.

19. Waiver of Notice . Any person entitled to notice hereunder may waive such notice in writing.

20. Information Confidential . As partial consideration for the granting of the Award hereunder, you hereby agree to keep confidential all information and knowledge, except that

which has been disclosed in any public filings required by law, that you have relating to the terms and conditions of this Agreement; provided , however , that such information may be disclosed as required by law and may be given in confidence to your spouse and tax and financial advisors. In the event any breach of this promise comes to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any future similar award to you, as a factor weighing against the advisability of granting any such future award to you.

21. Successors . This Agreement shall be binding upon you, your legal representatives, heirs, legatees and distributees, and upon the Company, its successors and assigns.

22. Severability . If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.

23. Company Action . Any action required of the Company shall be by resolution of the Board or by a person or entity authorized to act by resolution of the Board.

24. Headings . The titles and headings of Sections are included for convenience of reference only and are not to be considered in construction of the provisions hereof.

25. Governing Law . All questions arising with respect to the provisions of this Agreement shall be determined by application of the laws of Delaware without giving any effect to any conflict of law provisions thereof, except to the extent Delaware state law is preempted by federal law. The obligation of the Company to sell and deliver Stock hereunder is subject to applicable laws and to the approval of any governmental authority required in connection with the authorization, issuance, sale, or delivery of such Stock.

26. Amendment . This Agreement may be amended the Board or by the Committee at any time; provided that any amendment that would materially and adversely affect your rights hereunder shall not be effective without your consent.

27. Clawback . To the extent required by applicable law or any applicable securities exchange listing standards, or as otherwise determined by the Board (or a committee thereof), all shares of Stock granted under this Agreement shall be subject to the provisions of any applicable clawback policies or procedures adopted by the Company, which clawback policies or procedures may provide for forfeiture and/or recoupment of such shares of Stock. Notwithstanding any provision of this Agreement to the contrary, the Company reserves the right, without your consent, to adopt any such clawback policies and procedures, including such policies and procedures applicable to this Agreement with retroactive effect.

28. The Plan . This Agreement is subject to all the terms, conditions, limitations and restrictions contained in the Plan.

[Signature Page Follows]

IN WITNESS WHEREOF , the Company has caused this Agreement to be executed by its officer thereunto duly authorized, and the Grantee has set his hand as to the date and year first above written.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

Name:

Title:

[GRANTEE NAME]

GRANTEE

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

WildHorse Resource Development Corporation:

We consent to the use of our report dated August 12, 2016, with respect to the balance sheet of WildHorse Resource Development Corporation as of August 4, 2016, included herein and to the reference to our firm under the heading “Experts” in the prospectus.

(signed) KPMG LLP

Houston, Texas

November 22, 2016

Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

The Board of Managers and Members

WildHorse Resources II, LLC:

We consent to the use of our report dated August 12, 2016, with respect to the consolidated balance sheets of WildHorse Resources II, LLC and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, members’ equity, and cash flows for the years then ended, included herein and to the reference to our firm under the heading “Experts” in the prospectus.

(signed) KPMG LLP

Houston, Texas

November 22, 2016

Exhibit 23.3

Consent of Independent Registered Public Accounting Firm

The Board of Managers

WHE AcqCo., LLC:

We consent to the use of our report dated November 10, 2016, with respect to the statements of revenues and direct operating expenses of certain oil and gas properties of Clayton Williams Energy, Inc. contracted to be acquired by WHE AcqCo., LLC for the nine month period ended September 30, 2016 and the years ended December 31, 2015 and 2014, included herein and to the reference to our firm under the heading “Experts” in the prospectus.

/s/ KPMG LLP

Dallas, Texas

November 22, 2016

Exhibit 23.4

CONSENT OF INDEPENDENT AUDITORS

We consent to the reference to our firm under the caption “Experts” and to the use of our report dated August 10, 2016, with respect to the consolidated financial statements of Esquisto Resources II, LLC and Subsidiary included in the Registration Statement (Form S-1 No. 333-214569) and related Prospectus of WildHorse Resource Development Corporation for the registration of shares of its common stock.

/s/Ernst & Young

Dallas, TX

November 22, 2016

Exhibit 23.5

CONSENT OF INDEPENDENT AUDITORS

We consent to the reference to our firm under the caption “Experts” and to the use of our report dated August 1, 2016, with respect to the statements of revenues and direct operating expenses, which comprise the revenues and direct operating expenses of certain oil and gas properties of the members of Esquisto Resources II, LLC prior to formation of and contribution to Esquisto (the “Pre-Esquisto Properties working interest”) included in the Registration Statement (From S-1 No. 333-214569) and related Prospectus of WildHorse Resource Development Corporation for the registration of shares of its common stock.

/s/Ernst & Young

Dallas, TX

November 22, 2016

Exhibit 23.6

CONSENT OF INDEPENDENT AUDITORS

We consent to the reference to our firm under the caption “Experts” and to the use of our report dated August 1, 2016, with respect to the statements of revenues and direct operating expenses, which comprise the revenues and direct operating expenses of certain oil and gas properties of Comstock Resources, Inc. acquired by Esquisto Resouces II, LLC (the “Comstock Properties working interest”) included in the Registration Statement (Form S-1 No. 333-214569) and related Prospectus of WildHorse Resource Development Corporation for the registration of shares of its common stock.

/s/Ernst & Young

Dallas, TX

November 22, 2016

Exhibit 23.7

C AWLEY , G ILLESPIE & A SSOCIATES , I NC .


PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE, SUITE 100 AUSTIN, TEXAS 78729-1707 512-249-7000	306 WEST SEVENTH STREET, SUITE 302 FORT WORTH, TEXAS 76102-4987 817- 336-2461 www.cgaus.com	1000 LOUISIANA STREET, SUITE 1900 HOUSTON, TEXAS 77002-5008 713-651-9944

CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC.

As independent consultants, Cawley, Gillespie & Associates, Inc. hereby consents to the references to our firm in this Registration Statement on Form S-1 for WildHorse Resource Development Corporation, and to the use of information from, and the inclusion of, our reserve audits (i) dated February 3, 2015, with respect to the estimates of reserves and future net revenues of WildHorse Resources II, LLC, as of December 31, 2014, (ii) dated February 11, 2016, with respect to the estimates of reserves and future net revenues of WildHorse Resources II, LLC as of December 31, 2015, and (iii) dated August 11, 2016, with respect to the estimates of reserves and future net revenues of WildHorse Resources II, LLC as of June 30, 2016, in this Registration Statement. We further consent to the reference to our firm under the heading “Experts” in this Registration Statement and related prospectus.

/s/ CAWLEY, GILLESPIE & ASSOCIATES, INC.

CAWLEY, GILLESPIE & ASSOCIATES, INC.

Fort Worth, Texas

November 23, 2016

Exhibit 23.8

C AWLEY , G ILLESPIE & A SSOCIATES , I NC .


PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE, SUITE 100 AUSTIN, TEXAS 78729-1707 512-249-7000	306 WEST SEVENTH STREET, SUITE 302 FORT WORTH, TEXAS 76102-4987 817-336-2461 www.cgaus.com	1000 LOUISIANA STREET, SUITE 1900 HOUSTON, TEXAS 77002-5008 713-651-9944

CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC.

As independent consultants, Cawley, Gillespie & Associates, Inc. hereby consents to the references to our firm in this Registration Statement on Form S-1 for WildHorse Resource Development Corporation, and to the use of information from, and the inclusion of, our reserve reports (i) dated January 20, 2016, with respect to the estimates of reserves and future net revenues of Esquisto Resources II, LLC, as of December 31, 2014, (ii) dated March 14, 2016, with respect to the estimates of reserves and future net revenues of Esquisto Resources II, LLC as of December 31, 2015, and (iii) dated August 29, 2016, with respect to the estimates of reserves and future net revenues of Esquisto Resources II, LLC as of June 30, 2016, in this Registration Statement. We further consent to the reference to our firm under the heading “Experts” in this Registration Statement and related prospectus.

/s/ CAWLEY, GILLESPIE & ASSOCIATES, INC.

CAWLEY, GILLESPIE & ASSOCIATES, INC.

Fort Worth, Texas

November 23, 2016

Exhibit 99.7

CONSENT OF DIRECTOR NOMINEE

I consent to the use of my name as a Director Nominee in the Registration Statement, including in the section “Management,” filed by WildHorse Resource Development Corporation on Form S-1 and each related prospectus and each further amendment or supplement thereto.



Dated: November 23, 2016				/s/ Jonathan M. Clarkson
				Name: Jonathan M. Clarkson